Edgar Filing: Titan Energy, LLC

Three Months Ended March 31,

Weighted average number of common shares - basic ⁽¹⁾

Add dilutive effect of share based awards at end of period

Weighted average number of common shares - diluted

tten-10q_20170331.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2017

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-35317

TITAN ENERGY, LLC

(Exact name of registrant as specified in its charter)

Delaware		90-0812516
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

425 Houston Street, Suite 300 Fort Worth, TX		76102
(Address of principal executive offices)		(Zip code)

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, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐		Accelerated filer ☐		Non-accelerated filer ☒		Smaller reporting company ☐
						Emerging growth company ☐

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

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒ No ☐

The number of outstanding common shares of the registrant on May 11, 2017 was 5,450,270.

TITAN ENERGY, LLC

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

		PAGE
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)

	Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016	5

	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2017 and 2016	6

	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2017 and 2016	7

	Condensed Consolidated Statement of Changes in Members’ Equity (Deficit) for the Three Months Ended March 31, 2017	8

	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	9

	Notes to Condensed Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37

Item 4.	Controls and Procedures	38

PART II. OTHER INFORMATION

Item 6.	Exhibits	38

SIGNATURES		40

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:

•

our ability to achieve the anticipated benefits from the consummation of the filings by our predecessor under Chapter 11 of the United States Bankruptcy Code;

•

the prices of natural gas, oil, NGLs and condensate;

•

changes in the market price of our common shares;

•

future financial and operating results;

•

actions that we may take in connection with our liquidity needs, including the ability to service our debt, and ability to satisfy covenants in our debt documents;

•

economic conditions and instability in the financial markets;

•

the impact of our securities being quoted on the OTCQX Market rather than listed on a national exchange like the NYSE;

•

success in efficiently developing and exploiting our reserves and economically finding or acquiring additional recoverable reserves and meeting our substantial capital investment needs;

•

the accuracy of estimated natural gas and oil reserves;

•

the financial and accounting impact of hedging transactions;

•

potential changes in tax laws and environmental and other regulations which may affect our operations;

•

the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations at a reasonable cost and within applicable environmental rules;

•

the effects of unexpected operational events and drilling conditions, and other risks associated with drilling operations;

•

impact fees and severance taxes;

•

the effects of intense competition in the natural gas and oil industry;

•

general market, labor and economic conditions and uncertainties;

•

the ability to retain certain key customers;

•

dependence on the gathering and transportation facilities of third parties;

•

the availability of drilling rigs, equipment and crews;

•

access to sufficient amounts of carbon dioxide for tertiary recovery operations;

•

expirations of undeveloped leasehold acreage;

•

exposure to financial and other liabilities of the managing general partners of the investment partnerships;

•

exposure to new and existing litigation; and

•

development of alternative energy resources.

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 Annual Report on Form 10-K for the fiscal year ended December 31, 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.

PART I: FINANCIAL INFORMATION

ITEM 1: FINANCIAL STATEMENTS

TITAN ENERGY, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)


	March 31,		December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	28,966	$	24,446
Accounts receivable	27,786			33,728
Advances to affiliates	10,251			4,145
Subscriptions receivable	—			5,656
Prepaid expenses and other	19,408			18,125
Total current assets	86,411			86,100
Property, plant and equipment, net	780,930			784,723
Long-term derivative asset	1,227			—
Other assets, net	10,670			11,011
Total assets	$	879,238	$	881,834

LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	30,191	$	30,161
Liabilities associated with drilling contracts	5,787			10,656
Current portion of derivative liability	17,235			34,799
Accrued well drilling and completion costs	7,092			4,933
Accrued interest	1,643			1,789
Accrued liabilities	15,734			19,551
Current portion of long-term debt	701,602			694,810
Total current liabilities	779,284			796,699
Long-term derivative liability	163			14,615
Asset retirement obligations	77,159			75,347
Other long-term liabilities	2,238			2,114
Commitments and contingencies (Note 8)
Members’ Equity (Deficit):
Series A Preferred member’s equity (deficit)		393		(145	)
Common shareholders’ equity (deficit)		20,001		(6,796	)
Total members’ equity (deficit)		20,394		(6,941	)
Total liabilities and members’ equity (deficit)	$	879,238	$	881,834

See accompanying notes to condensed consolidated financial statements.

TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share and unit data)

(Unaudited)

	Successor			Predecessor
	Three Months Ended March 31,
	2017			2016
Revenues:
Gas and oil production	$	70,593		$	48,492
Drilling partnership management	10,050				8,596
Gain on mark-to-market derivatives		29,493			46,120
Total revenues	110,136				103,208
Costs and expenses:
Gas and oil production	29,987				35,842
Drilling partnership management	8,171				6,283
General and administrative	13,758				17,077
Depreciation, depletion and amortization	16,492				30,045
Total costs and expenses	68,408				89,247
Operating income		41,728			13,961
Interest expense		(13,985	)		(27,705	)
Gain on early extinguishment of debt		—			26,498
Other income (loss)	(654		)		9
Income before income taxes		27,089			12,763
Income tax provision (benefit)		180			—
Net income		26,909			12,763
Preferred member / limited partner dividends		—			(3,648	)
Net income attributable to common shareholders and Series A preferred member	$	26,909		$
Net income attributable to common limited partners and the general partner	$	—		$	9,115
Allocation of net income attributable to:
Series A Preferred member	$	538		$	—
Common shareholders	$	26,371		$	—
Common limited partners’ interest	$	—		$	8,933
General partner’s interest	$	—		$	182
Net income attributable to common shareholders per share / common limited partners per unit (Note 2):
Basic	$	5.10		$	0.09
Diluted	$	4.81		$	0.09
Weighted average shares / common limited partner units outstanding (Note 2):
Basic	5,170				102,403
Diluted	5,486				102,696

See accompanying notes to condensed consolidated financial statements.

TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

	Successor		Predecessor
	Three Months Ended March 31,
	2017		2016
Net income	$	26,909	$	12,763
Other comprehensive income (loss):
Derivative instruments designated as cash flow hedges:
Reclassification to net income of mark-to-market gains		—		(3,515	)
Total other comprehensive income (loss)		—		(3,515	)
Comprehensive income attributable to Series A Preferred member and common shareholders	$	26,909	$	—
Comprehensive income attributable to common and preferred limited partners and the general partner	$	—	$	9,248

See accompanying notes to condensed consolidated financial statements.

TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN MEMBERS’ EQUITY (DEFICIT)

(in thousands, except unit data)

(Unaudited)

	Series A Preferred Member’s Interest					Common Shareholders’ Interest					Total Members’ Equity (Deficit)
	Shares		Amount			Shares		Amount			Total Members’ Equity (Deficit)
Balance at December 31, 2016		1	$	(145	)		5,447,787	$	(6,796	)	$	(6,941	)
Net issued and unissued shares under incentive plans		—		—			—		426			426
Net income		—		538			—		26,371			26,909
Balance at March 31, 2017		1	$	393			5,447,787	$	20,001		$	20,394

See accompanying notes to condensed consolidated financial statements.

TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Successor			Predecessor
	Three Months Ended March 31,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	26,909			$	12,763
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		16,492					30,045
Gain on derivatives		(23,158	)				(40,332		)
Gain on extinguishment of debt		—				(26,498				)
Other (income) loss		1,006					(9		)
Non-cash compensation expense		426					(47		)
Non-cash interest expense		6,654					—
Amortization of deferred financing costs and debt discount		655				4,101
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(6,875	)				46,170
Accounts payable and accrued liabilities		(6,759	)				(61,112		)
Net cash provided by (used in) operating activities	15,350							(34,919			)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(10,444	)				(13,170		)
Net cash used in investing activities	(10,444		)					(13,170			)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facility		—				135,000
Repayments under revolving credit facility		—				(55,000				)
Senior note repurchases		—				(5,528				)
Distributions paid to shareholders/unitholders		—				(8,246				)
Net proceeds from issuance of common limited partner units		—				206
Deferred financing costs, distribution equivalent rights and other		(386	)				(411		)
Net cash provided by (used in) financing activities	(386		)					66,021
Net change in cash and cash equivalents		4,520					17,932
Cash and cash equivalents, beginning of period		24,446					1,353
Cash and cash equivalents, end of period	$	28,966			$	19,285

See accompanying notes to condensed consolidated financial statements.

