Edgar Filing: Titan Energy, LLC

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

424B3

Filed pursuant to Rule 424(b)(3)
Registration No. 333-214850

PROSPECTUS SUPPLEMENT NO. 2

(to Prospectus dated May 11, 2017)

LOGO

Titan Energy, LLC

3,266,936 Common Shares

Representing Limited Liability Company Interests

This prospectus supplement is being filed to update and supplement information contained in the prospectus dated May 11, 2017 with information contained in (i) our Current Report on Form 8-K, filed with the Securities and Exchange Commission (the “SEC”) on August 11, 2017 and (ii) our Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, filed with the SEC on August 21, 2017.

This prospectus supplement updates and supplements the information in the prospectus and is not complete without, and may not be delivered or utilized except in combination with, the prospectus, including any other amendments or supplements thereto. This prospectus supplement should be read in conjunction with the prospectus and if there is any inconsistency between the information in the prospectus and this prospectus supplement, you should rely on the information in this prospectus supplement.

Investing in our Common Shares involves risks. Please read “Risk Factors” beginning on page 3 of the prospectus.

Neither the SEC nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus supplement is August 23, 2017

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): August 7, 2017

Titan Energy, LLC

(Exact name of registrant specified in its charter)

Delaware

001-35317

90-0812516

(State or Other Jurisdiction

Of Incorporation)

(Commission

File Number)

(IRS 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

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

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. ☐

Item 2.01

Completion of Acquisition or Disposition of Assets

On June 12, 2017, ARP Rangely Production, LLC, a wholly owned subsidiary of Titan Energy, LLC (the “Company”), entered into a purchase and sale agreement with MMGJ Colorado, LLC, an affiliate of Merit Energy Company, LLC (the “Agreement”). Pursuant to the Agreement, the Company agreed to sell its 25% interest in the Rangely Field, a CO₂ flood located in Rio Blanco County, Colorado and operated by Chevron, as well as its 22% interest in Raven Ridge Pipeline, a CO₂ transportation line, and surrounding acreage in Rio Blanco and Moffat Counties, Colorado (collectively, the “Rangely Assets”). The Agreement provided for aggregate consideration of $105 million. On August 7, 2017, the Company completed the sale of the Rangely Assets for net cash proceeds of $103.5 million, after giving effect to customary preliminary purchase price adjustments.

The foregoing summary of the Agreement does not purport to be complete and is subject to, and qualified in its entirety by reference to, the full text of the Agreement, which is filed as Exhibit 2.1 to this Current Report on Form 8-K.

Item 9.01

Financial Statements and Exhibits

(b) Pro Forma Financial Information

The unaudited pro forma consolidated balance sheet of the Company as of March 31, 2017, and the related pro forma consolidated statements of operations for the three months ended March 31, 2017 and the years ended December 31, 2016, 2015 and 2014 are filed as Exhibit 99.1 to this Current Report on Form 8-K and are incorporated by reference herein.

(d) Exhibits


Exhibit Number		Description

2.1		Purchase and Sale Agreement by and between ARP Rangely Production, LLC and MMGJ Colorado, LLC, dated June 12, 2017.*

99.1		Unaudited pro forma financial information.

*	The registrant has omitted certain immaterial schedules and exhibits to this exhibit pursuant to the provisions of Regulation S-K, Item 601(b)(2). The registrant will furnish a copy of any of the omitted schedules and exhibits to the Securities and Exchange Commission upon request.

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 hereunto duly authorized.


Dated: August 11, 2017	TITAN ENERGY, LLC

	By:	/s/ Jeffrey M. Slotterback
		Name:	Jeffrey M. Slotterback
		Title:	Chief Financial Officer

EXHIBIT INDEX


Exhibit Number		Description

2.1		Purchase and Sale Agreement by and between ARP Rangely Production, LLC and MMGJ Colorado, LLC, dated June 12, 2017.*

99.1		Unaudited pro forma financial information.

*	The registrant has omitted certain immaterial schedules and exhibits to this exhibit pursuant to the provisions of Regulation S-K, Item 601(b)(2). The registrant will furnish a copy of any of the omitted schedules and exhibits to the Securities and Exchange Commission upon request.

