UNITED STATES  

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended September 30, 2016

OR

For the transition period from                       to                         

Commission file number: 001-35317

 

 

TITAN ENERGY, LLC

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code: (800) 251-0171

 

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

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

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

 

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

The number of outstanding common shares of the registrant on November 20, 2016 was 5,416,667.

 

 

 

 

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TITAN ENERGY, LLC

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

 

 

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Forward-Looking Statements

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

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Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under “Item 1A: Risk Factors” in our predecessor’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015 and in our predecessor’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

 

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TITAN ENERGY. LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

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TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share and unit data)

(Unaudited)

 

See accompanying notes to condensed consolidated financial statements.

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TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)

(Unaudited)

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

 

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TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY / PARTNERS’ CAPITAL (DEFICIT)

(in thousands, except unit data)

(Unaudited)

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

 

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TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

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TITAN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

NOTE 1 – ORGANIZATION

We are an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States. We sponsor and manage tax-advantaged investment partnerships (the “Drilling Partnerships”), in which we coinvest, to finance a portion of our natural gas, crude oil and NGL production activities. As discussed further below, we are the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”). Unless the context otherwise requires, references to “Titan Energy, LLC,” “Titan,” “the Company,” “we,” “us,” and “our,” refer to Titan Energy, LLC and our consolidated subsidiaries (and its predecessor, where applicable).

Titan Energy Management, LLC (“Titan Management”) manages us and holds our Series A Preferred Share, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution as discussed below) and to appoint four of our seven directors.  Titan Management is a wholly owned subsidiary of Atlas Energy Group, LLC (“Atlas Energy Group” or “ATLS”; OTC: ATLS), which is a publicly traded company.

In addition to its preferred member interest in us, ATLS also holds general and limited partner interests in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, oil and NGLs, with operations primarily focused in the Eagle Ford Shale, and in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs.

At September 30, 2016, we had 5,416,667 common shares representing limited liability company interests issued and outstanding.

ARP Restructuring and Emergence from Chapter 11 Proceedings

On July 25, 2016, ARP and certain of its subsidiaries and ATLS, solely with respect to certain sections thereof, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% Senior Notes due 2021 (the “7.75% Senior Notes”) and the 9.25% Senior Notes due 2021 (the “9.25% Senior Notes” and, together with the 7.75% Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties agreed, subject to certain terms and conditions, to support ARP’s restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).

 

On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

 

ARP operated its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired by the Plan and were satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:

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NOTE 2 – BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying condensed consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2015 was derived from ARP’s audited financial statements, have been prepared pursuant to the rules and regulations of the SEC and are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. It is suggested that these interim condensed consolidated financial statements be read in conjunction with the financial statements and the notes thereto included in ARP’s latest Annual Report on Form 10-K though, as described below, such prior financial statements may not be comparable to our interim financial statements due to the adoption of fresh-start accounting. In management’s opinion, all adjustments necessary for a fair presentation of our and ARP’s financial position, results of operations and cash flows for the periods disclosed have been made. Certain amounts in the prior year’s financial statements have been reclassified to conform to the current year presentation due to the adoption of certain accounting standards (see Notes 2 and 5). The results of operations for the interim periods presented may not necessarily be indicative of the results of operations for the full year.

In connection with ARP’s Chapter 11 filings, we were subject to the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852 Reorganizations (“ASC 852”). All expenses, realized gains and losses and provisions for losses directly associated with the bankruptcy proceedings were classified as “reorganization items” in the condensed consolidated statements of operations.

Upon emergence from bankruptcy on the Plan Effective Date, we adopted fresh-start accounting in accordance with ASC 852, which resulted in Titan becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Plan Effective Date, which differed materially from the recorded values of ARP’s assets and liabilities as reflected in ARP’s historical consolidated balance sheets. The effects of the Plan and the application of fresh-start accounting were reflected in our consolidated financial statements as of September 1, 2016 and the related adjustments thereto were recorded in our condensed consolidated statements of operations as reorganization items for the predecessor period January 1 to August 31, 2016.  

As a result, our condensed consolidated balance sheet and condensed consolidated statement of operations subsequent to the Plan Effective Date will not be comparable to ARP’s condensed consolidated balance sheet and condensed consolidated statements of operations prior to the Plan Effective Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on or after September 1, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

References to “Successor” relate to the Company on and subsequent to the Plan Effective Date. References to “Predecessor” refer to the Company prior to the Plan Effective Date. The consolidated financial statements of the Successor have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business.

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Principles of Consolidation

Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, our condensed consolidated financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which we have an interest. Such interests generally approximate 30%. Our condensed consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, we calculate these items specific to our own economics.

Liquidity and Capital Resources

 

Our primary sources of liquidity are cash generated from operations, capital raised through our Drilling Partnerships, and borrowings under our credit facilities.  Our primary cash requirements are operating expenses, debt service including interest, and capital expenditures.

 

We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under our credit facilities and equity and debt offerings. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on our liquidity position. In addition, challenges with our ability to raise capital through our Drilling Partnerships, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, could negatively impact our ability to remain in compliance with the covenants under our credit facilities.

If we are unable to remain in compliance with the covenants under our credit facilities (as described in Note 5), absent relief from our lenders, as applicable, we may be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under our credit facilities, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. If an event of default occurs (including if our borrowing base is redetermined below our current outstanding borrowings and we are unable to repay the deficiency or deposit additional collateral to eliminate such deficiency), or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern.

We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet, meeting our debt service obligations and/or achieving cost efficiency.  For example, we could pursue options such as refinancing, restructuring or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels.  

We also continue to implement various cost saving measures to reduce our capital, operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. We will continue to be opportunistic and aggressive in managing our cost structure and, in turn, our liquidity to meet our capital and operating needs. We cannot provide any assurances that any of these efforts will be successful or will result in cost reductions or cash flows or the timing of any such cost reductions or additional cash flows. It is also possible additional adjustments to our plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets, seeking additional partners to develop our assets, and/or reducing our planned capital program.  In addition, to the extent commodity prices remain low or decline further, or we experience disruptions in our longer-term access to or cost of capital, our ability to fund future capital expenditures or growth projects may be further impacted.

Arkoma Acquisition

On June 5, 2015, ARP acquired coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma from ATLS (the “Arkoma Acquisition”) for $31.5 million, net of purchase price adjustments, which was funded through the issuance of 6,500,000 of our Predecessor’s common limited partner units. We determined that the Arkoma Acquisition constituted a transaction between entities under common control and, accordingly, retroactively adjusted ARP’s prior period condensed consolidated financial statements assuming our Predecessor’s common limited partners participated in the net income (loss) of the Arkoma operations before the date of the transaction.

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In April 2015, the FASB updated the accounting guidance for earnings per unit (“EPU”) of master limited partnerships (“MLP”) applying the two-class method. The updated accounting guidance specifies that for general partner transfers (or “drop downs”) to an MLP accounted for as a transaction between entities under common control, the earnings (losses) of the transferred business before the date of the transaction should be allocated entirely to the general partner’s interest, and previously reported EPU of the limited partners should not change. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs are also required.

ARP adopted this accounting guidance upon its effective date of January 1, 2016, which resulted in the following retrospective restatement to allocate the net income (loss) of the Arkoma operations before the date of the transaction entirely to our Predecessor’s general partner’s interest:

 

 

Prior to the Arkoma Acquisition, our Predecessor’s common limited partners did not participate in the net income (loss) of the Arkoma operations. Subsequent to the Arkoma Acquisition, our Predecessor’s common limited partners participated in the net income (loss) of the Arkoma operations, which was determined after the deduction of our Predecessor’s general partner’s and preferred unitholders’ interests.

Use of Estimates

The preparation of our condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our condensed consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, fair value of derivative instruments, fair value of certain gas and oil properties and asset retirement obligations, and fair value of assets and liabilities in connection with the application of fresh-start accounting. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.

Predecessor’s Net Income Per Common Unit

Basic net income attributable to our Predecessor’s common limited partners per unit was computed by dividing net income attributable to our Predecessor’s common limited partners, which was determined after the deduction of our Predecessor’s general partner’s and preferred unitholders’ interests, by the weighted average number of our Predecessor’s common limited partner units outstanding during the period. Net income attributable to our Predecessor’s common limited partners was determined by deducting net income attributable to participating securities, if applicable, income attributable to our Predecessor’s preferred limited partners and net income attributable to our Predecessor’s general partner’s Class A units. Our Predecessor’s general partner’s interest in net income was calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 10), with a priority allocation of net income to our Predecessor’s general partner’s incentive distributions, if any, in accordance with our Predecessor’s partnership agreement, and the remaining net income allocated with respect to our Predecessor’s general partner’s and limited partners’ ownership interests.

Our Predecessor presented net income per unit under the two-class method for MLPs, which considers whether the incentive distributions of a MLP represent a participating security. The two-class method considers whether our Predecessor’s partnership agreement contained any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under our Predecessor’s

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partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management believed our Predecessor’s partnership agreement contractually limited cash distributions to available cash; therefore, undistributed earnings were not allocated to the incentive distribution rights.

Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. Phantom unit awards, which consist of common units issuable under the terms of our long-term incentive plan, contain non-forfeitable rights to distribution equivalents. The participation rights would result in a non-contingent transfer of value each time we declare a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

The following is a reconciliation of net income allocated to our Predecessor’s common limited partners for purposes of calculating net income attributable to our Predecessor’s common limited partners per unit (in thousands, except unit data):

 

 

 

Diluted net income attributable to our Predecessor’s common limited partners per unit was calculated by dividing net income attributable to our Predecessor’s common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, convertible preferred units and warrants, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of our long-term incentive plan.