TITAN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 1 – ORGANIZATION

We are a publicly traded (OTCQX: TTEN) Delaware limited liability company and an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States but primarily focused on the horizontal development of resource potential from the Eagle Ford Shale in South Texas. 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 our 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 (“ATLS”; OTCQX: 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 March 31, 2017, we had 5,447,787 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 certain of their lenders (the “Restructuring Support Parties”) to support ARP’s 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.”

On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:

•

ARP’s first lien lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and became lenders under our first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche (the “First Lien Credit Facility”) (refer to Note 4 – Debt for further information regarding terms and provisions).

•

ARP’s second lien lenders received a pro rata share of our second lien exit facility credit agreement with an aggregate principal amount of $252.5 million (the “Second Lien Credit Facility”) (refer to Note 4 – Debt for further information regarding terms and provisions). In addition, ARP’s second lien lenders received a pro rata share of 10% of our common shares, subject to dilution by a management incentive plan.

•

ARP’s senior note holders, in exchange for 100% of the $668 million aggregate principal amount of senior notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of our common shares, subject to dilution by a management incentive plan.

•

all of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.

•

ARP transferred all of its assets and operations to us as a new holding company and ARP dissolved. As a result, we became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended.

•

Titan Management, a wholly owned subsidiary of ATLS, received a Series A Preferred Share, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution if catch-up contributions are not made with respect to future equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. Four of the seven initial members of the board of directors were designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. We have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in our limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of us unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.

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

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities and Exchange Commission regarding interim financial reporting and include all adjustments that are necessary for a fair presentation of our consolidated results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The consolidated results of operations for the interim periods presented are not necessarily indicative of results for the full year. The year-end condensed consolidated balance sheet was derived from audited financial statements but does not include all disclosures required by U.S. GAAP. For a more complete discussion of our accounting policies and certain other information, refer to our consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

In connection with the Chapter 11 Filings, we were subject to the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852 Reorganizations (“ASC 852”).

Upon emergence from bankruptcy on the Plan Effective Date, we adopted fresh-start accounting in accordance with ASC 852. 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 a result, our condensed consolidated statement of operations subsequent to the Plan Effective Date is not comparable to ARP’s condensed consolidated statement of operations prior to the Plan Effective Date. Our condensed 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 the Plan Effective Date 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 condensed 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.

Reclassifications

Certain reclassifications have been made to our condensed consolidated financial statements for the prior year periods to conform to classifications used in the current year, specifically related to our segment information on the condensed consolidated statement of operations and segment footnote disclosures. See Note 10 for additional information.

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 10-30%. 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 Predecessor had historically funded its operations, acquisitions and cash distributions primarily through cash flows generated from its operations, amounts available under its credit facilities and equity and debt offerings. Since the Plan Effective Date, we have funded our operations through cash flows generated from our operations. 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 2017. 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, have negatively impacted our ability to remain in compliance with the covenants under our credit facilities.

We were not in compliance with certain of the financial covenants under our credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. As a result of the amendment referenced below, our financial covenants will not be tested again until the quarter ending December 31, 2017. We do not currently have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there is substantial doubt regarding our ability to continue as a going concern. We have classified $701.6 million of outstanding indebtedness under our credit facilities, which is net of $1.9 million of deferred financing costs, as current portion of long term debt, net within our condensed consolidated balance sheet as of March 31, 2017, based on the occurrence of the 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.

On April 19, 2017, we entered into an amendment to our First Lien Credit Facility in an attempt to ameliorate some of our liquidity concerns. The amendment provides for, among other things, waivers of our non-compliance, increases in certain financial covenant ratios and scheduled decreases in our borrowing base (refer to Note 4 – Debt for further information regarding the specific amended terms and provisions). In addition, we expect that we will sell a significant amount of non-core assets in the near future to comply with the requirements of our First Lien Credit Facility amendment and to attempt to enhance our liquidity.

In addition to the amendments to the financial ratio covenants, the First Lien Credit Facility lenders waived certain defaults by us with respect to the fourth quarter of 2016, including compliance with the ratios of Total Debt to EBITDA and First Lien Debt to EBITDA, as well as our obligation to deliver financial statements without a “going concern” qualification. The First Lien Credit Facility lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to our Second Lien Credit Facility), the failure to extend the standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the First Lien Credit Facility.

Even following this amendment, we continue to face liquidity issues and are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet.

On April 21, 2017, the lenders under the our Second Lien Credit Facility delivered a notice of events of default and reservation of rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the 180-day standstill period under the intercreditor agreement, during which the lenders under the Second Lien Credit Facility are prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility. The lenders have not accelerated the payment of amounts outstanding under the Second Lien Credit Facility.

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 and meeting our debt service obligations. 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 are evaluating various options, but there is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders. In addition, we expect that we will sell a significant amount of non-core assets in the near future to comply with the requirements of our First Lien Credit Facility amendment and to attempt to enhance our liquidity.

We cannot assure you that we would be able to implement the above actions, if necessary, on commercially reasonable terms, or at all, in a manner that would be permitted under the terms of our debt instruments or in a manner that does not negatively impact the price of our securities. Additionally, there can be no assurance that the above actions would allow us to meet our debt obligations and capital requirements.

Appalachia Divestiture

On May 4, 2017, we entered into a definitive agreement to sell our conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC, for $84.2 million. The transaction includes the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure (the “Appalachian Assets”). In 2016, the Appalachian Assets generated approximately 30 MMcfepd of net production (92% gas, 8% liquids). We will retain our Utica Shale position, Indiana assets and West Virginia CBM assets in the region. The transaction is subject to customary closing conditions, has an effective date of April 1, 2017 and is expected to close in June 2017. The net proceeds will be used to repay a portion of outstanding borrowings under our First Lien Credit Facility. The transaction will significantly improve our First Lien Credit Facility metrics and is expected to fulfill our borrowing base step down to $360 million, which is scheduled to occur on August 31, 2017.

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 of gas and oil properties and fair value of derivative instruments. 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.

Income Taxes

Our effective tax rate for the three months ended March 31, 2017 was 0.6%, which represents our expected Texas Franchise Tax liability. Our income tax provision differs from the provision computed by applying the U.S. Federal statutory corporate income tax rate of 35% primarily due to the valuation allowance on our deferred tax assets.

Successor’s Net Income Attributable to Common Shareholders Per Share

Our Successor’s basic net income attributable to common shareholders per share is computed by dividing net income attributable to our common shareholders by the weighted-average number of common shares outstanding, excluding any unvested restricted shares, for the period. Our Successor’s diluted net income attributable to common shareholders per share is similarly calculated except that the common shares outstanding for the period are increased using the treasury stock method to reflect the potential dilution that could occur if outstanding share based awards were vested at the end of the applicable period. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted net income attributable to common shareholders per share as their impact would be anti-dilutive.

The following table is a reconciliation of our Successor’s basic and diluted weighted average number of common shares used to calculate basic and diluted net income attributable to common shareholders per share (in thousands):

(1)	For the period presented, 278,000 restricted common shares outstanding were excluded from the basic weighted average number of common shares because they were not vested.