Exhibit 2.1

Execution Version

PURCHASE AND SALE AGREEMENT

ARP RANGELY PRODUCTION, LLC

(“Seller”)

and

MMGJ COLORADO, LLC

(“Buyer”)

June 12, 2017

PURCHASE AND SALE AGREEMENT

TABLE OF CONTENTS


		Page
ARTICLE 1	DEFINITIONS		1

ARTICLE 2	SALE AND PURCHASE OF PROPERTIES; EXCLUDED ASSETS		14
2.1	Sale and Purchase of Properties		14
2.2	Excluded Assets		16
2.3	Assumed Liabilities and Seller’s Retained Liabilities		17

ARTICLE 3	PURCHASE PRICE		18
3.1	Purchase Price; Deposit		18
3.2	Increases in Purchase Price		18
3.3	Decreases in Purchase Price		19

ARTICLE 4	TITLE MATTERS		19
4.1	Review of Title Records		19
4.2	Title Defect Notice		20
4.3	Seller’s Right to Cure Title Defects		20
4.4	Remedies for Title Defects		20
4.5	Exclusive Remedy		21
4.6	Calculation of Title Defect Value		21
4.7	Title Defect Dispute Resolution		22
4.8	Possible Upward Adjustment		23
4.9	Delayed Closing		23

ARTICLE 5	PREFERENTIAL RIGHTS AND CONSENTS		24
5.1	Preferential Rights to Purchase		24
5.2	Transfer Requirements other than Preferential Rights to Purchase		24
5.3	Delayed Closing		25

ARTICLE 6	ENVIRONMENTAL MATTERS		25
6.1	Environmental Assessment		25
6.2	Notice of Environmental Condition		26
6.3	Seller’s Right to Cure Environmental Conditions		26
6.4	Remedies for Environmental Conditions		26
6.5	Exclusive Remedy		27
6.6	Environmental Condition Dispute Resolution		27
6.7	Delayed Closing		28
6.8	Presence of Wastes, NORM, Hazardous Substances and Asbestos		28

ARTICLE 7	REPRESENTATIONS AND WARRANTIES OF SELLER		29
7.1	Organization		29
7.2	Authority		29
7.3	Enforceability		29
7.4	No Conflict		29

TABLE OF CONTENTS

(continued)


		Page
7.5	Transfer Requirements		30
7.6	Compliance with Laws		30
7.7	Certain Environmental Notices and Obligations		30
7.8	Litigation and Claims		30
7.9	Material Contracts		31
7.10	Governmental Permits		32
7.11	Payment of Royalties; Suspense Funds		32
7.12	Imbalances		32
7.13	Non-Consent Operations		32
7.14	Current Commitments		32
7.15	Taxes		32
7.16	Finder’s Fees		33
7.17	Operation of the Properties		33
7.18	Title to Facilities		33
7.19	Guarantees		33
7.20	Knowledge Qualifier for Non-Operated Assets		33

ARTICLE 8	REPRESENTATIONS AND WARRANTIES OF BUYER		33
8.1	Organization		33
8.2	Authority		33
8.3	Enforceability		34
8.4	No Conflicts		34
8.5	No Further Distribution		34
8.6	Finder’s Fees		34
8.7	Independent Evaluation		34

ARTICLE 9	COVENANTS OF THE PARTIES		34
9.1	Access		34
9.2	Conduct of Business Pending Closing		35
9.3	Consents and Approvals		36
9.4	Confidentiality		36
9.5	Public Announcements		36
9.6	Affiliate Contracts		37
9.7	Satisfaction of Conditions		37
9.8	Successor Operator		37
9.9	Replacement of Bonds		37
9.10	Amendment of Schedules		37

ARTICLE 10	CASUALTY LOSS		38
10.1	Notice of Casualty Loss Prior to Closing		38
10.2	Casualty Loss		38

ARTICLE 11	[RESERVED]		38

TABLE OF CONTENTS

(continued)


		Page
ARTICLE 12	CONDITIONS PRECEDENT TO THE OBLIGATIONS OF SELLER		39
12.1	Representations and Warranties		39
12.2	Covenants		39
12.3	No Litigation, Orders or Laws		39
12.4	Right to Terminate		39

ARTICLE 13	CONDITIONS PRECEDENT TO THE OBLIGATIONS OF BUYER		39
13.1	Representations and Warranties		39
13.2	Covenants		39
13.3	No Litigation, Orders or Laws		39
13.4	Right to Terminate		40

ARTICLE 14	CLOSING		40
14.1	The Closing		40
14.2	Closing Deliveries		40

ARTICLE 15	TERMINATION AND REMEDIES		42
15.1	Termination		42
15.2	Notice of Termination		43
15.3	Effect of Termination		43

ARTICLE 16	ACCOUNTING MATTERS		44
16.1	Preliminary Settlement Statement		44
16.2	Final Settlement Statement		44
16.3	Post-Closing Revenues		45
16.4	Post-Closing Expenses		45
16.5	Audits		46

ARTICLE 17	CERTAIN POST-CLOSING COVENANTS		46
17.1	Further Assurances		46
17.2	Delivery of Records by Seller		47
17.3	Use of Seller’s Name		47
17.4	Suspense Funds		47