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The following table sets forth the reconciliation of our Predecessor’s weighted average number of common limited partner units used to compute basic net income attributable to our Predecessor’s common limited partners per unit with those used to compute diluted net income attributable to our Predecessor’s common limited partners per unit (in thousands):

 

 

Recently Issued Accounting Standards

In February 2016, the FASB updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented.  We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed consolidated financial statements.

In August 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs specific to line of credit arrangements. The updated accounting guidance allows the option of presenting deferred debt issuance costs related to line-of-credit arrangements as an asset, and subsequently amortizing over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. We adopted the updated accounting guidance effective January 1, 2016, and it did not have a material impact on our condensed consolidated financial statements.

In February 2015, the FASB updated the accounting guidance related to consolidation under the variable interest entity and voting interest entity models. The updated accounting guidance modifies the consolidation guidance for variable interest entities, limited partnerships and similar legal entities. We adopted this accounting guidance upon its effective date of January 1, 2016, and it did not have a material impact on our condensed consolidated financial statements.

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. We adopted this accounting guidance on January 1, 2016, and provided enhanced disclosures, as applicable, within our condensed consolidated financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed consolidated financial statements and our method of adoption.

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NOTE 3 – FRESH START ACCOUNTING

Upon our emergence from bankruptcy, we adopted fresh-start accounting in accordance with ASC 852. We qualified for fresh-start accounting because (i) the reorganization value of our assets immediately prior to the confirmation of the Plan was less than the post-petition liabilities and allowed claims, and (ii) the holders of existing voting shares of our Predecessor received less than 50% of the voting shares of the post-emergence Successor entity.

Reorganization Value: Reorganization value represents the fair value of the Successor’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Under fresh-start accounting, we allocated the reorganization value to our individual assets based on their estimated fair values.

Our reorganization value was derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long term debt and shareholders’ equity. The estimated enterprise value of the Successor of approximately $714.3 million represents management’s best estimate of fair value on the Plan Effective Date and is within the range of value contemplated by the Bankruptcy Court in confirmation of the Plan after extensive negotiations among the Company and its creditors.

We estimated the enterprise value of the Successor utilizing the discounted cash flow method. To estimate fair value utilizing the discounted cash flow method, we established an estimate of future cash flows for both our gas and oil production business and our partnership management business based on the financial projections in our disclosure statement. The financial projections for our gas and oil production business were based on our forecast, which includes a number of assumptions regarding future anticipated performance of reserves including decline curves for existing proved developed producing wells, as well as new wells brought online, commodity pricing and average realized pricing, and reductions for operating costs and general and administrative expenses.  The financial projections for our partnership management business were based on our forecast, which includes a number of assumptions regarding future anticipated performance including existing fee revenue streams and future annual partnership capital fund raises, based on historical averages. A terminal value was included for the partnership management business, and was calculated using a long-term growth rate of 1% on the projected cash flows of the final year of the forecast period.

The discount rates of 10% for our gas and oil production business and 12% for our partnership management business were estimated based on an after-tax weighted average cost of capital (“WACC”) derived from a comparable set of publicly-held companies reflecting the rate of return that would be expected by a market participant within each respective business. The WACC also takes into consideration a company-specific risk premium, reflecting the risk associated with the overall uncertainty of the financial projections used to estimate future cash flows.

A reconciliation of the reorganization value was provided in the table below:

 

Consolidated Balance Sheet

The adjustments set forth in the following condensed consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh-start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions or inputs.

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Reorganization Adjustments:

 

 

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Fresh Start Accounting Adjustments:

 

 

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Reorganization Items, net:

 

Incremental costs incurred as a result of the Chapter 11 Filings, net gain on settlement of liabilities subject to compromise and reorganization adjustments, and net impact of fresh start adjustments are classified as “Reorganization items, net” in the Predecessor’s condensed consolidated statement of operations.  The following table summarizes the reorganization items:

 

 

 

NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

 

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During the Successor period from September 1, 2016 through September 30, 2016, the Predecessor periods from January 1, 2016 through August 31, 2016 and the nine months ended September 30, 2015, we recognized $0.4 million, $18.7 million and $5.2 million, respectively, of non-cash property, plant and equipment additions, which was included within the changes in accounts payable and accrued liabilities on our condensed consolidated statements of cash flows.

We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rate used to capitalize interest on borrowed funds during the Successor period September 1, 2016 through September 30, 2016, the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015 was 7.6%, 6.0%, 6.5%, 6.5%, and 6.4%, respectively. The aggregate amount of interest capitalized during the Successor period September 1, 2016 through September 30, 2016, the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015 was $0.7 million, $1.7 million, $6.5 million, $4.0 million, and $12.0 million, respectively.

During the Successor period September 1, 2016 through September 30, 2016, the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015, $0.5 million, $1.3 million, $4.6 million, $1.6 million and $4.7 million, respectively, of accretion expense was recorded related to our asset retirement obligations within depreciation, depletion and amortization in our condensed consolidated statements of operations. For the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor recorded additional asset retirement obligation liabilities of $12.9 million in our condensed consolidated balance sheets due to the liquidation of some of our Predecessor’s Drilling Partnerships.

 

NOTE 5 – DEBT

Total debt consists of the following at the dates indicated (in thousands):

 

 

In April 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs. The updated accounting guidance requires that debt issuance costs be presented as a direct deduction from the associated debt obligation. We adopted this accounting guidance upon its effective date of January 1, 2016. The retrospective effect of the reclassification resulted in the following changes to our Predecessor’s balance sheet:

 

 

Cash Interest. Total cash payments for interest by us for the Successor period September 1, 2016 through September 30, 2016, the predecessor period from January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015, were $0.5 million, $53.7 million, $40.4 million and $87.7 million, respectively. There were no cash payments for interest for the predecessor period from July 1, 2016 through August 31, 2016.

 

First Lien Credit Facility

 

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On September 1, 2016, we entered into a $440 million third amended and restated first lien credit agreement with Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent, and the lenders party thereto (the “First Lien Credit Facility”).  A summary of the key provisions of the First Lien Credit Facility is as follows:

Second Lien Credit Facility

 

On September 1, 2016, we entered into an amended and restated second lien credit agreement with Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (the “Second Lien Credit Facility”) for an aggregate principal amount of $252.5 million maturing on February 23, 2020. A summary of the key provisions of the Second Lien Credit Facility is as follows:

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Old First Lien Credit Facility

Our Predecessor was party to a Second Amended and Restated Credit Agreement, dated as of July 31, 2013 by and among our Predecessor, the lenders from time to time party thereto, and Wells Fargo, as administrative agent, as amended, supplemented or modified from time to time (the “Old First Lien Credit Facility”), which provided for a senior secured revolving credit facility with a maximum borrowing base of $1.5 billion and was scheduled to mature in July 2018.

Pursuant to the Restructuring Support Agreement, our Predecessor completed the sale of substantially all our commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the Old First Lien Credit Facility. As of August 31, 2016 under our Predecessor, the weighted average interest rate on outstanding borrowings under the Old First Lien Credit Facility was 5.5%. Pursuant to the Plan, the Old First Lien Credit Facility was replaced by the First Lien Credit Facility (see Note 1).  

Old Second Lien Term Loan

Our Predecessor was party to a Second Lien Credit Agreement, dated as of February 23, 2015 by and among our Predecessor, the lenders from time to time party thereto, and Wilmington Trust, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “Old Second Lien Term Loan”), which provided for a second lien term loan in an original principal amount of $250.0 million.

As of August 31, 2016 under our Predecessor, the weighted average interest rate on outstanding borrowings under the Old Second Lien Term Loan was 10.0%. Pursuant to the Plan, the Old Second Lien Term Loan was replaced by the Second Lien Facility (see Note 1).  

Senior Notes

In January and February 2016, our Predecessor executed transactions to repurchase $20.3 million of our 7.75% Senior Notes and $12.1 million of our 9.25% Senior Notes for $5.5 million, which included $0.6 million of interest. As a result of these transactions, our Predecessor recognized $26.5 million as gain on early extinguishment of debt, net of accelerated amortization of deferred financing costs of $0.9 million, in the condensed consolidated statement of operations for the Predecessor period from January 1, 2016 through August 31, 2016.

Pursuant to the Plan, Holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of the common equity interests of us (see Note 1).

 

NOTE 6 – DERIVATIVE INSTRUMENTS

We use a number of different derivative instruments, principally swaps and options, in connection with our commodity price risk management activities. We do not apply hedge accounting to any of our derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings.

We enter into commodity future option contracts to achieve more predictable cash flows by hedging our exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Stock Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are priced based on the respective Mt. Belvieu price. These contracts were recorded at their fair values.

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Pursuant to the Restructuring Support Agreement, our Predecessor completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the Old First Lien Credit Facility.

The following table summarizes the commodity derivative activity and presentation in our condensed consolidated statements of operations for the periods indicated (in thousands):

 

 

 

The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities included on our condensed consolidated balance sheets for the periods indicated (in thousands):

 

 

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At September 30, 2016, we had the following commodity derivatives:

 

 

Secured Hedge Facility

At September 30, 2016, we have a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under our revolving credit facility, we are required to utilize this secured hedge facility for future commodity risk management activity for our equity production volumes within the participating Drilling Partnerships. We, as the ultimate general partner of the Drilling Partnerships, administer the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantee their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

An event of default occurred under the secured hedging facility agreement upon our filing of voluntary petitions for relief under Chapter 11. The lenders under the secured hedge facility agreed to forbear from exercising remedies in respect of such event of default while the Chapter 11 Filings were pending and, upon occurrence of the effective date of the Plan contemplated by the Restructuring Support Agreement, such event of default is no longer be deemed to exist or to continue under the secured hedge facility.