Predecessor’s Net Income Per Common Unit

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

	Predecessor
	Three Months ended March 31, 2016
Net income	$	12,763
Preferred limited partner dividends		(3,648	)
Net income attributable to common limited partners and the general partner		9,115
Less: General partner’s interest		182
Net income attributable to common limited partners		8,933
Less: Net income attributable to participating securities – phantom units		25
Net income utilized in the calculation of net income attributable to common limited partners per unit – Basic		8,908
Plus: Convertible preferred limited partner dividends⁽¹⁾		—
Net income utilized in the calculation of net loss attributable to common limited partners per unit – Diluted	$	8,908

(1)	For the period presented, distributions on our Predecessor’s Class C convertible preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive.

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):

Weighted average number of common limited partner units—diluted

102,696

(1)

For the period presented, potential common limited partner units issuable upon (a) conversion of our Predecessor’s Class C preferred units and (b) exercise of the common unit warrants issued with our Predecessor’s Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As our Predecessor’s Class D and Class E preferred units were convertible only upon a change of control event, they were not considered dilutive securities for earnings per unit purposes.

Recently Issued Accounting Standards

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

In 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 evaluating the impact of this updated accounting guidance on our condensed consolidated financial statements, and based on the continuing evaluation of our revenue streams, this accounting guidance is not expected to have a material impact on our net income (loss). This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.

NOTE 3 – PROPERTY, PLANT AND EQUIPMENT

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


	March 31, 2017			December 31, 2016
Natural gas and oil properties:
Proved properties	$	728,139		$	717,839
Unproved properties		74,434			74,434
Support equipment and other		14,701			14,180
Total natural gas and oil properties		817,274			806,453
Less – accumulated depreciation, depletion and amortization		(36,344	)		(21,730	)
	$	780,930		$	784,723

During the Successor three months ended March 31, 2017 and the Predecessor three months ended March 31, 2016, we recognized $1.8 million and $18.7 million, respectively, of non-cash investing activities capital expenditures, which was reflected 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 three months ended March 31, 2017 and the Predecessor three months ended March 31, 2016, was 7.7% and 6.7%, respectively. The aggregate amount of interest capitalized during the Successor three months ended March 31, 2017 and the Predecessor three months ended March 31, 2016 was $0.1 million and $2.4 million, respectively.

For the Successor three months ended March 31, 2017 and the Predecessor three months ended March 31, 2016, we recorded $1.9 million and $1.7 million, respectively, of accretion expense related to our and our Predecessor’s asset retirement obligations within depreciation, depletion and amortization in our and our Predecessor’s condensed consolidated statements of operations. For the Predecessor three months ended March 31, 2016, our Predecessor incurred liabilities of $2.8 million in asset retirement obligations in its condensed consolidated balance sheet due to the consolidation of some of its Drilling Partnerships.

NOTE 4 – DEBT

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


	March 31,			December 31,
	2017			2016
First Lien Credit Facility	$	435,809		$	435,809
Second Lien Credit Facility		267,676			261,022
Deferred financing costs, net of accumulated amortization of $335 and $172, respectively		(1,883	)		(2,021	)
Total debt, net		701,602			694,810
Less current maturities		(701,602	)		(694,810)
Total long-term debt, net	$	—		$	—

Cash Interest. Total cash payments for interest by us for the Successor three months ended March 31, 2017 and the Predecessor three months ended March 31, 2016, were $6.9 million and $41.2 million, respectively.

First Lien Credit Facility

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

•

Borrowing base of a $410 million conforming reserve based tranche plus a $30 million non-conforming tranche.

•

Provides for the issuance of letters of credit, which reduce borrowing capacity.

•

Obligations are secured by mortgages on substantially all of our oil and gas properties and first priority security interests in substantially all of our assets and are guaranteed by certain of our material subsidiaries, and any non-guarantor subsidiaries of ours are minor.

•

Borrowings bear interest at our election at either LIBOR plus an applicable margin between 3.00% and 4.00% per annum or the “alternate base rate” plus an applicable margin between 2.00% and 3.00% per annum, which fluctuates based on utilization. We are also required to pay a fee of 0.50% per annum on the unused portion of the borrowing base. At March 31, 2017, the weighted average interest rate on outstanding borrowings under the First Lien Credit Facility was 5.0%.

•

Contains covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets.

•

Requires us to enter into commodity hedges covering at least 80% of our expected 2019 production prior to December 31, 2017.

We were not in compliance with certain of the financial covenants under our credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. On April 19, 2017, we, Titan Energy Operating, LLC (our wholly owned subsidiary), as borrower, and certain subsidiary guarantors entered into a Third Amendment (the “First Lien Credit Facility Amendment”) to the First Lien Credit Facility with Wells Fargo, as administrative agent, and the lenders party thereto. Pursuant to the First Lien Credit Facility Amendment, certain of the financial ratio covenants were revised upwards. Specifically, beginning December 31, 2017, we will be required to maintain a ratio of Total Debt to EBITDA (each as defined in the First Lien Credit Facility) of not more than 5.50 to 1.00 for each fiscal quarter through December 31, 2018 and of not more than 5.00 to 1.00 thereafter. We will also be required, beginning December 31, 2017, to maintain a ratio of First Lien Debt (as defined in the First Lien Credit Facility) to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter through December 31, 2018 and of not more than 3.50 to 1.00 thereafter.

In addition to the amendments to the financial ratio covenants, the First Lien Credit Facility lenders waived certain defaults by us with respect to the fourth quarter of 2016, including compliance with the ratios of Total Debt to EBITDA and First Lien Debt to EBITDA, as well as our obligation to deliver financial statements without a “going concern” qualification. The First Lien Credit Facility lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to our second lien credit facility), the failure to extend the 180-day standstill period under the intercreditor

agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the First Lien Credit Facility.

The First Lien Credit Facility Amendment confirms the conforming and non-conforming tranches of the borrowing base at $410 million and $30 million, respectively, but requires us to take actions (which can include asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $330 million by August 31, 2017 and to $190 million by October 1, 2017 (subject to extension at the administrative agent’s option to October 31, 2017). Similarly, the non-conforming tranche of the borrowing base will be required to be reduced to $10 million by November 1, 2017. In addition, we will be required to use excess asset sale proceeds (after application in accordance with the existing terms of the First Lien Credit Facility) to repay outstanding borrowings and reduce the applicable borrowing base to the required level.

Second Lien Credit Facility

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

•

Until May 1, 2017, interest will be payable at a rate of 2% in cash plus paid-in-kind interest at a rate equal to the Adjusted LIBO Rate (as defined in the Second Lien Credit Facility) plus 9% per annum. During the subsequent 15-month period, cash and paid-in-kind interest will vary based on a pricing grid tied to our leverage ratio under the First Lien Credit Facility. After such 15-month period, interest will accrue at a rate equal to the Adjusted LIBO Rate plus 9% per annum and will be payable in cash.

•

All prepayments are subject to the following premiums, plus accrued and unpaid interest:

4.5% of the principal amount prepaid for prepayments prior to February 23, 2017;

2.25% of the principal amount prepaid for prepayments on or after February 23, 2017 and prior to February 23, 2018; and

no premium for prepayments on or after February 23, 2018.

•

Obligations are secured on a second priority basis by security interests in the same collateral securing the First Lien Credit Facility and are guaranteed by certain of our material subsidiaries, and any non-guarantor subsidiaries of ours are minor.

•

Contains covenants that limit our ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions, engage in other business activities, and other covenants substantially similar to those in the First Lien Credit Facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables.

•

Requires us to maintain certain financial ratios (the financial ratios will use an annualized EBITDA measurement for periods prior to June 30, 2017):

EBITDA to Interest Expense (each as defined in the Second Lien Credit Facility) of not less than 2.50 to 1.00;

Total Leverage Ratio (as defined in the Second Lien Credit Facility) of no greater than 5.5 to 1.0 prior to December 31, 2017 and no greater than 5.0 to 1.0 thereafter; and

Current assets to current liabilities (each as defined in the Second Lien Credit Facility) of not less than 1.0 to 1.0.