ARTICLE 18	INDEMNIFICATION		47
18.1	Seller’s Indemnity		47
18.2	Limitations on Seller’s Indemnity		48
18.3	Survival of Seller’s Representations and Warranties		49
18.4	Buyer’s Indemnity		49
18.5	Limitations of Warranties		49
18.6	Notice of Claims		50
18.7	Defense of Claims		50
18.8	Specific Performance; Scope of Remedies		51
18.9	Extent of Indemnification		51
18.10	Tax Treatment of Indemnification Payments		52

iii

TABLE OF CONTENTS

(continued)


		Page
ARTICLE 19	TAXATION		52
19.1	Responsible Party		52
19.2	Transfer Taxes		52
19.3	Allocation of Values		53
19.4	Tax Contests		53

ARTICLE 20	MISCELLANEOUS		53
20.1	Notice		53
20.2	Governing Law		54
20.3	Assignment		54
20.4	Entire Agreement		55
20.5	Amendment; Waiver		55
20.6	Severability		55
20.7	Construction		55
20.8	Headings		56
20.9	Counterparts		56
20.10	Expenses and Fees		56
20.11	Limitation on Damages		56
20.12	Third Party Beneficiaries		56
20.13	Survival of Certain Obligations		57
20.14	Bulk Transfer Laws		57
20.15	Schedules		57
20.16	Conspicuousness		57


EXHIBITS AND SCHEDULES:

Exhibit A-1		Leases and Royalty Interests; Fee Interests
Exhibit A-2		Wells and Units
Exhibit A-3		Surface Interests
Exhibit A-4		Facilities
Exhibit B		Working Interest/Net Revenue Interest; Allocated Values
Exhibit C		Form of Conveyance
Exhibit D		Form of Non-foreign Affidavit

Schedule 1		Individuals with “Knowledge”
Schedule 2.2.9		Excluded Assets
Schedule 7.5		Consents and Preferential Rights
Schedule 7.7		Environmental NOVs and Agreed Orders
Schedule 7.8		Litigation
Schedule 7.9		Material Contracts
Schedule 7.11		Royalties; Suspense Funds
Schedule 7.14(a)		Approved Current Commitments
Schedule 7.14(b)		Rejected Current Commitments
Schedule 7.19		Guarantees
Schedule 9.2.8		Insurance
Schedule 9.6		Affiliate Contracts

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (this “Agreement”) is made and entered into on June 12, 2017, by and between ARP Rangely Production, LLC, a Delaware limited liability company (“Seller”) and MMGJ Colorado, LLC, a Delaware limited liability company (“Buyer”).

WHEREAS, Seller desires to sell to Buyer, and Buyer desires to purchase from Seller, the Properties (as defined below) on the terms and conditions set forth herein;

NOW, THEREFORE, based on and in consideration of the mutual covenants and agreements contained herein, the Parties agree as follows:

ARTICLE 1

DEFINITIONS

When used in this Agreement, the following terms have the following meanings (other defined terms may be found elsewhere in this Agreement):

“Affiliate” means when used with respect to any Person, any other Person that, directly or indirectly, Controls, is Controlled by, or is under common Control with, such Person in question.

“Agreement” is defined in the preamble.

“Allocated Value” means, with respect to any Property, the value allocated to Seller’s interest in such Property as set forth on Exhibit B.

“Assignment Premiums” is defined in Section 9.3.4.

“Assumed Liabilities” is defined in Section 2.3.1.

“BIA” means the U.S. Bureau of Indian Affairs.

“BLM” means the U.S. Bureau of Land Management.

“Business Day” means each Monday, Tuesday, Wednesday, Thursday and Friday which is not a day on which banks in Houston, Texas are generally authorized or obligated, by law or executive order, to close.

“Buyer” is defined in the preamble.

“Buyer Group” means Buyer, its Affiliates and its and their respective employees, officers, directors, managers, agents, consultants and representatives.

“Casualty Loss” is defined in Section 10.1.

“Claim” means any and all actual out-of-pocket losses, damages, Liabilities, claims, demands, suits, causes of action, fines, penalties, costs and expenses (including reasonable attorneys’ fees and costs of litigation, arbitration and settlements), whether known or unknown.

“Claim Notice” is defined in Section 18.6.

“Closing” is defined in Section 14.1.

“Closing Date” is defined in Section 14.1.

“Closing Purchase Price” means the Purchase Price determined in accordance with Article 3 and Section 16.1.

“Code” means Internal Revenue Code of 1986, or any successor statute thereto, as amended.

“Commercially Reasonable Efforts” means, as to a Person, the commercially reasonable efforts of such Person without the obligation to pursue any litigation or other proceedings or to pay or incur any material monetary payments; provided however, that the foregoing shall not require or cause any Party to (i) waive any right it may have under the provisions of this Agreement, (ii) grant any material accommodations or (iii) take or cause to be taken, or to do or cause to be done anything, contemplated by this Agreement to be taken or done or caused to be taken or done by the other Party.