 

In addition, it will be an event of default under our First Lien Credit Facility if we, as the ultimate general partner of the Drilling Partnerships, breach an obligation governed by the secured hedge facility, and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

 

NOTE 7 – FAIR VALUE OF FINANCIAL INSTRUMENTS

 

Assets and Liabilities Measured at Fair Value on a Recurring Basis

We use a market approach fair value methodology to value our outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value.  As of September 30, 2016 and December 31, 2015, all of our derivative financial instruments were classified as Level 2.

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Information for financial instruments measured at fair value at September 30, 2016 and December 31, 2015 was as follows (in thousands):

 

 

 

Other Financial Instruments

Our other current assets and liabilities on our condensed consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair value of our long-term debt at September 30, 2016, which consists of our First Lien Credit Facility and Second Lien Credit Facility, was $639.4 million compared with a carrying amount of $690.3 million. At September 30, 2016, the carrying value of outstanding borrowings under our First Lien Credit Facility, which bears interest at variable interest rates, approximated estimated fair value. The estimated fair value of our Second Lien Credit Facility was based upon the market approach and calculated using yields of our Second Lien Credit Facility as provided by financial institutions and thus were categorized as Level 3 values.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Management estimated the fair values of natural gas and oil properties transferred to our Predecessor upon liquidations of certain Drilling Partnerships (see Note 8) based on discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, our future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves and estimated salvage values using our historical experience and external estimates of recovery values. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.  

Management estimated the fair value of asset retirement obligations transferred to our Predecessor upon liquidations of certain Drilling Partnerships (see Note 4) based on discounted cash flow projections using our historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future considering inflation rates, federal and state regulatory requirements, and our assumed credit-adjusted risk-free interest rate. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

Management estimated the fair value of our enterprise value and reorganizational value of assets and liabilities upon our emergence from bankruptcy through fresh-start accounting (see Note 3) utilizing the discounted cash flow method for both our gas and oil production business and our partnership management business based on the financial projections in our disclosure statement.  The resulting fair value of our equity was used to value shares issued under our incentive plan.  These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

 

 

NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with ATLS. Except for our named executive officers, we do not directly employ any persons to manage or operate our business. These functions are provided by employees of ATLS and/or its affiliates. As of September 30, 2016 and December 31, 2015, we had a $5.5 million receivable and a $1.3 million payable, respectively, from/to ATLS related to the timing of funding cash accounts related to general and administrative expenses, such as payroll and benefits, which was recorded in advances to/from affiliates in the condensed consolidated balance sheets.

Relationship with Drilling Partnerships. We conduct certain activities through, and a portion of our revenues are attributable to, sponsorship of the Drilling Partnerships. We serve as general partner and operator of the Drilling Partnerships and assume customary

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rights and obligations for the Drilling Partnerships. As the general partner, we are liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if we breach our responsibilities with respect to the operations of the Drilling Partnerships. We are entitled to receive management fees, reimbursement for administrative costs incurred and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements.

In March 2016, our Predecessor transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by our Predecessor to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, our Predecessor transferred $5.2 million of funds to certain of the Drilling Partnerships that were projected to make monthly or quarterly distributions to their limited partners over the next several months and/or quarters to ensure accessible distribution funding coverage in accordance with the respective Drilling Partnerships’ operations and partnership agreements in the event our Predecessor experienced a prolonged restructuring period as we perform all administrative and management functions for the Drilling Partnerships. On July 26, 2016, we adopted certain amendments to the Drilling Partnerships’ partnership agreements, in accordance with our ability to amend the Drilling Partnerships’ partnership agreements to cure an ambiguity in or correct or supplement any provision of the Drilling Partnerships’ partnership agreements as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the Chapter 11 Filings, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Drilling Partnerships nor cause the termination of the Drilling Partnerships.

We intend to continue to fund the Drilling Partnerships’ operations and obligations, as necessary, until they are liquidated. Depending on commodity pricing and each of the Drilling Partnerships’ reserves value, we expect to realize all outstanding receivables from the Drilling Partnerships’ through the receipt of cash flows from their operations and/or the transfer of net assets and liabilities to us upon their liquidation. During the predecessor period from January 1, 2016 to August 31, 2016, our Predecessor recorded $7.2 million and $12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to our Predecessor as a result of certain Drilling Partnership liquidations. The gas and oil properties and asset retirement obligations were recorded at their fair values on the respective dates of the Drilling Partnerships’ liquidation and transfer to our Predecessor (see Note 7) and resulted in a non-cash loss of $6.1 million, net of liquidation and transfer adjustments, for the predecessor period from January 1, 2016 through August 31, 2016, which was recorded in other income/(loss) in our Predecessor’s condensed consolidated statements of operations.  

On October 24, 2016, the Board of Directors of our subsidiary, Atlas Resources, LLC, approved our acquisition of properties in exchange for assuming all liabilities in connection with the liquidation of certain of our Drilling Partnerships.  These acquisitions have an effective date of October 1, 2016. We estimate we will record approximately $31.0 million and $14.7 million of gas and oil properties and asset retirement obligations, respectively, which will result in an estimated non-cash gain of approximately $16.3 million, before any liquidation and transfer accounting adjustments, that will be recognized in the fourth quarter of 2016.

During the Predecessor periods from July 1, 2016 to August 31, 2016 and January 1, 2016 to August 31, 2016, we recognized a $10.9 million provision for losses on Drilling Partnership receivables related to the write down of certain receivables to their estimated net realizable values. As of September 30, 2016 and December 31, 2015, we had trade receivables of $0.6 million and a $6.6 million, respectively, from certain of the Drilling Partnerships’, which were recorded in accounts receivable in the condensed consolidated balance sheets.  As of September 30, 2016 and December 31, 2015, we had trade payables of $2.3 million and $3.0 million, respectively, to certain of the Drilling Partnerships’, which were recorded in accounts payable in the condensed consolidated balance sheets.

Relationship with AGP. At the direction of ATLS, we charge direct costs, such as salaries and wages, and allocate indirect costs, such as rent and other general and administrative costs, to AGP based on the number of ATLS employees who devoted time to AGP’s activities.  In addition, Anthem Securities, Inc. (“Anthem”), our wholly owned subsidiary, acted as dealer manager for AGP’s private placement offering, which was completed in June 2015.  As the dealer manager, Anthem received compensation from AGP equal to a maximum of 12% of the gross proceeds of the private placement offering as selling commissions, marketing efforts, and other issuance costs. 

Anthem is currently acting as the dealer manager for AGP’s issuance and sale in a continuous offering of up to a maximum agreement amount of 100,000,000 common units representing limited partner interests in AGP as further described in AGP’s registration statement on Form S-1 (File No. 333-207537). AGP will pay Anthem (1) compensation equal to 3.00% of the gross proceeds of the offering (Anthem may reallow up to 1.50% of gross offering proceeds it receives as dealer manager fees to participating broker-dealers, but expects to reallow 1.25% of gross offering proceeds to participating broker-dealers); (2) 7.00% and 3.00% of aggregate gross proceeds from the sale of Class A common units and Class T common units, respectively, as sales commissions; (3) with respect to Class T common units, a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. On November 2, 2016, AGP decided to temporarily suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues.

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As of September 30, 2016 and December 31, 2015, we had a $0.1 million receivable and $8.7 million payable, respectively, from/to AGP related to AGP’s direct costs, indirect cost allocation and dealer manager costs, which was recorded in advances to/from affiliates in the condensed consolidated balance sheets.

 

 

NOTE 9 – COMMITMENTS AND CONTINGENCIES

General Commitments

We are the ultimate managing general partner of the Drilling Partnerships and have agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. We have structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally, for Drilling Partnerships with this structure, we are not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and we may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that we do not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by us to reflect current well performance, commodity prices and production costs, among other items. Based on our historical experience, as of September 30, 2016, our management believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.

While our historical structure has varied, we have generally agreed to subordinate a portion of our share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically from 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. We periodically compare the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, we recognize subordination as an estimated reduction of our pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which we have recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, we will recognize an estimated increase in our portion of historical cumulative gas and oil net production revenue, subject to a limitation of the cumulative subordination previously recognized. For the Successor period September 1, 2016 through September 30, 2016, the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015, $0.2 million, $0.4 million, $1.0 million, $0.4 million and $1.5 million, respectively, of our gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses.

As of September 30, 2016, we are committed to expend approximately $4.3 million, principally on drilling and completion expenditures.

Legal Proceedings

We are party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

 

NOTE 10 – INCOME TAXES

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

We recognize the financial statement benefit of a tax position after determining that the relevant tax authority would more likely than not sustain the position following an audit under guidance contained in FASB ASC 740.  For tax positions meeting a more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority.  Our policy is to reflect interest and

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penalties related to uncertain tax positions as part of the income tax expense, when and if they become applicable.  We have applied this methodology to all tax positions for which the statute of limitations remains open, and there are no additions, reductions or settlements in unrecognized tax benefits during the Successor period from September 1, 2016 to September 30, 2016. We have no material uncertain tax positions as of September 30, 2016.  