On April 21, 2017, the lenders under the our Second Lien Credit Facility delivered a Notice, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of the Notice began the 180-day standstill period under the intercreditor agreement, during which the lenders under the Second Lien Credit Facility are prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility. The lenders have not accelerated the payment of amounts outstanding under the Second Lien Credit Facility.

NOTE 5 – 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.

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

	Successor			Predecessor
	Three Months Ended March 31,
	2017			2016
Portion of settlements associated with gains (losses) previously recognized within accumulated other comprehensive income, net of prior year offsets⁽¹⁾	$	—		$	3,515
Portion of settlements attributable to subsequent mark to market gains (losses)⁽²⁾	(3,749		)		45,193
Total cash settlements on commodity derivative contracts	$	(3,749	)	$	48,708

Gains recognized on cash settlement⁽²⁾	$	6,335		$	5,788
Gains recognized on open derivative contracts⁽²⁾	23,158				40,332
Gains on mark-to-market derivatives	$	29,493		$	46,120

(1)	Recognized in gas and oil production revenue.

(2)	Recognized in gain (loss) on mark-to-market derivatives.

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

Offsetting Derivatives as of March 31, 2017	Gross Amounts Recognized			Gross Amounts Offset			Net Amount Presented

Current portion of derivative assets	$	632		$	(632	)	$	—
Long-term portion of derivative assets		3,200		(1,973		)		1,227
Total derivative assets	$	3,832		$	(2,605	)	$	1,227

Current portion of derivative liabilities	$	(17,867	)	$	632		$	(17,235	)
Long-term portion of derivative liabilities	(2,136		)	1,973			(163		)
Total derivative liabilities	$	(20,003	)	$	2,605		$	(17,398	)

Offsetting Derivatives as of December 31, 2016
Current portion of derivative assets	$	7		$	(7	)	$	—
Long-term portion of derivative assets		819			(819	)		—
Total derivative assets	$	826		$	(826	)	$	—

Current portion of derivative liabilities	$	(34,806	)	$	7		$	(34,799	)
Long-term portion of derivative liabilities		(15,434	)		819			(14,615	)
Total derivative liabilities	$	(50,240	)	$	826		$	(49,414	)

At March 31, 2017, we had the following commodity derivatives instruments:

Type	Production Period Ending December 31,	Volumes⁽¹⁾		Average Fixed Price⁽²⁾		Fair Value Liability			Total Type
						(in thousands)⁽²⁾			(in thousands)
Natural Gas – Fixed Price Swaps	2017	38,759,800	⁽³⁾	$	3.140	$	(6,373	)
	2018	47,559,300		$	2.959	$	(3,437	)
									$	(9,810	)
Crude Oil – Fixed Price Swaps	2017	891,500	⁽³⁾	$	46.971	$	(4,121	)
	2018	1,011,100		$	49.544	$	(2,240	)
									$	(6,361	)
						Total net liabilities			$	(16,171	)

(1)	Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels.

(2)	Fair value for natural gas fixed price swaps are based on forward NYMEX natural gas prices, as applicable. Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) index crude oil prices, as applicable.

(3)	The production volumes for 2017 include the remaining nine months of 2017 beginning April 1, 2017.

NOTE 6 – FAIR VALUE OF FINANCIAL INSTRUMENTS

Assets and Liabilities Measured 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 March 31, 2017 and December 31, 2016, all of our derivative financial instruments were classified as Level 2.

Information for financial instruments measured at fair value were as follows (in thousands):

Derivatives, Fair Value, as of March 31, 2017	Level 1		Level 2			Level 3		Total
Assets, gross
Commodity swaps	$	—	$	3,832		$	—	$	3,832
Total derivative assets, gross		—	3,832				—	3,832
Liabilities, gross
Commodity swaps		—		(20,003	)		—		(20,003	)
Total derivative liabilities, gross		—		(20,003	)		—		(20,003	)
Total derivatives, fair value, net	$	—	$	(16,171	)	$	—	$	(16,171	)

Derivatives, Fair Value, as of December 31, 2016	Level 1		Level 2			Level 3		Total
Assets, gross
Commodity swaps	$	—	$	826		$	—	$	826
Total derivative assets, gross		—		826			—		826
Liabilities, gross
Commodity swaps	$	—		(50,240	)		—		(50,240	)
Total derivative liabilities, gross		—		(50,240	)		—		(50,240	)
Total derivatives, fair value, net		—	$	(49,414	)	$	—	$	(49,414	)

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 March 31, 2017, which consists of our First Lien Credit Facility and Second Lien Credit Facility, approximated carrying value of $703.5 million. At March 31, 2017, 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.

NOTE 7 – 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 March 31, 2017 and December 31, 2016, we had receivables of $8.9 million and $3.3 million, respectively, from 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 our condensed consolidated balance sheets.

Relationship with Drilling Partnerships. We conduct certain activities through, and a portion of our revenues are attributable to, sponsorship of the Drilling Partnerships. We serve as general partner and operator of the Drilling Partnerships and assume customary rights and obligations for the Drilling Partnerships. As the general partner, we are liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if we breach our responsibilities with respect to the operations of the Drilling Partnerships. We are entitled to receive management fees, reimbursement for administrative costs incurred and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements.

In March 2016, our Predecessor transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by our Predecessor to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program.

As of March 31, 2017 and December 31, 2016, we had trade receivables of $0.2 million and $0.3 million, respectively, from certain of the Drilling Partnerships, which were recorded in accounts receivable in our condensed consolidated balance sheets. As of March 31, 2017 and December 31, 2016, we had trade payables of $5.0 million and $5.6 million, respectively, to certain of the Drilling Partnerships, which were recorded in accounts payable in our 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. As of March 31, 2017 and December 31, 2016, we had receivables of $1.3 million and $0.8 million, respectively, from AGP related to AGP’s direct costs and indirect cost allocation, which was recorded in advances to affiliates in our condensed consolidated balance sheets.

Other Relationships. We have other related party transactions with regard to certain funds advised and sub-advised by GSO Capital Partners LP and its affiliates (“GSO”) as GSO funds are majority lenders under our Second Lien Credit Facility and GSO funds hold an excess of ten-percent of our common shares.

NOTE 8 – COMMITMENTS AND CONTINGENCIES

Drilling Partnership Commitments

As of March 31, 2017, we are committed to expend approximately $11.2 million, principally on drilling and completion expenditures.

Environmental Matters

We and our subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our and our subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. We and our subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. We and our subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability as of March 31, 2017 and December 31, 2016.

Legal Proceedings

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

NOTE 9 – PREDECESSOR CASH DISTRIBUTIONS

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.

During the Predecessor three months ended March 31, 2016, our Predecessor paid three monthly cash distributions totaling approximately $3.8 million to its common limited partners ($0.0125 per unit per month); $1.9 million to its Preferred Class C limited partners ($0.17 per unit per month); and $0.1 million to its General Partner Class A holder ($0.0125 per unit per month).

During the Predecessor three months ended March 31, 2016, our Predecessor paid a distribution of $2.2 million to its Class D Preferred limited partners ($0.5390625 per unit) for the period October 15, 2015 through January 14, 2016. During the Predecessor three months ended March 31, 2016, our Predecessor paid a distribution of $0.2 million to its Class E Preferred limited partners ($0.671875 per unit) for the period October 15, 2015 through January 14, 2016.

NOTE 10 – OPERATING SEGMENT INFORMATION

Our operations include two reportable operating segments: gas and oil production and Drilling Partnership management. The Drilling Partnership management segment includes all of our managing and operating activities specific to the Drilling Partnerships including well construction and completion, administration and oversight, well services, and gathering and processing. These operating segments reflect the way we manage our operations and make business decisions.