“Confidentiality Agreement” is defined in Section 20.4.

“Contracts” is defined in Section 2.1.8.

“Control” means the ability to direct the management and policies of a Person through ownership of voting shares or other equity rights, pursuant to a written agreement, or otherwise. The terms “Controls” and “Controlled by” and other derivatives shall be construed accordingly.

“Conveyance” is defined in Section 14.2.1.

“Cure Period” is defined in Section 4.4.2.

“Defect Notification Deadline” is defined in Section 4.2.

“Deposit” is defined in Section 3.1.

“Dollars” means U.S. dollars.

“Effective Time” means 7:00 a.m. Houston time on May 1, 2017.

“Environmental Arbitrator” is defined in Section 6.6.2.

“Environmental Condition” means an individual existing condition of a Property or of the soil, sub-surface, surface waters, groundwaters, atmosphere, natural resources or other environmental medium, wherever located, exclusively associated with the ownership or

operation of the Properties (including the presence or release of waste, hazardous substances or Hydrocarbons), that (in each case) (i) is not in compliance with Environmental Laws and (ii) requires, if known, or will require, once discovered, investigation, monitoring, removal, cleanup, remediation, restoration or correction (including any monitoring, reporting or permitting, or any pollution control equipment installation and operation) in accordance with Environmental Laws.

“Environmental Condition Notice” is defined in Section 6.2.

“Environmental Condition Property” is defined in Section 6.2.

“Environmental Condition Removal” means any Environmental Condition Property excluded from this Agreement pursuant to Section 6.4.2 (subject to Seller’s right to cure set forth in Section 6.4.2) or Section 6.6.4.

“Environmental Defect Deductible” means an amount equal to $3,150,000.

“Environmental Laws” means all applicable Laws concerning or relating to (i) prevention of pollution or environmental damage, (ii) removal or remediation of pollution or environmental damage or (iii) protection of the environment (including natural resources) or workplace health or safety, including the Clean Air Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), the Federal Water Pollution Control Act, the Safe Drinking Water Act, the Toxic Substance Control Act, the Resource Conservation and Recovery Act, the Hazardous Materials Transportation Act, the National Environmental Policy Act, the Endangered Species Act, the Fish and Wildlife Coordination Act, the National Historic Preservation Act and the Oil Pollution Act of 1990, as such Laws may be amended from time to time.

“Equity Interests” means (i) any shares of capital stock, (ii) any membership interests or units, (iii) any partnership interests, (iv) any other interest or participation that confers on a Person the right to receive a unit of the profits and losses of, or distribution of assets of, the issuing entity, (v) any subscriptions, calls, warrants, options, or commitments of any kind or character relating to, or entitling any Person or entity to purchase or otherwise acquire membership interests or units, capital stock, or any other equity securities, (vi) any securities convertible into or exercisable or exchangeable for partnership interests, membership interests or units, capital stock, or any other equity securities or (vii) any other interest classified as an equity security of a Person.

“Escrow Agent” means Key Bank National Association.

“Escrow Agreement” means that certain Escrow Agreement of even date herewith, by and among Seller, Buyer and Escrow Agent.

“Escrow Funds” is defined in Section 3.1.

“Escrow Release” is defined in Section 3.1.

“Excluded Assets” is defined in Section 2.2.

“Facilities” is defined in Section 2.1.5.

“Fee Interests” is defined in Section 2.1.1.

“Final Purchase Price” means the Purchase Price determined in accordance with Article 3 and Section 16.2.

“Final Settlement Statement” is defined in Section 16.2.

“First PSA” means that certain Purchase and Sale Agreement by and among Merit Management Partners I, L.P., et al., as Seller, and ARP Rangely Production, LLC, as Buyer, executed May 6, 2014.

“First PSA Properties” means the Properties (other than Wells), each as defined in the First PSA.

“GAAP” means United States generally accepted accounting principles.

“Good and Defensible Title” means:

(i) with respect to those certain Properties described on Exhibit B, title as of the date hereof and as of the Closing Date that:

(a) is free and clear of all liens, charges, obligations, defects and encumbrances, except for Permitted Encumbrances (other than Permitted Encumbrances that consist of consents and approvals set forth on Schedule 7.5, unless and until such consents and approvals are obtained);

(b) entitles Seller to receive not less than the Net Revenue Interest set forth in Exhibit B in all Hydrocarbons produced from the Properties described in Exhibit A without reduction at any time during the productive life thereof except decreases resulting from operations where Seller is a non-consenting party and decreases required to allow other working interest owners to make up past underproduction or pipelines to make up past under deliveries; and

(c) obligates Seller to bear not more than the Working Interest set forth in Exhibit B in the Properties described in Exhibit A without increase at any time during the productive life or abandonment thereof unless there is a corresponding proportionate increase in the applicable Net Revenue Interest; or

(ii) with respect to all other Properties not described on Exhibit B, title that:

(a) is good title and free and clear of all liens, charges, obligations, defects and encumbrances, except for Permitted Encumbrances; and

(b) with respect to such Properties that are Fee Interests, is perpetual and not subject to limited term or reversion, except as set forth on Exhibit A.