We have evaluated the full impact of the restructuring pursuant to the pre-packaged plan of reorganization and believe the reorganization will be treated as a taxable exchange under the Internal Revenue Code.  Accordingly, we will have an initial tax basis in the assets acquired equal to their respective fair market values immediately after the reorganization and no tax attributes will carryover to us as a result of the reorganization.  In addition, as part of the reorganization, we have elected to be treated as a corporation for U.S. Federal and state income tax purposes.

For the Successor period September 1, 2016 to September 30, 2016, we generated an operating loss but did not recognize any income tax benefit.  Management has determined uncertainties exist as to the future utilization of the operating loss carryforward; therefore, has recorded a full valuation allowance against our net deferred tax asset.  

We are subject to income taxes in the U.S. federal jurisdiction and various states. Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws and regulations and require significant judgment to apply. We are no longer subject to U.S. federal, state, and local, or non-U.S. income tax examinations by tax authorities for the years before 2013.  

 

 

NOTE 11 – ISSUANCES OF UNITS

As of the Plan Effective Date, we had 5,416,667 shares of our common equity outstanding. Titan Management holds our Series A Preferred Share, which entitles Titan Management to 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution if catch-up contributions are not made with respect to future equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. We have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in our limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of us unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.

On September 1, 2016, we adopted the Titan Energy, LLC Management Incentive Plan (the “MIP”) for the employees, directors and individual consultants of us and our affiliates. On October 26, 2016 the MIP was amended and restated to increase the number of shares that may be issued. The MIP permits the grant of options, phantom shares and restricted and unrestricted common shares, as well as dividend equivalent rights. Subject to adjustment in accordance with the MIP, a maximum of 655,555 common shares may be issued pursuant to awards under the MIP. Common Shares subject to forfeited awards or withheld to satisfy exercise prices or tax withholding obligations will again be available for delivery pursuant to other awards. The MIP has a term of 10 years and will be administered by the Board of Directors, which may delegate to a committee or the Company’s chief executive officer.  On September 1, 2016, 138,750 common shares from the MIP were issued and vested immediately as the service inception date was the date of the Chapter 11 Filings and the service completion date was the Plan Effective Date, resulting in $0.7 million of non-cash compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 to August 31, 2016. Also on September 1, 2016, 277,917 common shares from the MIP were issued and vest 33% on each of the next three anniversaries of the date of grant, resulting in $0.1 million of non-cash compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the Successor period from September 1, 2016 to September 30, 2016. At September 30, 2016, we had $1.5 million in unrecognized compensation expense related to unvested common shares. The fair value of the common shares was determined in connection with our estimate of the equity value of the Successor utilizing the discounted cash flow method (see Notes 3 and 7).

On the Plan Effective Date, all of our Predecessor’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any distribution or consideration.

Our Predecessor had an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to its equity distribution agreement, our Predecessor sold from time to time through the Agents its common units representing limited partner interests of the Predecessor having an aggregate offering price of up to $100.0 million. Sales of its common units were made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the former trading market for its common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. Our Predecessor paid each of the Agents a commission, which in each case was not more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of its equity distribution agreement, our Predecessor sold common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of its common units to an Agent as principal was pursuant to the terms of a separate terms agreement between the Predecessor and

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such Agent. During the Predecessor period from July 1, 2016 through August 31, 2016, our Predecessor did not issue any common limited partner units under its equity distribution program.  During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor issued 245,175 common limited partner units under its equity distribution program for net proceeds of $0.2 million, net of $4,000 in commissions and offering expenses paid.  During the Predecessor three months ended September 30, 2015, our Predecessor issued 5,519,110 common limited partner units under its equity distribution program for net proceeds of $18.6 million, net of $0.3 million in commissions and offering expenses paid. During the Predecessor nine months ended September 30, 2015, our Predecessor issued 8,404,934 common limited partner units under its equity distribution program for net proceeds of $40.0 million, net of $1.0 million in commissions and offering expenses paid.

In August 2015, our Predecessor entered into a distribution agreement with MLV & Co. LLC (“MLV”), which it terminated and replaced in November 2015, when our Predecessor entered into a distribution agreement with MLV and FBR Capital Markets & Co. in which it sold its 8.625% Class D Cumulative Redeemable Perpetual Preferred Units (“Class D Preferred Units”) and Class E Cumulative Redeemable Perpetual Preferred Units (“Class E Preferred Units”). Under both the August 2015 ATM Agreement and the November 2015 ATM Agreement, our Predecessor did not issue any Class D Preferred units nor Class E Preferred Units under its preferred equity distribution program for the Predecessor period from January 1, 2016 through August 31, 2016. During the three and nine months ended September 30, 2015, our Predecessor issued 90,328 Class D Preferred Units and 1,083 Class E Preferred Units under its preferred equity distribution program for net proceeds of $1.0 million, net of $0.2 million in commissions and offering expenses paid.

In May 2015, in connection with the Arkoma Acquisition, our Predecessor issued 6,500,000 of its common limited partner units in a public offering at a price of $7.97 per unit, yielding net proceeds of $49.7 million. Our Predecessor used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under its Old First Lien Credit Facility.

In April 2015, our Predecessor issued 255,000 of its Class E Preferred Units at a public offering price of $25.00 per unit for net proceeds of $6.0 million.

On March 31, 2015, to partially pay its portion of a quarterly installment related to the Eagle Ford acquisition, our Predecessor issued an additional 800,000 Class D Preferred Units to the seller at a value of $25.00 per unit.

On July 31, 2016, our Predecessor’s 3,749,986 Class C Preferred Units that were issued to ATLS on July 31, 2013, were converted into 3,749,986 common units and the associated warrant issued to ATLS to purchase 562,497 of its common units expired.

On July 12, 2016, our Predecessor received notification from the New York Stock Exchange (“NYSE”) that the NYSE commenced proceedings to delist its common units as a result of our failure to comply with the continued listed standards set forth in Section 802.01C of the NYSE Listed Company Manual to maintain an average closing price of $1.00 per unit over a consecutive 30 day period. Our Predecessor’s Class D Preferred Units and Class E Preferred Units were also delisted from the NYSE. Our Predecessor’s common units, Class D Preferred Units, and Class E Preferred Units began trading on the OTC market on July 13, 2016 with the ticker symbol “ARPJ” for its common units, “ARPJP” for its Class D Preferred Units, and “ARPJN” for its Class E Preferred Units.

On May 12, 2016, due to the income tax ramifications of the potential options our Predecessor was considering, our Predecessor’s Board of Directors delayed the vesting date of approximately 110,000 units granted to employees, directors and officers until March 2017.  The phantom units were set to vest between May 15, 2016 and August 31, 2016. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the predecessor period from January 1, 2016 through August 31, 2016.  As a result of the Chapter 11 Filings, our Predecessor’s 2012 Long-Term Incentive Plan was cancelled.  The remaining unrecognized compensation cost of $0.8 million was recognized upon the cancellation and was recorded in general and administrative expenses on the condensed consolidated statement of operations for the predecessor period from July 1, 2016 through August 31, 2016.

 

 

NOTE 12 – CASH DISTRIBUTIONS

We did not pay any distributions for the period from September 1, 2016 through September 30, 2016.

Our Predecessor had a monthly cash distribution program whereby it distributed all of its available cash (as defined in its partnership agreement) for that month to its unitholders within 45 days from the month end. If our Predecessor’s common unit distributions in any quarter exceed specified target levels, ATLS received between 13% and 48% of such distributions in excess of the specified target levels.

While outstanding, our Predecessor’s Class B Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 (or $0.1333 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. In July 2015, the remaining 39,654 of our Predecessor’s Class B Preferred Units were converted into common limited partner units.

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Our Predecessor’s Class C Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.51 (or $0.17 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. On May 5, 2016, our Predecessor’s Board of Directors elected to suspend our Predecessor’s common unit and Class C preferred distributions, beginning with the month of March of 2016, due to the continued lower commodity price environment.

Our Predecessor paid quarterly distributions on its Class D Preferred Units at an annual rate of $2.15625 per unit, $0.5390625 per unit paid on a quarterly basis, or 8.625% of the $25.00 liquidation preference. Our Predecessor paid quarterly distributions on its Class E Preferred Units at an annual rate of $2.6875 per unit, or $0.671875 per unit on a quarterly basis, or 10.75% of the $25.00 liquidation preference. On June 16, 2016, our Predecessor’s Board of Directors elected to suspend its quarterly distributions on its Class D Preferred Units and its Class E Preferred Units, beginning with the second quarter 2016 distribution, due to the continued lower commodity price environment. Our Predecessor’s Class D Preferred Units and Class E Preferred Units accrued distributions of $3.4 million and $0.3 million, respectively, from April 15, 2016 through August 31, 2016.  However, due to our Predecessor’s distribution suspension and our Predecessor’s recent Chapter 11 Filings, these amounts were not earned as the preferred units were cancelled without receipt of any consideration on the Plan Effective Date.

During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor paid four monthly cash distributions totaling $5.1 million to its common limited partners ($0.0125 per unit per month); $2.5 million to its Preferred Class C limited partners ($0.0125 per unit per month); and $0.2 million to its General Partner Class A holder ($0.0125 per unit per month). During our Predecessor’s nine months ended September 30, 2015, our Predecessor paid nine monthly cash distributions totaling $103.0 million to its common limited partners ($0.1966 per unit in both January and February 2015 and $0.1083 per unit in March through September 2015); $5.9 million to its Preferred Class C limited partners ($0.1966 per unit in both January and February 2015 and $0.17 per unit in March through September 2015); approximately $42,000 to its Preferred Class B limited partners ($0.1966 per unit in both January and February 2015 and $0.1333 per unit in March through July 2015); and $4.3 million to its General Partner Class A holder ($0.1966 per unit in both January and February 2015 and $0.1083 per unit in March through September 2015).