We previously presented three reportable operating segments; however, due to the decline in investor capital funds raised in recent years, anticipated lower levels of future investor capital fund raise, and the consolidation of certain historical Drilling Partnerships in 2016, we aggregated our well construction and completion segment with our other partnership management segment to report all of our Drilling Partnership management activities in one combined segment as they do not meet the quantitative threshold for reporting individual segment information. As a result of this change, we have restated our prior year condensed consolidated statements of operations and segment footnote disclosures to conform to our current presentation.

Operating segment data for the periods indicated were as follows (in thousands):

	Successor			Predecessor
	Three Months Ended March 31,
	2017			2016
Gas and oil production:⁽¹⁾
Gas and oil production revenues	$	100,086		$	94,612
Gas and oil production costs		(29,987	)		(35,842	)
Depreciation, depletion and amortization		(16,013	)		(26,580	)
Segment income	$	54,086		$	32,190
Drilling partnership management:⁽²⁾
Drilling partnership management revenues	$	10,050		$	8,596
Drilling partnership management expenses		(8,171	)		(6,283	)
Depreciation, depletion and amortization		(479	)		(3,465	)
Segment income (loss)	$	1,400		$	(1,152	)
Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Gas and oil production	$	54,086		$	32,190
Drilling partnership management ⁽²⁾	1,400				(1,152	)
Total segment income (loss)		55,486			31,038
General and administrative expenses⁽³⁾		(13,758	)		(17,077	)
Interest expense⁽³⁾		(13,985	)		(27,705	)
Gain on early extinguishment of debt⁽³⁾		—			26,498
Other income (loss)⁽³⁾	(654		)		9
Income tax (provision) benefit⁽³⁾		(180	)		—
Net income	$	26,909		$	12,763
Reconciliation of segment revenues to total revenues:
Gas and oil production	$	100,086		$	94,612
Drilling partnership management	10,050				8,596
Total revenues	$	110,136		$	103,208
Capital expenditures:
Gas and oil production	$	9,913		$	11,945
Drilling partnership management	420				1,134
Corporate and other	111				91
Total capital expenditures	$	10,444		$	13,170

(1)	Includes gain on mark-to-market derivatives.

(2)	Includes revenues and expenses from our Drilling Partnership management activities, including well construction and completion, well services, gathering and processing, administration and oversight, that do not meet the quantitative threshold for reporting individual segment information.

(3)	General & administrative expenses, interest expense, gain on early extinguishment of debt, other income (loss) and income tax (provision) benefit have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented.


	March 31, 2017		December 31, 2016
Balance sheet:
Total assets:
Gas and oil production	$	811,895	$	819,454
Drilling partnership management	12,540			18,182
Corporate and other⁽¹⁾	54,803			44,198
Total assets	$	879,238	$	881,834

(1)

Corporate and other primarily consists of cash and cash equivalents, advances to affiliates and other assets, net, which have not been allocated to reportable segments.

NOTE 11 – SUBSEQUENT EVENTS

Appalachia Divestiture. On May 4, 2017, we entered into a definitive agreement to sell our conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC, for $84.2 million. The net proceeds will be used to repay a portion of outstanding borrowings under our First Lien Credit Facility. The transaction will significantly improve our First Lien Credit Facility metrics and is expected to fulfill our borrowing base step down to $360 million, which is scheduled to occur on August 31, 2017 (see Note 2).

ITEM 2:

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS OVERVIEW

ARP Restructuring and Emergence from Chapter 11 Proceedings

On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:

•

ARP’s second lien lenders received a pro rata share of our second lien exit facility credit agreement with an aggregate principal amount of $252.5 million (the “Second Lien Credit Facility”). In addition, ARP’s second lien lenders received a pro rata share of 10% of our common shares, subject to dilution by a management incentive plan.

•

all of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.

•

For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. We have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in our limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of us unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.

RECENT DEVELOPMENTS

Appalachia Divestiture

Liquidity, Capital Resources, and Ability to Continue as a Going Concern

On April 19, 2017, we entered into an amendment to our First Lien Credit Facility in an attempt to ameliorate some of our liquidity concerns. The amendment provides for, among other things, waivers of our non-compliance, increases in certain financial covenant ratios and scheduled decreases in our borrowing base (refer to Liquidity and Capital Resources – Credit Facilities section below for further information regarding the specific amended terms and provisions). In addition, we expect that we will sell a significant amount of non-core assets in the near future to comply with the requirements of our First Lien Credit Facility amendment and to attempt to enhance our liquidity.

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 and meeting our debt service obligations. 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 are evaluating various options, but there is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders. In addition, we expect that we will sell a significant amount of non-core assets in the near future to comply with the requirements of our first lien credit facility amendment and to attempt to enhance our liquidity.

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 and have continued to remain low in 2017. 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, and our ability to make payments on our debts, 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, results of operations, and cash flows on and after the Plan Effective Date are not comparable to our financial condition, results of operations, and cash flows prior to the Plan Effective Date. References to “Successor” relate to Titan on and subsequent to the Plan Effective Date. References to “Predecessor” refer to ARP prior to the Plan Effective Date. We have presented our financial condition, results of operations, and cash flows with a black line division to delineate the lack of comparability between the amounts presented on or after September 1, 2016 and dates prior.

Reclassifications. Certain reclassifications have been made to our condensed consolidated financial statements for the prior year periods to conform to classifications used in the current year, specifically related to our segment information on the condensed consolidated statement of operations and segment footnote disclosures.

Segments. Our operations include two reportable operating segments: gas and oil production and Drilling Partnership management. The Drilling Partnership management segment includes all of our managing and operating activities specific to the Drilling Partnerships including well construction and completion, administration and oversight, well services, and gathering and processing. These operating segments reflect the way we manage our operations and make business decisions.

GAS AND OIL PRODUCTION

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

•

the Eagle Ford Shale in south Texas, in which we acquired acreage and producing wells in November 2014;

•

Coalbed Methane producing natural gas assets in (1) the Raton Basin in northern New Mexico and southern Colorado, acquired in 2013; (2) the Black Warrior Basin in central Alabama, acquired in 2013; (3) the Central Appalachia Basin in West Virginia and Virginia, acquired in 2014, and; (4) the Arkoma Basin in eastern Oklahoma, acquired in 2015.

•

the Rangely field in northwest Colorado, a mature tertiary CO2 flood with low-decline oil production, where we have a 25% non-operated net working interest position which we acquired in 2014;

•

the Appalachia Basin assets, including the Marcellus Shale and the Utica Shale; the Chattanooga Shale in northeastern Tennessee, and the New Albany Shale in southwestern Indiana; and

•

the Mid-Continent assets, including Barnett Shale and Marble Falls plays, both in the Fort Worth Basin in northern Texas and acquired in 2012, the Mississippi Lime and Hunton plays in northwestern Oklahoma, and the Niobrara Shale in northeastern Colorado.

At March 31, 2017, we had a one-rig program actively drilling on our Eagle Ford Shale position. We anticipate increasing to a two-rig program during the year ending December 31, 2017.

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 periods indicated:

	Successor		Predecessor
	Three Months Ended March 31,
		2017		2016
Gross wells drilled⁽³⁾:
Eagle Ford		4		—
Net wells drilled⁽¹⁾⁽³⁾:
Eagle Ford		3		—
Gross wells turned in line⁽²⁾⁽³⁾:
Eagle Ford		—		—
Net wells turned in line^(1)(2)(3):
Eagle Ford		—		—

(1)	Includes (i) our percentage interest in the wells in which we have had a direct ownership interest and (ii) our percentage interest in the wells based on our percentage ownership in the Drilling Partnerships.

(2)	Wells turned in line refers to wells that have been drilled, completed, and connected to a gathering system.

(3)	There were no exploratory wells drilled during the periods presented. There were no gross or net dry wells within any of our operating areas during the periods presented.