Notwithstanding anything else herein, the Parties will not treat title to a Property affected or burdened by a sliding-scale royalty as less than Good and Defensible Title as a result of the effect of any such royalty on Seller’s Net Revenue Interest in the affected Property.

“Governmental Authority” means any federal, state, local, municipal, tribal, arbitral or other government, any governmental, regulatory or administrative agency, arbitral panel, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or Taxing authority or power, or any court or government tribunal.

“Hydrocarbons” means oil, gas, natural gas liquids, condensate, casinghead gas and other liquid or gaseous hydrocarbons (or any combination or constituents thereof), any other minerals of every kind or character.

“Imbalances” means over-production or under-production subject to an imbalance or make-up obligation with respect to Hydrocarbons produced from or allocated to the Properties, regardless of whether such over-production or under-production, imbalance or make-up obligation arises at the platform, wellhead, pipeline, gathering system, transportation or other location and regardless of whether the same arises under contract or by operation of Law.

“Indebtedness” means, with respect to any Person, without duplication: (i) indebtedness for borrowed money; (ii) indebtedness for borrowed money of any other Person guaranteed in any manner by such Person; and (iii) obligations of such Person as lessee under leases which are required to be capitalized in accordance with GAAP, as obligor or guarantor.

“Indemnified Party” is defined in Section 18.6.

“Indemnifying Party” is defined in Section 18.6.

“Independent Accounting Firm” means PricewaterhouseCoopers, or if such Independent Accounting Firm is unavailable, such other nationally recognized independent public accounting firm as may be mutually agreed by the Parties; provided, that, if the Parties cannot agree within five Business Days of such notice of unavailability on a single accounting firm to serve as the Independent Accounting Firm, then Seller and Buyer will each nominate a nationally recognized accounting firm, and both such Buyer and Seller nominated accounting firms shall select a third, nationally recognized accounting firm to serve as the Independent Accounting Firm.

“Knowledge” (or “known” or other derivatives thereof) means, whether or not capitalized, (i) with respect to Seller, the actual knowledge of any of the individuals listed in Subpart 1 of Schedule 1, and (ii) with respect to Buyer, the actual knowledge of any of the individuals listed in Subpart 2 of Schedule 1.

“Lands” is defined in Section 2.1.2.

“Laws” means any and all laws, statutes, codes, ordinances, permits, licenses, authorizations, agreements, decrees, writs, orders, awards, judgments, principles of common law, rules or regulations (including, for the avoidance of doubt, Environmental Laws) that are promulgated, issued or enacted by a Governmental Authority having jurisdiction.

“Lease” and “Leases” is defined in Section 2.1.2.

“Lease Burdens” means royalties, overriding royalties, sliding scale royalties, production payments, reversionary interests, convertible interests, net profits interests and similar burdens.

“Liabilities” means all liabilities or obligations of any kind or character (whether absolute, accrued, contingent, fixed, known, unknown or otherwise, or whether due or to become due).

“Material Adverse Effect” means an event, effect or circumstance that, individually or in the aggregate, does or would reasonably be expected to have a material adverse effect on (i) the ownership, operations or value of the Properties, taken as a whole or (ii) the ability of Seller to consummate the transactions contemplated by this Agreement; provided, however, that, for the purpose of clause (i) hereof, none of the following shall be deemed to constitute a Material Adverse Effect: (1) any effect resulting from changes in generally applicable market, economic, financial or political conditions (including changes in fuel supply or transportation markets) in the United States or worldwide, or any outbreak of hostilities, war or terrorist acts; (2) any effect resulting from any changes in the prices of Hydrocarbons; (3) any effect resulting from entering into this Agreement or the announcement of the transactions contemplated herein; (4) acts of God, including storms, drought or meteorological events; (5) acts or failures to act of Governmental Authorities or a change in Laws from and after the date of this Agreement; (6) matters that are cured or no longer exist by the earlier of the Closing and the termination of this Agreement, without cost or liability to Buyer; (7) reclassification or recalculation of reserves in the ordinary course of business consistent with past practice; or (8) declines in well performance due to natural causes, except in the cases of clauses (1), (4) and (5), to the extent disproportionately affecting the Properties as a whole as compared with other Persons or businesses in the oil and gas exploration and production industry generally and then only such disproportionate impact shall be considered.