During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor paid two distributions totaling $4.4 million to its Class D Preferred units ($0.5390625 per unit) for the period October 15, 2015 through April 14, 2016. During our Predecessor’s nine months ended September 30, 2015, our Predecessor paid three distributions totaling $6.3 million to its Class D Preferred units ($0.6169270 per unit for the period October 2, 2014 through January 14, 2015 and $0.539063 per unit for the period January 15, 2015 through July 14, 2015).

During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor paid two distributions totaling $0.3 million to its Class E Preferred units ($0.671875 per unit) for the period October 15, 2015 through April 14, 2016.  During our Predecessor’s nine months ended September 30, 2015, our Predecessor paid one $0.2 million distribution to its Class E Preferred units ($0.6793 per unit) for the period April 14, 2015 through July 14, 2015.

 

 

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NOTE 13 – OPERATING SEGMENT INFORMATION

Our operations include and our predecessor’s operations included three reportable operating segments. These operating segments reflect the way we manage and our predecessor managed our operations and make business decisions. Operating segment data for the periods indicated were as follows (in thousands):

 

 

 

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NOTE 14 – SUBSEQUENT EVENTS

Partnership Liquidations. On October 24, 2016, the Board of Directors of our subsidiary, Atlas Resources, LLC, approved our acquisition of properties in exchange for assuming all liabilities in connection with the liquidation of certain of our Drilling Partnerships.  These acquisitions have an effective date of October 1, 2016 (see Note 8).

 

 

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ITEM 2:MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS OVERVIEW

We are an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations in basins across the United States. We sponsor and manage tax-advantaged investment partnerships (the “Drilling Partnerships”), in which we coinvest, to finance a portion of our natural gas, crude oil and NGL production activities. Unless the context otherwise requires, references to “Titan Energy, LLC,” “Titan,” “the Company,” “we,” “us,” “our” and “our company,” refer to Titan Energy, LLC and our consolidated subsidiaries (and its predecessor, where applicable).

Titan Energy Management, LLC (“Titan Management”) manages us and holds our Series A Preferred Share, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution as discussed below) and to appoint four of our seven directors.  Titan Management is a wholly owned subsidiary of Atlas Energy Group, LLC (“Atlas Energy Group” or “ATLS”; OTC: ATLS), which is a publicly traded company.

In addition to its preferred member interest in us, ATLS also holds general and limited partner interests in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, oil and NGLs, with operations primarily focused in the Eagle Ford Shale, and in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs.

FINANCIAL PRESENTATION

Our consolidated balance sheet at September 30, 2016, and the consolidated statements of operations for the period from September 1, 2016 through September 30, 2016 include our accounts and the accounts of our wholly-owned subsidiaries. The consolidated balance sheet at December 31, 2015, and the consolidated statements of operations for the period from July 1, 2016 through August 31, 2016, the period from January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015 include our predecessor’s accounts and the accounts of its wholly-owned subsidiaries. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the consolidated balance sheets and related consolidated statements of operations. Actual balances and results could be different from those estimates. All significant intercompany transactions and balances have been eliminated in the consolidation of the financial statements.

RECENT DEVELOPMENTS

ARP Restructuring and Emergence from Chapter 11 Proceedings

On July 25, 2016, Atlas Resource Partners, L.P. (“ARP”) and certain of its subsidiaries and ATLS, solely with respect to certain sections thereof, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% Senior Notes due 2021 (the “7.75% Senior Notes”) and the 9.25% Senior Notes due 2021 (the “9.25% Senior Notes” and, together with the 7.75% Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties agreed, subject to certain terms and conditions, to support ARP’s restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).

 

On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 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 were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

 

ARP operated its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired by the Plan and were satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

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On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:

 

First Lien Credit Facility

On September 1, 2016, we entered into a $440 million third amended and restated first lien credit agreement with Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent, and the lenders party thereto (the “First Lien Credit Facility”).  (See “Credit Facilities” below).

Second Lien Credit Facility

On September 1, 2016, we entered into an amended and restated second lien credit agreement with Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (the “Second Lien Credit Facility”) for an aggregate principal amount of $252.5 million maturing on February 23, 2020. (See “Credit Facilities” below).

Common Equity

As of the Plan Effective Date, we had 5,416,667 common shares outstanding. (See “Issuance of Units” below).

Liquidation of Drilling Partnerships

On October 24, 2016, the Board of Directors of our subsidiary, Atlas Resources, LLC, approved our acquisition of properties in exchange for assuming all liabilities in connection with the liquidation of certain of our Drilling Partnerships.  These acquisitions have an effective date of October 1, 2016.  We estimated we will record approximately $31.0 million and $14.7 million of gas and oil properties and asset retirement obligations, respectively, which will result in an estimated non-cash gain of approximately $16.3 million, before any liquidation and transfer accounting adjustments, that will be recognized in the fourth quarter of 2016.

Liquidation of Hedge Portfolio

On July 27, 2016, pursuant to the Restructuring Support Agreement, we completed the sale of certain of our commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under ARP’s Old First Lien Credit Facility.

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GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by key trends in natural gas and oil production markets. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines since the fourth quarter of 2014 through the third quarter of 2016. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

Our future gas and oil reserves, production, cash flow, our ability to make payments on our debts and our ability to make distributions to our unitholders, including ATLS, depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. To the extent we do not have sufficient capital, our ability to drill and acquire more reserves will be negatively impacted.  Based on current market conditions, we believe that a reduction in our debt and cash interest obligations is needed to improve our financial position and flexibility and to position us to take advantage of opportunities that may arise out of the current industry downturn.

RESULTS OF OPERATIONS

 

Matters Impacting Comparability of Results

Fresh Start Accounting. Upon our emergence from bankruptcy, we adopted fresh-start accounting in accordance with ASC 852. We qualified for fresh-start accounting because (i) the reorganization value of our assets immediately prior to the confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of existing voting shares of our predecessor company received less than 50% of the voting shares of the post-emergence Successor entity.

As a result of the application of fresh start accounting, at the Plan Effective Date, our assets and liabilities were recorded at their estimated fair values which, in some cases, are significantly different than amounts included in our financial statements prior to the Plan Effective Date. Accordingly, our financial condition and results of operations on and after the Effective Date are not comparable to our financial condition and results of operations prior to the Plan Effective Date. For comparative purposes, we believe that reporting and analyzing the successor period results for the period from September 1, 2016 through September 30, 2016 combined with the predecessor period results from the period July 1, 2016 through August 31, 2016 and the successor period results for the period from September 1, 2016 through September 30, 2016 combined with the predecessor period results from the period January 1, 2016 through August 31, 2016 compared with the three and nine months ended September 30, 2016, respectively, provides a reasonable basis of comparison and is consistent with how management reviews our results.

Gas and Oil Production

Production Profile. Currently, we have focused our natural gas, crude oil and NGL production operations in various plays throughout the United States. Through September 30, 2016, we have established production positions in the following operating areas:

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The following table presents the number of wells we drilled and the number of wells we turned in line, both gross and for our interest, during the combined three and nine months ended September 30, 2016 and the three and nine months ended September 30, 2015:

 

 

 

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Production Volumes. The following table presents our total net natural gas, crude oil, and NGL production volumes per day in each of our operating areas and total production for the combined three and nine months ended September 30, 2016 and the three and nine months ended September 30, 2015:

 

 

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Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. The following table presents our production revenues and average sales prices for our natural gas, oil, and natural gas liquids production for the combined three and nine months ended September 30, 2016 and the three and nine months ended September 30, 2015 along with our average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

 

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The $33.1 million decrease in gas and oil production revenues during the combined three months ended September 30, 2016 as compared to the prior year period consisted of an $11.2 million decrease attributable to our Coal-bed Methane operations, a $10.2 million decrease associated with our Rangely operations, a $5.0 million decrease attributable to our Barnett Shale/Marble Falls operations, a $4.2 million decrease attributable to our Eagle Ford operations, a $1.6 million decrease attributable to our Mid-Continent operations and a $0.9 million decrease attributable to our Appalachia operations. Our gas and oil production revenue decreases in all operating areas were attributed to lower production volumes and decreases in natural gas and oil prices compared to the prior year period.

The $134.7 million decrease in gas and oil production revenues during the combined nine months ended September 30, 2016 as compared to the prior year period consisted of a $54.8 million decrease attributable to our Coal-bed Methane operations, a $29.5 million decrease attributable to our Barnett Shale/Marble Falls operations, a $26.4 million decrease associated with our Rangely operations, a $12.8 million decrease attributable to our Eagle Ford operations, a $7.1 million decrease attributable to our Mid-Continent operations and a $4.1 million decrease attributable to our Appalachia operations. Our gas and oil production revenue decreases in all operating areas were attributed to lower production volumes and decreases in commodity prices compared to the prior year period.

The $11.2 million decrease in gas and oil production expenses during the combined three months ended September 30, 2016 as compared to the prior year period primarily consisted of a $4.4 million decrease attributable to our Barnett Shale/Marble Falls operations, a $4.2 million decrease attributable to our Coal-bed Methane operations, a $1.9 million decrease attributable to our Appalachia operations, a $0.6 million decrease attributable to our Mid-Continent operations and a $0.2 million decrease attributable to our Eagle Ford operations, partially offset by a $0.1 million increase attributable to our Rangely operations. Total production costs per Mcfe decreased between the periods primarily as a result of continued efforts to reduce operating costs in each of our areas of production.