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 each of the periods indicated:

	Successor	Predecessor
	Three Months Ended March 31,
	2017		2016
Production volumes per day:^{(1) (2)}
Eagle Ford:
Natural gas (Mcfd)	668		389
Oil (Bpd)	2,008		1,362
NGLs (Bpd)	146		81
Total (Mcfed)	13,589		9,049
Coalbed Methane:
Natural gas (Mcfd)	108,399		120,549
Oil (Bpd)	—		—
NGLs (Bpd)	—		—
Total (Mcfed)	108,399		120,549
Rangely:
Natural gas (Mcfd)	—		—
Oil (Bpd)	2,253		2,354
NGLs (Bpd)	245		256
Total (Mcfed)	14,987		15,657
Appalachia:
Natural gas (Mcfd)	40,615		31,545
Oil (Bpd)	300		295
NGLs (Bpd)	270		290
Total (Mcfed)	44,039		35,054
Mid-Continent:
Natural gas (Mcfd)	32,131		42,067
Oil (Bpd)	244		553
NGLs (Bpd)	1,259		1,882
Total (Mcfed)	41,149		56,674
Total production volumes per day:⁽²⁾
Natural gas (Mcfd)	181,813		194,550
Oil (Bpd)	4,804		4,563
NGLs (Bpd)	1,921		2,509
Total (Mcfed)	222,163		236,983
Total production:⁽²⁾
Natural gas (MMcf)	16,363		17,704
Oil (MBbls)	432		415
NGLs (MBbls)	173		228
Total (MMcfe)	19,995		21,565

(1)

Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the Drilling Partnerships in which we have an interest, based on our equity interest in each such Drilling Partnership and based on each Drilling Partnership’s proportionate net revenue interest in these wells.

(2)

“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately 6 Mcf to one barrel.

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, along with our average production costs, which include lease operating expenses, taxes, and transportation costs, for each of the periods indicated:

	Successor		Predecessor
	Three Months Ended March 31,
		2017		2016
Production revenues (in thousands):⁽¹⁾
Eagle Ford:
Natural gas revenue	$	186	$	90
Oil revenue		9,045		5,860
Natural gas liquids revenue		269		86
Total revenues		9,500		6,036
Coalbed Methane:
Natural gas revenue	$	29,665	$	23,839
Oil revenue		—		—
Natural gas liquids revenue		—		—
Total revenues	$	29,665	$	23,839
Rangely:
Natural gas revenue	$	—	$	—
Oil revenue		9,891		7,724
Natural gas liquids revenue		815		489
Total revenues	$	10,706	$	8,213
Appalachia:
Natural gas revenue	$	9,621	$	3,795
Oil revenue		1,340		1,201
Natural gas liquids revenue		352		25
Total revenues		11,313		5,021
Mid-Continent:
Natural gas revenue	$	6,379	$	4,928
Oil revenue		1,014		1,463
Natural gas liquids revenue		2,016		1,296
Total revenues	$	9,409	$	7,687
Total production revenues:⁽¹⁾
Natural gas revenue	$	45,851	$	31,284
Oil revenue		21,290		15,312
Natural gas liquids revenue		3,452		1,896
Total revenues	$	70,593	$	48,492
Average sales price:
Natural gas (per Mcf):
Total realized price, after hedge^{(2) (3)}	$	2.77	$	3.41
Total realized price, before hedge⁽³⁾	$	2.91	$	1.78
Oil (per Bbl):
Total realized price, after hedge⁽²⁾	$	45.85	$	77.16
Total realized price, before hedge	$	49.25	$	29.51
Natural gas liquids (per Bbl):
Total realized price, after hedge	$	19.97	$	8.31
Total realized price, before hedge	$	19.97	$	8.31
Production costs (per Mcfe):
Eagle Ford:
Lease operating expenses	$	1.15	$	1.75
Production taxes		0.45		0.38
Transportation		0.09		0.10
Total production costs (per Mcfe)	$	1.69	$	2.23
Coalbed Methane:
Lease operating expenses	$	0.96	$	1.02

	Successor		Predecessor
	Three Months Ended March 31,
Production taxes		0.26		0.16
Transportation		0.16		0.32
Total production costs (per Mcfe)	$	1.38	$	1.50
Rangely:
Lease operating expenses	$	4.29	$	4.36
Production taxes		0.52		0.56
Transportation		0.01		0.01
Total production costs (per Mcfe)	$	4.82	$	4.93
Appalachia:
Lease operating expenses⁽⁴⁾	$	0.59	$	0.84
Production taxes		0.03		0.06
Transportation		0.35		0.24
Total production costs (per Mcfe)⁽⁴⁾	$	0.97	$	1.14
Mid-Continent:
Lease operating expenses	$	0.94	$	1.07
Production taxes		0.16		0.15
Transportation		0.21		0.22
Total production costs (per Mcfe)	$	1.32	$	1.44
Total production costs:
Lease operating expenses⁽⁴⁾	$	1.12	$	1.25
Production taxes		0.23		0.18
Transportation		0.19		0.26
Total production costs (per Mcfe)⁽⁴⁾	$	1.54	$	1.69

(1)

For the Predecessor three months ended March 31, 2016, production revenue includes the portion of settlements associated with gains on commodity derivative contracts previously recognized within accumulated other comprehensive income following our Predecessor’s decision to de-designate hedges beginning on January 1, 2015, consisting of $0.4 million gain associated with natural gas derivative contracts and $3.1 million gain associated with crude oil derivative contracts for the Predecessor three months ended March 31, 2016.

(2)

For the Successor three months ended March 31, 2017, calculation includes the impact of cash settlements on commodity derivative contracts, consisting of $2.3 million in payments for natural gas derivative contracts and $1.5 million in payments for crude oil derivative contracts. For the Predecessor three months ended March 31, 2016, calculation includes the impact of cash settlements on commodity derivative contracts not previously included within accumulated other comprehensive income following our Predecessor’s decision to de-designate hedges beginning on January 1, 2015, consisting of $28.5 million in receipts associated with natural gas derivative contracts and $16.7 million in receipts associated with crude oil derivative contracts.

(3)

Calculation excludes the impact of subordination of our production revenue to investor partners within our Drilling Partnerships for each of the periods presented. Including the effect of this subordination, the average realized gas sales price was $2.66 per Mcf ($2.80 per Mcf before the effects of financial hedging) for the Successor period three months ended March 31, 2017 and $3.37 per Mcf ($1.74 per Mcf before the effects of financial hedging) for the Predecessor period three months ended March 31, 2016.

(4)

Excludes the effects of our proportionate share of lease operating expenses associated with subordination of our production revenue to investor partners within our Drilling Partnerships for each of the periods presented. Including the effects of these costs, Appalachia lease operating expenses were $0.39 per Mcfe ($0.78 per Mcfe for total production costs) and $0.66 per Mcfe ($0.97 per Mcfe for total production costs) for the Successor period three months ended March 31, 2017 and the Predecessor period three months ended March 31, 2016, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $1.08 per Mcfe ($1.50 per Mcfe for total production costs) and $1.23 per Mcfe ($1.66 per Mcfe for total production costs) for the Successor period three months ended March 31, 2017 and the Predecessor period three months ended March 31, 2016 respectively.

	Successor			Predecessor
	Three Months Ended March 31,
		2017			2016
(in thousands)
Gas and oil production revenues	$	70,593	$		48,492
Gas and oil production costs	$	29,987	$		35,842

Our gas and oil production revenues were higher in the current quarter due to an increase of $19.5 million due to higher average realized sales prices before hedging activities resulting from the improved commodity pricing environment, an increase of $4.0 million due to the consolidation of certain historical Drilling Partnerships in 2016, and an increase of $5.4 million due to 15 wells turned inline in our Eagle Ford operating area since the end of the first quarter 2016, partially offset by a decrease of $6.8 million due to lower production volumes resulting from natural decline and cost control operating decisions.