“Material Contracts” is defined in Section 7.9.1.

“Minimal Defect” means (i) any individual Title Defect with a Title Defect Value of less than $200,000 or (ii) any individual Environmental Condition with a Remediation Amount of less than $200,000.

“Net Reduction of Interest” means (i) a reduction of Seller’s Net Revenue Interest in a Property described in Exhibit A at any time during the productive life thereof, below the Net Revenue Interest for such Property set forth in Exhibit B, except decreases resulting from operations where Seller is a non-consenting party and decreases required to allow other working interest owners to make up past underproduction or pipelines to make up past under deliveries, or (ii) an increase in Seller’s Working Interest in a Property described in Exhibit A at any time during the productive life or abandonment thereof, to more than the Working Interest for such Property set forth in Exhibit B unless there is a corresponding proportionate increase in Seller’s Net Revenue Interest.

“Net Revenue Interest” means Seller’s interest in and to all production of Hydrocarbons produced, saved and sold from any Property after giving effect to all royalties, overriding royalties, production payments, carried interests, net profits interests, reversionary interests and other burdens upon, measured by, or payable out of such production.

“Non-Operated Properties” means Properties operated by any Person other than Seller or its Affiliates.

“NORM” means naturally occurring radioactive material.

“Oil and Gas Properties” is defined in Section 2.1.4.

“Operating Expenses” shall mean all operating expenses incurred in the ownership and operation of the Properties, including (i) costs of insurance, (ii) Property Taxes, (iii) Severance Taxes, (iv) capital expenditures (including drilling operations) in the ordinary course of business and, where applicable, approved in accordance with the relevant operating or unit agreement, if any, and (v) Third Party overhead costs charged to the Properties under the relevant operating agreement or unit agreement.

“Operative Documents” means, with regard to a Party, those documents listed or referred to in Section 14.2 or otherwise delivered at the Closing, in each case to the extent executed and delivered by a Party.

“Outside Date” means September 30, 2017.

“Party” means either Buyer or Seller, as the case may be, and “Parties” means both of them.

“Permit” and “Permits” is defined in Section 2.1.9.

“Permitted Encumbrances” means:

(i) Lease Burdens if the cumulative effect of the Lease Burdens does not operate as a Net Reduction of Interest or materially interfere with the operation or use of any of the Properties as currently used or operated;

(ii) Division orders and sales contracts terminable without penalty upon no more than 30 days notice or as set forth on Schedule 7.9;

(iii) Transfer Requirements with respect to which the applicable waivers, consents, approvals, authorizations, filings, and notifications have been obtained or made, or will be obtained or made prior to Closing, from or to the appropriate parties;

(iv) Transfer Requirements (other than Preferential Rights) with respect to which the failure to obtain or make the applicable waivers, consents, approvals, authorizations, filings and notifications prior to Closing will not cause (a) the assignment to Buyer to be void or (b) the termination of the Property under the express terms thereof;

(v) All rights to consent by, required notices to, filings with, or other actions by Governmental Authorities in connection with the sale or conveyance of Hydrocarbon leases or interests therein if they are routinely made or obtained subsequent to transfer;

(vi) Materialman’s, mechanic’s, repairman’s, employee’s, contractor’s, operator’s, and other similar liens or charges arising in the ordinary course of business for obligations (a) that are not delinquent or (b) that if delinquent, are being contested in good faith through appropriate proceedings;

(vii) Liens for Taxes or assessments not yet delinquent or, if delinquent, being contested in good faith in the normal course of business through appropriate proceedings;

(viii) Easements, rights-of-way, servitudes, permits, surface leases, and other rights in respect of surface operations that do not individually or in the aggregate materially interfere with the use and operation of such Property affected thereby for the purpose for which such Property is currently used;

(ix) All (a) Contracts (including calls on Hydrocarbon production thereunder), (b) other operating agreements, unit agreements, unit operating agreements, communitizations, and pooling agreements affecting the Properties (except for any terms or provisions thereof that are not usual and customary for agreements of such nature covering Hydrocarbon properties and operations similar to the Properties and current operation thereof) or (c) compulsory or commissioner’s pooling or units or pooling designations; provided, however, that the effect of any such items listed in clause (a) through (c) does not and will not operate as a Net Reduction of Interest or materially interfere with the operation or use of any of the Properties as currently used or operated;

(x) Conventional rights of reassignment prior to release or surrender requiring notice to the holders of the rights (excepting circumstances where such rights have already been triggered);