The $33.1 million decrease in gas and oil production expenses during the combined nine months ended September 30, 2016 as compared to the prior year period primarily consisted of a $12.7 million decrease attributable to our Barnett Shale/Marble Falls operations, an $11.9 million decrease attributable to our Coal-bed Methane operations, a $5.7 million decrease attributable to our Appalachia operations, a $2.3 million decrease attributable to our Mid-Continent operations and a $0.6 million decrease attributable to our Eagle Ford operations, partially offset by a $0.1 million increase attributable to our Rangely operations. Total production costs per Mcfe decreased between the periods primarily as a result of continued efforts to reduce operating costs in each of our areas of production.

PARTNERSHIP MANAGEMENT

Well Construction and Completion

Drilling Program Results. The number of wells we drill will vary within the partnership management segment depending on the amount of capital we raise through our Drilling Partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for Drilling Partnerships we sponsor. As our drilling contracts with the Drilling Partnerships are on a “cost-plus” basis, an increase or decrease in our average cost per well also results in a proportionate increase or decrease in our average revenue per well, which directly affects the number of wells we drill. The

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following table presents the amounts of Drilling Partnership investor capital raised and deployed, as well as sets forth information relating to these revenues and the related costs and number of net wells associated with these revenues during the periods indicated (dollars in thousands):

 

 

 

 

The $0.4 million and $5.6 million decreases in well construction and completion gross profit margin during the combined three and nine month periods ended September 30, 2016, respectively, as compared to the respective prior year period were due to decreases in the number of partnership wells for which completion activities were being performed related to timing and the economics of such activities during the challenging commodity price environment along with a downward revision to our estimated total costs to

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complete wells, which resulted in unfavorable adjustments to our gross profit margin recognized on our percentage of completion basis for the wells in progress.  

Administration and Oversight

 

 

Administration and oversight fee revenues represent supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for our Drilling Partnerships. Typically, we receive a lower administration and oversight fee related to shallow, vertical wells we drill within the Drilling Partnerships, such as those in the Marble Falls play, as compared to deep, horizontal wells, such as those drilled in the Marcellus and Utica Shales. The following table presents the number of gross and net development wells we drilled for our Drilling Partnerships during the combined three and nine months ended September 30, 2016 and the three and nine months ended September 30, 2015. There were no exploratory wells drilled during the combined three and nine months ended September 30, 2016 and the three and nine months ended September 30, 2015:

 

 

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The $5.0 million and $5.9 million decreases in administration and oversight fee revenues during the combined three and nine months ended September 30, 2016, respectively, compared to the prior year periods were primarily due to decreases in the number of wells spud within the combined three and nine months ended September 30, 2016 compared with the prior year periods.

Well Services

 

 

 

Well service revenue and expenses represent the monthly operating fees we charge and the work our service company performs, including work performed for our Drilling Partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells for which we serve as operator.

The $2.0 million and $6.1 million decreases in well services revenue during the combined three and nine month periods ended September 30, 2016, respectively, as compared to the respective prior year periods are primarily related to lower fee revenue associated with our salt water gathering and disposal systems within the Mississippi Lime and Marble Falls operating areas, which are utilized by our Drilling Partnership wells, an increase in the number of wells having been shut in and certain Drilling Partnerships liquidated in the current year, both of which result in a reduction of the monthly operating fees we charge the Drilling Partnerships.

The $0.9 million and $1.5 million decreases in well services expenses during the combined three and nine months ended September 30, 2016 as compared to the prior year periods are primarily related to lower labor costs.

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Gathering and Processing

 

 

 

Gathering and processing margin includes gathering fees we charge to our Drilling Partnership wells and the related expenses and gross margin for our processing plants in the New Albany Shale and the Chattanooga Shale. Generally, we charge a gathering fee to our Drilling Partnership wells equivalent to the fees we remit. In Appalachia, a majority of our Drilling Partnership wells are subject to a gathering agreement, whereby we remit a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, we charge our Drilling Partnership wells a 13% gathering fee. As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

The $0.1 million and $0.9 unfavorable movements in gathering and processing margin during the combined three and nine month periods ended September 30, 2016, respectively, as compared to the respective prior year periods were principally due to lower overall natural gas prices in Appalachia and lower gathering fees, particularly from our Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing our gathering pipeline.

OTHER REVENUES AND EXPENSES

 

 

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Gain (Loss) on Mark-to-Market Derivatives. We recognize changes in the fair value of our derivatives immediately within gain (loss) on mark-to-market derivatives on our condensed consolidated statements of operations. The decreases in mark-to-market derivative gains during the combined three and nine-month periods ended September 30, 2016 compared to the respective prior year periods is due to increases in commodity future prices relative to our hedged derivative positions.  

 

General and Administrative. The $8.1 million increase in general and administrative expenses for the combined three months ended September 30, 2016 as compared to the prior year period is primarily due to $10.9 million related to the write-down of receivables from certain Drilling Partnerships to their estimated net realizable values, a $1.6 million valuation adjustment of our subsidiary’s deferred tax assets and a $1.2 million increase in non-cash stock compensation primarily due to the issuance of shares under the Titan Energy, LLC Management Incentive Plan, partially offset by a $3.3 million decrease in various non-recurring financial advisors and legal counsel costs due to reclassifying the costs to reorganization items, net, a $1.5 million decrease in salaries, wages and benefits and an $0.8 million decrease in other corporate activities.

 

The $18.5 million increase in general and administrative expenses for the combined nine months ended September 30, 2016 as compared to the prior year period is primarily due to $10.9 million related to the write-down of receivables from certain Drilling Partnerships to their estimated net realizable values, a $7.0 million increase in salaries, wages and benefits, a $2.3 million increase in non-recurring reorganization items, net, a $1.6 million valuation adjustment of our subsidiary’s deferred tax assets and a $1.5 million increase in syndication expenses due to lower program fundraising activities, partially offset by a $3.3 million decrease in non-cash stock compensation and a $1.5 million decrease in other corporate activities.

Depreciation, Depletion and Amortization. The decreases in depreciation, depletion and amortization for the combined three and nine month periods ended September 30, 2016 as compared to the respective prior year periods were primarily due to $14.8 million and $42.1 million decreases in our depletion expense, respectively. The following table presents total depletion expense, depletion as a percent of gas and oil production revenue and depletion expense per Mcfe for our operations for the respective periods (in thousands, except for percentage and per Mcfe data):

 

 

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Depletion expense varies from period to period and is directly affected by changes in our gas and oil reserve quantities, production levels, product prices and changes in the depletable cost basis of our gas and oil properties. The decreases in depletion expense and depletion expense per Mcfe when compared with the comparable prior year periods were due to impairments of our proved properties recorded in the third and fourth quarters of 2015 as a result of lower forecasted commodity prices, which reduced the depletable cost basis of our proved gas and oil properties in the current year periods. The increase in the depletion expense as a percentage of gas and oil revenues for the combined nine months ended September 30, 2016 when compared with the comparable prior year period was due to the decrease in our gas and oil revenues as a result of lower commodity prices and production volumes in the current year period, partially offset by the decrease in depletion expense described above.

 

Asset Impairment. The $672.2 million asset impairment for the three and nine months ended September 30, 2015 represents the $740.2 million of asset impairment related to oil and gas properties in the Barnett, Coal-bed Methane, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, reduced by $68.0 million of future hedge gains reclassified from accumulated other comprehensive income.

Interest Expense. The decrease in our interest expense during the combined three months ended September 30, 2016 as compared to the prior year period consisted of a $10.7 million decrease associated with interest expense on our Predecessor’s Notes primarily due to only one month of interest expense in the current year period due to the Chapter 11 Filings, partially offset by a $1.8 million increase associated with lower outstanding borrowings under our First Lien Credit Facility at higher interest rates, a $1.6 million decrease in capitalized interest due to lower capital spending (a $2.3 million decrease in our Predecessor’s capitalized interest for the period from July 1, 2016 through September 30, 2016 as compared to the three months ended September 30, 2015, partially offset by $0.7 million for the Successor period from September 1, 2016 through September 30, 2016) and an $0.8 million increase associated with our Second Lien Credit Facility, which replaced our Predecessor’s Old Second Lien Term Loan pursuant to the Plan, with a higher rate of interest than the Old Second Lien Term Loan.

The increase in our interest expense during the combined nine months ended September 30, 2016 as compared to the prior year period consisted of a $4.8 million decrease in capitalized interest due to lower capital spending (a $5.5 million decrease in our Predecessor’s capitalized interest for the period from January 1, 2016 through August 31, 2016 as compared to the nine months ended September 30, 2015, partially offset by $0.7 million for the Successor period from September 1, 2016 through September 30, 2016), a $4.6 million increase associated primarily with two months of interest expense with a higher rate of interest under our Second Lien Credit Facility, which replaced our Predecessor’s Old Second Lien Term Loan pursuant to the Plan, a $4.5 million increase associated with higher interest rates on lower outstanding borrowings under our First Lien Credit Facility and a $1.9 million increase primarily associated with amortization of our Predecessor’s deferred financing costs, partially offset by a $10.5 million decrease associated with interest expense on our Predecessor’s Notes due to only seven months of interest expense in the current year period resulting from the Chapter 11 Filings , a $1.3 million decrease associated with interest expense on our Predecessor’s Notes due to our Predecessor’s repurchases of Notes in the first quarter of 2016, and a $0.7 million decrease in amortization of our deferred financing costs.