Our total production costs were lower in the current quarter due to a $4.1 million decrease in lease operating expenses related to lower labor costs from employee reductions and other production cost control measures in each of our operating areas, a $1.7 million decrease in transportation costs due to contract negotiations for lower rates, and a $0.6 million decrease in production taxes due to lower property taxes and production volumes partially offset by higher realized sales prices.

DRILLING PARTNERSHIP MANAGEMENT

We are a sponsor and manager of Drilling Partnerships in which we co-invest, to finance a portion of our drilling activities, and conduct certain energy activities through to support a portion of our natural gas, crude oil and natural gas liquids production activities and generate revenues as the manager and operator of the Drilling Partnerships. Drilling Partnership investor capital raised by us is deployed to drill and complete wells included within the partnership. As we deploy Drilling Partnership investor capital, we recognize certain management fees we are entitled to receive, including well construction and completion revenues and a portion of administration and oversight revenues. At each period end, if we have Drilling Partnership investor capital that has not yet been deployed, we recognize a current liability titled “Liabilities Associated with Drilling Contracts” on our condensed consolidated balance sheet. After the Drilling Partnership well is completed and turned in line, we are entitled to receive additional well services and operating fee revenues, administration and oversight fee revenues, and gathering and processing fee revenues on a monthly basis while the well is operating and as the services are performed. In addition, we are also entitled to our pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximates 10-30%, which is recognized in our gas and oil production segment.

	Successor			Predecessor
	Three Months Ended March 31,
		2017			2016

Drilling partnership management revenues	$	10,050	$		8,596
Drilling partnership management expenses	$	8,171	$		6,283

Drilling partnership management revenues. Our Drilling partnership management revenues were higher in the current quarter due to an increase of $2.8 million in well construction and completion revenues related to the timing of drilling and completion activities for the partnership wells, which is recognized on a cost plus basis, and $0.4 million higher gathering and processing revenues due to fewer wells shut in and increased natural gas production for the Drilling Partnerships, partially offset by $2.0 million lower well services and operating revenues due to the consolidation of a significant portion of the Drilling Partnerships in the second and fourth quarters of 2016, which lowered the number of wells we charge services and operating fees.

At March 31, 2017, our condensed consolidated balance sheet includes $5.8 million of “liabilities associated with well drilling contracts” for funds raised by our Drilling Partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our condensed consolidated statement of operations. We expect to recognize this amount as revenue during 2017.

Drilling partnership management expenses. Our Drilling partnership management expenses were lower in the current quarter due to a decrease of $2.4 million in well construction and completion expenses related to the timing of drilling and completion activities for the partnership wells, which is recognized on a percentage of completion basis, partially offset by $0.7 million lower well services and operating expenses due to the consolidation of a significant portion of the Drilling Partnerships in the second and fourth quarters of 2016, which lowered the labor and vehicle costs incurred to service and operate such wells.

OTHER REVENUES AND EXPENSES

	Successor			Predecessor
	Three Months Ended March 31,
		2017				2016
(in thousands)
Other Revenues
Gain on mark-to-market derivatives	$	29,493			$	46,120
Other Expenses
General and administrative	$	13,758			$	17,077
Depreciation, depletion and amortization		16,492				30,045
Interest expense		13,985				27,705
Gain on extinguishment of debt		—				26,498
Other income (loss)		(654	)			9
Income tax provision (benefit)		180				—

Gain on Mark-to-Market Derivatives. We recognize changes in the fair value of our derivatives immediately within gain on mark-to-market derivatives on our condensed consolidated statements of operations. The gains on mark-to-market derivatives during the Successor three months ended March 31, 2017 and the Predecessor period three months ended March 31, 2016 were due to decreases in commodity future prices relative to our and our Predecessor’s derivative positions as of the respective prior year end.

General and Administrative. Our general and administrative expenses were lower in the current quarter due to a $1.7 million decrease in syndication expenses related to lower investment partnership program fundraising activities and employee reductions in 2017, a $1.6 million decrease in salaries and benefits expenses related to employee reductions in 2016, and $0.6 million decrease due to cost control measures implemented, partially offset by a $0.5 million increase in non-cash stock compensation.

Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization expenses were lower in the current quarter due to a $10.8 million decrease in depletion expense and a $2.8 million decrease as a result of the application of fresh-start accounting to our proved gas and oil properties on September 1, 2016.

Interest Expense. Interest expense during the Successor three months ended March 31, 2017 primarily consisted of $5.5 million related to our First Lien Credit Facility, $7.9 million related to our Second Lien Credit Facility, and $0.7 million related to amortization of deferred financing costs. Interest expense during the Predecessor three months ended March 31, 2016 consisted of $14.4 million related to our Predecessor’s senior notes, $5.3 million related to our Predecessor’s first lien credit facility, $6.3 million related to our Predecessor’s second lien term loan, $4.1 related to amortization of deferred financing costs and debt discounts, partially offset by $2.4 million in capitalized interest.

Gain on Early Extinguishment of Debt. The gain on early extinguishment of debt for the Predecessor three months ended March 31, 2016 represents a $26.5 million gain related to the repurchase of a portion of our Predecessor’s 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.

Other Income (Loss). The $0.7 million of loss for the Successor three months ended March 31, 2017 represents a $0.8 million write off of receivables from our Drilling Partnerships and a $0.2 million loss on sale of assets in our Mid-Continent operating area, partially offset by a $0.4 million sale of inventory in our Coalbed methane operating area.

Income Tax Provision (Benefit). For the Successor period three months ended March 31, 2017, we recorded a full valuation allowance against our net 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. Our effective tax rate for the three months ended March 31, 2017 was 0.6%, which represents our expected Texas Franchise Tax liability. Our income tax provision differs from the provision computed by applying the U.S. Federal statutory corporate income tax rate of 35% primarily due to the valuation allowance on our deferred tax assets.

LIQUIDITY AND CAPITAL RESOURCES

General

On April 19, 2017, we entered into an amendment to our First Lien Credit Facility in an attempt to ameliorate some of our liquidity concerns. The amendment provides for, among other things, waivers of our non-compliance, increases in certain financial covenant ratios and scheduled decreases in our borrowing base. In addition, we expect that we will sell a significant amount of non-core assets in the near future to comply with the requirements of our First Lien Credit Facility amendment and to attempt to enhance our liquidity.

price of our securities. Additionally, there can be no assurance that the above actions would allow us to meet our debt obligations and capital requirements.

Appalachia Divestiture

Cash Flows

	Successor			Predecessor
	Three Months Ended March 31,
		2017			2016
Net cash provided by (used in) operating activities	$	15,350		$	(34,919	)
Net cash used in investing activities		(10,444	)		(13,170	)
Net cash provided by (used in) financing activities		(386	)		66,021

Cash Flows From Operating Activities:

The increase in cash flows provided by operating activities was primarily due to:

•

an increase of $31.7 million net cash provided by operating activities for cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production and Drilling Partnership management revenues, and collections net of payments for royalties, lease operating expenses, gathering, processing and transportation expenses, severance taxes, Drilling Partnership management expenses, and general and administrative expenses;

•

a decrease of $34.3 million of cash paid for interest due to a decrease of $29 million and $5 million in cash paid for interest related to our Predecessor’s senior notes and second lien term loan, respectively, as a result of the Plan; and

•

a decrease of $36.7 million of investor capital raised transferred by our Predecessor to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program; partially offset by

•

a decrease of $52.5 million of cash settlement receipts on commodity derivative contracts.

Cash Flows From Investing Activities:

The decrease in cash flows used in investing activities was due to a $2.7 million decrease in capital expenditures related to the timing and costs our drilling activities.

Cash Flows From Financing Activities:

The change in cash flows from financing activities was primarily due to:

•

a decrease of $80 million in net borrowings under our Predecessor’s revolving credit facility; partially offset by

•

a decrease of $8.2 million in distributions paid to our Predecessor’s unitholders; and

•

a decrease $5.5 million related to our Predecessor’s senior note repurchases.