(xi) All rights reserved to or vested in any Governmental Authority to control or regulate any of the Properties in any manner, and all applicable Laws; provided, however, that the effect of any such items does not and will not operate as a Net Reduction of Interest or materially interfere with the operation or use of any of the Properties as currently used or operated;

(xii) The terms and conditions of the Material Contracts and Leases; provided, however, that the effect of any such terms and conditions do not and will not operate as a Net Reduction of Interest or materially interfere with the operation or use of any of the Properties as currently used or operated;

(xiii) Claims set forth on Schedule 7.8;

(xiv) Any Title Defects that constitute Minimal Defects;

(xv) Any Title Defects Buyer has expressly waived in writing or which are treated as Permitted Encumbrances under Section 4.2;

(xvi) Any liens, mortgages, security interests, deeds of trust, production payments or other encumbrances burdening the Properties which will be released at or before Closing;

(xvii) Defects that would be accepted by a reasonably prudent buyer engaged in the business of owning and operating oil and gas properties in the region where the Oil and Gas Properties are located, including the absence of any lease amendment or consent by any royalty interest or mineral interest holder authorizing the pooling of any leasehold interest, royalty interest or mineral interest and the failure of Exhibit A to reflect any leased or any unleased mineral interest where the owner thereof was treated as a non-participating co-tenant during the drilling of any well;

(xviii) Defects based on failure to record Leases issued by the BLM, the BIA, any tribal authority or a state, or any assignments of record title or operating rights in such Leases, in the real property or other county records of the county in which the applicable Property is located; provided such Leases or assignments were properly filed in the BLM, the BIA, appropriate tribal authority or state offices; provided however, that this subparagraph shall not include defects arising from the existence of an assignment or other document filed in the county records where a Property is located that results in another Person’s superior claim of title than Seller;

(xix) Defects based on failure to file any assignments of record title or operating rights in Leases issued by the BLM, the BIA, any tribal authority, or a state, in the records of the BLM, the BIA, the land office of such tribal authority or the land office of such state, provided such assignments are recorded in the county records of the county in which the applicable Property is located and there is no assignment on file in the records of the BLM, the BIA, the land office of such tribal authority or the land office of such state that results in another Person’s superior claim of title than Seller;

(xx) Defects that result from the failure to demonstrate of record proper authority for execution by any Person on behalf of a corporation, limited liability company, partnership, trust or other entity;

(xxi) Defects arising out of lack of corporate or other entity authorization, unless Buyer provides affirmative evidence that the action was not authorized and such lack of authorization results in a Third Party’s actual and superior claim of title to the relevant Oil and Gas Interest;

(xxii) The presence or lack of production sales contracts; division orders; contracts for sale, purchase, exchange, refining, processing or fractionating of hydrocarbons; compression agreements; equipment leases; surface leases; unitization and pooling designations, declarations, orders and agreements; processing agreements; plant agreements; pipeline, gathering, and transportation agreements; injection, repressuring, and recycling agreements; salt water or other disposal agreements; seismic or geophysical

permits or agreements; and any and all other agreements which are ordinary and customary in the oil and gas exploration, development, or extraction business, or in the business of processing of gas and gas condensate production for the extraction of products therefrom;

(xxiii) Defects based solely on: (a) lack of information, including lack of information in Seller’s files, the lack of Third Party records or unavailability of information from Governmental Authorities, (b) the absence of certain documents in Seller’s files that are referenced by other documents that are located in Seller’s files, or (c) Tax assessments or other records related to such assessments, unless such absent information, documents or records are required to establish the existence or validity of the Oil and Gas Interest;

(xxiv) Defects as a consequence of cessation of production, insufficient production, or failure to conduct operations during any period after the completion of a well capable of production in paying quantities or any of the Oil and Gas Interests held by production, or lands pooled, communitized or unitized therewith, except to the extent of a Third Party’s claim of termination; provided, however, that defects based upon a determination that (a) there has been no Hydrocarbon production from wells located on the Oil and Gas Interests or lands pooled therewith, and (b) there has been no activity conducted on the Oil and Gas Interest or lands pooled therewith that would otherwise maintain the Oil and Gas Interest in force and effect, may be considered as a Title Defect;

(xxv) Defects based on a gap in a Seller’s chain of title in the county records as to fee Leases, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain or runsheet, which documents shall be included in a Title Defect Notice;

(xxvi) Defects that have been cured by applicable Laws of limitations or prescription;

(xxvii) Defects identified on any Schedule or Exhibit to this Agreement or disclosed in any document referenced in this Agreement;

(xxviii) Defects in the chain of title or in the Oil and Gas Properties itself consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless Buyer provides affirmative evidence that such failure or omission results in another Person’s superior claim of title to the relevant Properties;