Gain on Early Extinguishment of Debt. The gain on early extinguishment of debt for the combined nine months ended September 30, 2016 represents a $26.5 million gain related to the repurchase of a portion of our Predecessor’s 7.75% and 9.25% Senior Notes. Of the $26.5 million gain, $27.4 million related to the gain from the redemption of the principal values and accrued interest, partially offset by $0.9 million related to the accelerated amortization of the related deferred financing costs.

Reorganization Items, Net. Incremental costs incurred as a result of the Chapter 11 Filings, net gain on settlement of liabilities subject to compromise and reorganization adjustments, and net impact of fresh start adjustments are classified as “Reorganization items, net” in the Predecessor’s condensed consolidated statement of operations.  The following table summarizes the reorganization items:

 

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Other income (loss). The $3.0 million loss for the combined three months ended September 30, 2016 represents a non-cash loss for the write-off of notes receivables with certain investors of our Drilling Partnerships.

The $9.2 million loss for the combined nine months ended September 30, 2016 represents $6.1 million of non-cash losses, net of liquidation and transfer adjustments, of certain Drilling Partnerships’ liquidation and transfer of oil and gas properties and asset retirement obligations to us and $3.0 million of non-cash loss for the write-off of notes receivables with certain investors of our Drilling Partnerships.

 

Income Tax Provision (Benefit). For the one month ended September 30, 2016, we recorded a full valuation allowance against our deferred tax asset balance which reduced our effective tax rate to zero. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. Our effective tax rate fluctuates as a result of the impact of state income taxes and permanent differences between our accounting for certain revenue or expense items and their corresponding treatment for income tax purposes.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash generated from operations, capital raised through our Drilling Partnerships, and borrowings under our revolving credit facility (see “Credit Facilities”). Our primary cash requirements, in addition to normal operating expenses, are for debt service including interest and capital expenditures. In general, we expect to fund:

 

We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under our credit facilities and equity and debt offerings. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on our liquidity position. In addition, challenges with our ability to raise capital through our Drilling Partnerships, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, could negatively impact our ability to remain in compliance with the covenants under our credit facilities.

If we are unable to remain in compliance with the covenants under our credit facilities (as described in “Credit Facilities”), absent relief from our lenders, as applicable, we may be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under our credit facilities, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. If an event of default occurs (including if our borrowing base is redetermined below our current outstanding borrowings and we are unable to repay the deficiency or deposit additional collateral to eliminate such deficiency), or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern.

We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet, meeting our debt service obligations and/or achieving cost efficiency.  For example, we could pursue options such as refinancing, restructuring or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels.  

We also continue to implement various cost saving measures to reduce our capital, operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. We will continue to be opportunistic and aggressive in managing our cost structure and,

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in turn, our liquidity to meet our capital and operating needs. We cannot provide any assurances that any of these efforts will be successful or will result in cost reductions or cash flows or the timing of any such cost reductions or additional cash flows. It is also possible additional adjustments to our plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets, seeking additional partners to develop our assets, and/or reducing our planned capital program.  In addition, to the extent commodity prices remain low or decline further, or we experience disruptions in our longer-term access to or cost of capital, our ability to fund future capital expenditures or growth projects may be further impacted.

During 2016, we have taken steps to improve our liquidity, strengthen our balance sheet and expand our financial flexibility including reducing our debt by approximately $900 million and interest expense by $80 million per year.  See “Recent Developments – Restructuring and Chapter 11 Bankruptcy Proceedings” and “Restructuring Support Agreement” for further information regarding our Restructuring Support Agreement and the Plan.

 

Cash Flows – Combined Nine Months Ended September 30, 2016 Compared with the Nine Months Ended September 30, 2016

 

 

The change in cash flows provided by operating activities when compared with the comparable prior year period was primarily due to:

 

 

 

 

 

 

 

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The change in cash flows used in investing activities when compared with the comparable prior year period was primarily due to:

The change in cash flows provided by (used in) financing activities when compared with the comparable prior year period was primarily due to:

Capital Requirements

At September 30, 2016, the capital requirements of our natural gas and oil production primarily consist of expenditures to maintain or increase production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures. The following table summarizes our total capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

 

 

During the three months ended September 30, 2016, our total capital expenditures consisted primarily of $7.1 million for wells drilled exclusively for our own account compared with $14.4 million for the comparable prior year period, $0.2 million of investments in our Drilling Partnerships compared with $7.3 million for the prior year comparable period, $0.8 million of leasehold acquisition

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costs compared with $6.1 million for the prior year comparable period and $3.3 million of corporate and other costs compared with $5.0 million for the prior year comparable period.

During the nine months ended September 30, 2016, our total capital expenditures consisted primarily of $16.9 million for wells drilled exclusively for our own account compared with $40.1 million for the comparable prior year period, $0.8 million of investments in our Drilling Partnerships compared with $26.0 million for the prior year comparable period, $2.8 million of leasehold acquisition costs compared with $9.9 million for the prior year comparable period and $9.8 million of corporate and other costs compared with $26.3 million for the prior year comparable period.

We continuously evaluate acquisitions of gas and oil assets. In order to make any acquisitions in the future, we believe we will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies. There can be no assurance that we will be successful in our efforts to obtain outside capital. As of September 30, 2016, we are committed to expend approximately $4.3 million on drilling and completion and other capital expenditures, excluding acquisitions. We expect to fund these capital expenditures primarily with cash flow from operations, capital raised through our Drilling Partnerships and borrowings under our revolving credit facility.

OFF BALANCE SHEET ARRANGEMENTS

As of September 30, 2016, our off-balance sheet arrangements were limited to our letters of credit outstanding of $4.2 million and commitments to spend $4.3 million related to our drilling and completion and capital expenditures, excluding acquisitions.

We are the ultimate managing general partner of the Drilling Partnerships and have agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. We have structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally, for Drilling Partnerships with this structure, we are not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and we may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that we do not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by us to reflect current well performance, commodity prices and production costs, among other items. Based on our historical experience, as of September 30, 2016, we believe that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.

CREDIT FACILITIES

 

First Lien Credit Facility

On September 1, 2016, we entered into a $440 million third amended and restated first lien credit agreement with Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent, and the lenders party thereto (the “First Lien Credit Facility”).  A summary of the key provisions of the First Lien Credit Facility is as follows:

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Second Lien Credit Facility

On September 1, 2016, we entered into an amended and restated second lien credit agreement with Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (the “Second Lien Credit Facility”) for an aggregate principal amount of $252.5 million maturing on February 23, 2020. A summary of the key provisions of the Second Lien Credit Facility is as follows:

 

Old First Lien Credit Facility

Our Predecessor was party to a Second Amended and Restated Credit Agreement, dated as of July 31, 2013 by and among our Predecessor, the lenders from time to time party thereto, and Wells Fargo, as administrative agent, as amended, supplemented or modified from time to time (the “Old First Lien Credit Facility”), which provided for a senior secured revolving credit facility with a maximum borrowing base of $1.5 billion and was scheduled to mature in July 2018.

Pursuant to the Restructuring Support Agreement, we completed the sale of substantially all our commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the Old First Lien Credit Facility. As of August 31, 2016 under our Predecessor, the weighted average interest rate on outstanding borrowings under the Old First Lien Credit Facility was 5.5%. Pursuant to the Plan, the Old First Lien Credit Facility was replaced by the First Lien Credit Facility.  

Old Second Lien Term Loan

Our Predecessor was party to a Second Lien Credit Agreement, dated as of February 23, 2015 by and among our Predecessor, the lenders from time to time party thereto, and Wilmington Trust, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “Old Second Lien Term Loan”), which provided for a second lien term loan in an original principal amount of $250.0 million.

As August 31, 2016 under our Predecessor, the weighted average interest rate on outstanding borrowings under the Old Second Lien Term Loan was 10.0%. Pursuant to the Plan, the Old Second Lien Term Loan was replaced by the Second Lien Credit Facility.  

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Senior Notes

In January and February 2016, we executed transactions to repurchase $20.3 million of our 7.75% Senior Notes and $12.1 million of our 9.25% Senior Notes for $5.5 million, which included $0.6 million of interest. As a result of these transactions, 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 consolidated statement of operations for the Predecessor period from January 1, 2016 through August 31, 2016.

Pursuant to the Plan, Holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the chapter 11 cases, received 90% of the common equity interests of us.

SECURED HEDGE FACILITY

At September 30, 2016, we 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 our revolving credit facility, we are required to utilize this secured hedge facility for future commodity risk management activity for our equity production volumes within the participating Drilling Partnerships. We, as the ultimate general partner of the Drilling Partnerships, administer the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantee their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

An event of default occurred under the secured hedging facility agreement upon our filing of voluntary petitions for relief under Chapter 11. The lenders under the secured hedge facility agreed to forbear from exercising remedies in respect of such event of default while the Chapter 11 Filings were pending and, upon occurrence of the effective date of the Plan contemplated by the Restructuring Support Agreement, such event of default is no longer be deemed to exist or to continue under the secured hedge facility.

In addition, it will be an event of default under our First Lien Credit Facility if we, as the ultimate general partner of the Drilling Partnerships, breach an obligation governed by the secured hedge facility, and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

ISSUANCE OF UNITS

As of the Plan Effective Date, we had 5,416,667 shares of our common equity outstanding. Titan Management holds our Series A Preferred Share, which entitles Titan Management to receive to 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution if catch-up contributions are not made with respect to future equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. We have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in our limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of us unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.