Capital Requirements

At March 31, 2017, 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.

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 March 31, 2017, we are committed to expend approximately $11.2 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

There have been no material changes to our off balance sheet arrangements from those disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

There have been no material changes to our contractual obligations and commercial commitments from those disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, except for our well drilling and completion commitments is $10.6 million as of March 31, 2017 as compared to $19.4 million as of December 31, 2016.

CREDIT FACILITIES

First Lien Credit Facility

•

Borrowing base of a $410 million conforming reserve based tranche plus a $30 million non-conforming tranche.

•

Provides for the issuance of letters of credit, which reduce borrowing capacity.

•

Requires us to enter into commodity hedges covering at least 80% of our expected 2019 production prior to December 31, 2017.

We were not in compliance with certain of the financial covenants under our credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. On April 19, 2017, we, Titan Energy Operating, LLC (our wholly owned subsidiary), as borrower, and certain subsidiary guarantors entered into a Third Amendment (the “First Lien Credit Facility Amendment”) to the First Lien Credit Facility with Wells Fargo, as administrative agent, and the lenders party thereto. Pursuant to the First Lien Credit Facility Amendment, certain of the financial ratio covenants were revised upwards. Specifically, beginning December 31, 2017, we will be required to maintain a ratio of Total Debt to EBITDA (each as defined in the First Lien Credit Facility) of not more than 5.50 to 1.00 for each fiscal quarter through December 31, 2018 and of not more than 5.00 to 1.00 thereafter. We will also be required, beginning December 31, 2017, to maintain a ratio of First Lien Debt (as defined in the First Lien Credit Facility) to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter through December 31, 2018 and of not more than 3.50 to 1.00 thereafter.

In addition to the amendments to the financial ratio covenants, the First Lien Credit Facility lenders waived certain defaults by us with respect to the fourth quarter of 2016, including compliance with the ratios of Total Debt to EBITDA and First Lien Debt to EBITDA, as well as our obligation to deliver financial statements without a “going concern” qualification. The First Lien Credit Facility lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to our second lien credit facility), the failure to extend the 180-day standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the First Lien Credit Facility.

Second Lien Credit Facility

•

All prepayments are subject to the following premiums, plus accrued and unpaid interest:

•

4.5% of the principal amount prepaid for prepayments prior to February 23, 2017;

•

2.25% of the principal amount prepaid for prepayments on or after February 23, 2017 and prior to February 23, 2018; and

•

no premium for prepayments on or after February 23, 2018.

•

Requires us to maintain certain financial ratios (the financial ratios will use an annualized EBITDA measurement for periods prior to June 30, 2017):

•

EBITDA to Interest Expense (each as defined in the Second Lien Credit Facility) of not less than 2.50 to 1.00;

•

Total Leverage Ratio (as defined in the Second Lien Credit Facility) of no greater than 5.5 to 1.0 prior to December 31, 2017 and no greater than 5.0 to 1.0 thereafter; and

•

Current assets to current liabilities (each as defined in the Second Lien Credit Facility) of not less than 1.0 to 1.0.

On April 21, 2017, the lenders under the our Second Lien Credit Facility delivered a notice, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the 180-day standstill period under the intercreditor agreement, during which the lenders under the Second Lien Credit Facility are prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility. The lenders have not accelerated the payment of amounts outstanding under the Second Lien Credit Facility.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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, 2016.

Recently Issued Accounting Standards

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

ITEM 3:

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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.

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 as if the hypothetical changes in market risk factors occurred on March 31, 2017. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.

Interest Rate Risk. At March 31, 2017, $435.8 million was outstanding under our First Lien Credit Facility and $267.7 million was outstanding under our Second Lien Credit Facility. Holding all other variables constant, a hypothetical 1% change in variable interest rates would change our condensed consolidated interest expense for the twelve-month period ending March 31, 2018 by approximately $7.0 million.

Commodity Price Risk. 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 condensed consolidated operating income for the twelve-month period ending March 31, 2018 of approximately $6.2 million.

At March 31, 2017, we had the following commodity derivatives:

Type	Production Period Ending December 31,		Volumes⁽¹⁾		Average Fixed Price⁽¹⁾
Natural Gas – Fixed Price Swaps		2017⁽²⁾		38,759,800	$	3.140
		2018		47,559,300	$	2.959

Crude Oil – Fixed Price Swaps		2017⁽²⁾		891,500	$	46.971
		2018		1,011,100	$	49.544

(1)

Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels.

(2)

The production volumes for 2017 include the remaining nine months of 2017 beginning April 1, 2017.

ITEM 4:

CONTROLS AND PROCEDURES

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 March 31, 2017, 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

ITEM 6:

EXHIBITS

Exhibit Number		Description of Exhibit

3.1(a)		Certification of Conversion of Titan Energy, LLC (incorporated by reference to Exhibit 3.1(a) to our Registration Statement on Form S-1 (File No. 333-214850) filed on November 30, 2016)\|

3.1(b)		Certificate of Formation of Titan Energy, LLC (incorporated by reference to Exhibit 3.1(b) to our Registration Statement on Form S-1 (File No. 333-214850) filed on November 30, 2016)

3.2		Amended and Restated Limited Liability Company Agreement of Titan Energy, LLC, dated as of September 1, 2016 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed September 7, 2016)

10.1		First Amendment to Third Amended and Restated Credit Agreement, dated as of March 24, 2017, among Titan Energy Operating, LLC, as borrower, Titan Energy, LLC, as parent, the subsidiary guarantors party thereto, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed March 30, 2017)

10.2		Second Amendment to Third Amended and Restated Credit Agreement, dated as of April 10, 2017, among Titan Energy Operating, LLC, as borrower, Titan Energy, LLC, as parent, the subsidiary guarantors party thereto, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1(c) to our Post-Effective Amendment No. 1 to Registration Statement on Form S-1 filed May 1, 2017)

Exhibit Number		Description of Exhibit
10.3		Third Amendment to Third Amended and Restated Credit Agreement, dated as of April 19, 2017, among Titan Energy Operating, LLC, as borrower, Titan Energy, LLC, as parent, the subsidiary guarantors party thereto, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed April 21, 2017)

10.4		First Amendment to Amended and Restated Second Lien Credit Agreement, dated as of March 27, 2017, among Titan Energy Operating, LLC, as borrower, Titan Energy, LLC, as parent, the subsidiary guarantors party thereto, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed March 30, 2017)

10.5		Second Amendment to Amended and Restated Second Lien Credit Agreement, dated as of April 10, 2017, among Titan Energy Operating, LLC, as borrower, Titan Energy, LLC, as parent, the subsidiary guarantors party thereto, and the lenders party thereto (incorporated by reference to Exhibit 10.2(c) to our Post-Effective Amendment No. 1 to Registration Statement on Form S-1 filed May 1, 2017)

31.1*		Rule 13(a)-14(a)/15(d)-14(a) Certification

31.2*		Rule 13(a)-14(a)/15(d)-14(a) Certification

32.1*		Section 1350 Certification

32.2*		Section 1350 Certification

101.INS**		XBRL Instance Document

101.SCH**		XBRL Schema Document

101.CAL**		XBRL Calculation Linkbase Document

101.LAB**		XBRL Label Linkbase Document

101.PRE**		XBRL Presentation Linkbase Document

101.DEF**		XBRL Definition Linkbase Document

*	Provided herewith.

**	Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

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.

	TITAN ENERGY, LLC

Date: May 15, 2017	By:	/s/ Daniel C. Herz
		Daniel C. Herz
		Chief Executive Officer and Director

Date: May 15, 2017	By:	/s/ Jeffrey M. Slotterback
		Jeffrey M. Slotterback
		Chief Financial Officer

Date: May 15, 2017	By:	/s/ Matthew J. Finkbeiner
		Matthew J. Finkbeiner
		Chief Accounting Officer