On September 1, 2016, we adopted the Titan Energy, LLC Management Incentive Plan (the “MIP”) for the employees, directors and individual consultants of us and our affiliates. On October 26, 2016, the MIP was amended and restated to increase the number of shares that may be issued. The MIP permits the grant of options, phantom shares and restricted and unrestricted common shares, as well as dividend equivalent rights. Subject to adjustment in accordance with the MIP, a maximum of 655,555 common shares may be issued pursuant to awards under the MIP. Common Shares subject to forfeited awards or withheld to satisfy exercise prices or tax withholding obligations will again be available for delivery pursuant to other awards. The MIP has a term of 10 years and will be administered by the Board of Directors, which may delegate to a committee or the Company’s chief executive officer.  On September 1, 2016, 138,750 common shares from the MIP were issued and vested immediately as the service inception date was the date of the Chapter 11 Filings and the service completion date was the Plan Effective Date, resulting in $0.7 million of non-cash compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the Predecessor periods from July 1, 2016 to August 31, 2016 and January 1, 2016 to August 31, 2016. Also on September 1, 2016, 277,917 common shares from the MIP were issued and vest 33% on each of the next three anniversaries of the date of grant, resulting in $0.1 million of non-cash compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the Successor period from September 1, 2016 to September 30, 2016. At September 30, 2016, we had $1.5 million in

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unrecognized compensation expense related to unvested common shares. The fair value of the common shares was determined in connection with our estimate of the equity value of the Successor utilizing the discounted cash flow method (see Notes 3 and 7).

On the Plan Effective Date, all of our Predecessor’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any distribution or consideration.

Our Predecessor had an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to its equity distribution agreement, our Predecessor sold from time to time through the Agents its common units representing limited partner interests of the Predecessor having an aggregate offering price of up to $100.0 million. Sales of its common units were made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the former trading market for its common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. Our Predecessor paid each of the Agents a commission, which in each case was not more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of its equity distribution agreement, our Predecessor sold common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of its common units to an Agent as principal was pursuant to the terms of a separate terms agreement between the Predecessor and such Agent. During the Predecessor period from July 1, 2016 through August 31, 2016, our Predecessor did not issue any common limited partner units under its equity distribution program.  During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor issued 245,175 common limited partner units under its equity distribution program for net proceeds of $0.2 million, net of $4,000 in commissions and offering expenses paid.  During the Predecessor three months ended September 30, 2015, our Predecessor issued 5,519,110 common limited partner units under its equity distribution program for net proceeds of $18.6 million, net of $0.3 million in commissions and offering expenses paid. During the Predecessor nine months ended September 30, 2015, our Predecessor issued 8,404,934 common limited partner units under its equity distribution program for net proceeds of $40.0 million, net of $1.0 million in commissions and offering expenses paid.

In August 2015, our Predecessor entered into a distribution agreement with MLV & Co. LLC (“MLV”), which it terminated and replaced in November 2015, when our Predecessor entered into a distribution agreement with MLV and FBR Capital Markets & Co. in which it sold its 8.625% Class D Cumulative Redeemable Perpetual Preferred Units (“Class D Preferred Units”) and Class E Cumulative Redeemable Perpetual Preferred Units (“Class E Preferred Units”). Under both the August 2015 ATM Agreement and the November 2015 ATM Agreement, our Predecessor did not issue any Class D Preferred units nor Class E Preferred Units under its preferred equity distribution program for the Predecessor period from January 1, 2016 through August 31, 2016. During the three and nine months ended September 30, 2015, our Predecessor issued 90,328 Class D Preferred Units and 1,083 Class E Preferred Units under its preferred equity distribution program for net proceeds of $1.0 million, net of $0.2 million in commissions and offering expenses paid.

In May 2015, in connection with the Arkoma Acquisition, our Predecessor issued 6,500,000 of its common limited partner units in a public offering at a price of $7.97 per unit, yielding net proceeds of $49.7 million. Our Predecessor used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under its Old First Lien Credit Facility.

In April 2015, our Predecessor issued 255,000 of its Class E Preferred Units at a public offering price of $25.00 per unit for net proceeds of $6.0 million.

On March 31, 2015, to partially pay its portion of a quarterly installment related to the Eagle Ford acquisition, our Predecessor issued an additional 800,000 Class D Preferred Units to the seller at a value of $25.00 per unit.

On July 31, 2016, our Predecessor’s 3,749,986 Class C Preferred Units that were issued to ATLS on July 31, 2013, were converted into 3,749,986 common units and the associated warrant issued to ATLS to purchase 562,497 of its common units expired.

On July 12, 2016, our Predecessor received notification from the New York Stock Exchange (“NYSE”) that the NYSE commenced proceedings to delist its common units as a result of our failure to comply with the continued listed standards set forth in Section 802.01C of the NYSE Listed Company Manual to maintain an average closing price of $1.00 per unit over a consecutive 30 day period. Our Predecessor’s Class D Preferred Units and Class E Preferred Units were also delisted from the NYSE. Our Predecessor’s common units, Class D Preferred Units, and Class E Preferred Units began trading on the OTC market on July 13, 2016 with the ticker symbol “ARPJ” for its common units, “ARPJP” for its Class D Preferred Units, and “ARPJN” for its Class E Preferred Units.

On May 12, 2016, due to the income tax ramifications of the potential options our Predecessor was considering, our Predecessor’s Board of Directors delayed the vesting date of approximately 110,000 units granted to employees, directors and officers until March 2017.  The phantom units were set to vest between May 15, 2016 and August 31, 2016. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the predecessor period from January 1, 2016 through August 31, 2016.  As a result of the

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Chapter 11 Filings, our Predecessor’s 2012 Long-Term Incentive Plan was cancelled.  The remaining unrecognized compensation cost of $0.8 million was recognized upon the cancellation and was recorded in general and administrative expenses on the condensed consolidated statement of operations for the predecessor period from July 1, 2016 through August 31, 2016.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Recently Issued Accounting Standards

See Notes 2 and 5 to our condensed consolidated financial statements for additional information related to recently issued accounting standards.

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed consolidated financial statements, please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

 

 

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of the market risk-sensitive instruments were entered into for purposes other than trading.

General

All of our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on September 30, 2016. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.

We are subject to the risk of loss on our derivative instruments that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the quarterly monitoring of our oil, natural gas and NGLs counterparties’ credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords us netting or set off opportunities to mitigate exposure risk; and (v) when appropriate requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. Our assets related to derivatives as of September 30, 2016 represent financial instruments from ten counterparties; all of which are financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with our revolving credit facility. Subject to the terms of our revolving credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the revolving credit facility.

Interest Rate Risk. At September 30, 2016, $435.8 million was outstanding under our revolving credit facility and $254.5 million was outstanding under our term loan facility. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our consolidated interest expense for the twelve-month period ending September 30, 2017 by approximately $6.9 million.

Commodity Price Risk. Our market risk exposure to commodities is due to the fluctuations in the commodity prices and the impact those price movements have on our financial results. To limit our exposure to changing commodity prices, we use financial derivative instruments, including financial swap and option instruments, to hedge portions of our future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap agreements, we receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period.

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Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our consolidated operating income for the twelve-month period ending September 30, 2017 of approximately $7.6 million.

Realized pricing of our natural gas, oil, and NGL production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas, oil and NGL production. Pricing for natural gas, oil and NGL production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas, oil and NGL prices, we enter into natural gas and oil swap and put option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter (“OTC”) futures contracts with qualified counterparties. OTC contracts are generally financial contracts which are settled with financial payments or receipts and generally do not require delivery of physical hydrocarbons. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are priced based on the respective Mt. Belvieu price.

At September 30, 2016, we had the following commodity derivatives:

 

 

 

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.

There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

 

 

There have been no material changes to the Risk Factors disclosed in Part I – Item 1A “–Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2015 except as follows.

 

The Chapter 11 cases may have a negative impact on our image, which may negatively impact our business going forward.

 

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Negative events or publicity associated with our Chapter 11 cases could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties. In addition, we may face greater difficulties in attracting, motivating and retaining management. These and other related issues could adversely affect our operations and financial condition.

 

Even following the consummation of the Plan, we may not be able to achieve our stated goals and continue as a going concern.

 

Even following the consummation of the Plan, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other plan of reorganization will achieve our stated goals.

 

Furthermore, even following the reduction in our debts as a result of the consummation of the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all.

 

Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern.

 

Our long term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

 

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirements necessary to fund our ongoing operations, we incurred significant fees and other costs in connection with the Chapter 11 Filings. We cannot assure you that our cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations following the consummation of the Plan.

 

Our financial results may be volatile and may not reflect historical trends.

 

Following the consummation of the Plan, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial performance. As a result, our historical financial performance is likely not indicative of our financial performance following the commencement of the Chapter 11 Filings.

 

In addition, following the consummation of the Plan, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We have adopted fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

 

The Plan was based in large part upon assumptions and analyses developed by us. If these assumptions prove to be incorrect, we may be unsuccessful.

 

The Plan has affected both our capital structure and the ownership, structure and operation of our businesses and reflects assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to obtain adequate liquidity and financing sources; (ii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iii) our ability to retain key employees, and (iv) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

 

In addition, the Plan relied upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by the Plan will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations.

 

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SIGNATURES

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

 

 

 

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