(xxix) Defects arising solely out of lack of survey or lack of metes and bounds descriptions, unless a survey is expressly required by applicable Law;

(xxx) Defects based upon Seller’s ownership or Seller’s failure to own leasehold rights in Leases in zones or depths covered by the Lease;

(xxxi) Defects related to mineral or leasehold ownership;

(xxxii) Defects arising from any change in applicable Law after the Effective Time;

(xxxiii) Defects arising from prior oil and gas leases in the chain of title that are not surrendered of record, unless it can be demonstrated that there is a reasonable possibility that such prior oil and gas lease had not expired prior to the creation of the Oil and Gas Interest in question; or

(xxxiv) All other liens, charges, encumbrances, contracts, agreements, instruments, obligations, defects and irregularities affecting the Properties which individually or in the aggregate (a) do not interfere materially with the ownership, operation, value or use of any of the Property, (b) could not reasonably be expected to prevent or delay Buyer from receiving the proceeds of production from any of Properties and (c) do not and will not operate as a Net Reduction of Interest.

“Person” means an individual, group, partnership, corporation, trust or other entity, including Governmental Authorities.

“Plug and Abandon” means (i) necessary plugging, replugging and abandonment of Wells; (ii) the necessary removal, abandonment and disposal of all associated structures, pipelines, equipment, operating inventory, abandoned property, trash, refuse and junk located on or comprising part of the Properties; (iii) the necessary capping and burying of all associated flow lines located on or comprising part of the Properties; and (iv) the necessary restoration of the surface and subsurface (including any required reclamation), in each case, required by Applicable Laws or by any Contract with a Governmental Authority.

“Post-Effective Time Suspense Funds” is defined in Section 17.4.

“Pre-Closing Tax Period” means all Taxable periods (or portions thereof) ending on or before the Closing Date.

“Preference Right” is defined in Section 5.1.1.

“Preliminary Settlement Statement” is defined in Section 16.1.

“Properties” is defined in Section 2.1.

“Property Taxes” means all federal, state or local taxes, assessments, levies or other charges, which are imposed upon the Properties, including ad valorem, property, documentary or stamp, as well as any interest, penalties and fines assessed or due in respect of any such taxes, whether disputed or not.

“Purchase Price” is defined in Section 3.1.

“PV-NRI” is defined in Section 4.6.2.

“Records” means all books and records, files, data, correspondence, studies, surveys, reports, Hydrocarbon sales contract files, gas processing files, geologic, geophysical and seismic

data (including raw data, but excluding any interpretative data or information, relating to such geologic, geophysical and seismic data) and other data (in each case whether in written or electronic format) in the actual possession or control of Seller and which Seller has the right to transfer (either without the payment of money or delivery of other consideration or unduly burdensome effort or, upon Buyer’s election, at Buyer’s expense) and exclusively relating to the ownership or operation of the Properties, including all title records, prospect information, title opinions, title insurance reports, abstracts, property ownership reports, customer lists, supplier lists, sales materials, well logs, well tests, maps, engineering data and reports, health, environmental and safety information and records, third-party licenses, accounting and financial records, promotional materials, operational records, technical records, production and processing records, division order, lease, land and right-of-way files, accounting files, tax records (other than income tax), and contract files (including copies of all Contracts, all files regarding the Contracts and related files); provided, however, “Records” shall not include (i) Seller’s general corporate books and records, even if containing references to Properties, (ii) books, records (including seismic data) and files that cannot be disclosed under the terms of any third party agreement (and Seller’s requested consent to make disclosure has not been obtained) or are not transferable without payment of fees or penalties (except as may be agreed to be paid by Buyer) or cannot be disclosed under applicable Law, (iii) information entitled to legal privilege, including attorney work product and attorney-client communications (excluding title opinions created in the ordinary course of business, which shall be included in the Records), and information relating to Excluded Assets, (iv) Seller’s or its Affiliates’ studies related to internal reserve assessments, (v) records relating to the acquisition or disposition (or proposed acquisition or disposition) of the Properties, including proposals received from or made to, and records of negotiations with, Persons which are not a part of Seller Group or its Representatives and economic analyses associated therewith, (vi) seismic data already owned or held by Buyer, any seismic data that is not transferrable as set forth above, and any seismic interpretative data relating to Properties, (vii) reserve estimates and economic estimates; and (viii) Excluded Assets.

“Remediation” shall mean, with respect to an Environmental Condition, the implementation and completion of any remedial, removal, response, construction, closure, disposal or other corrective actions, including any monitoring, reporting or permitting, or any pollution control equipment installation or operation, required under Environmental Laws to correct or remove such Environmental Condition, and includes the use of risk-based cleanup standards and institutional controls to the extent reasonably available under applicable Environmental Law.

“Remediation Amount” shall mean, with respect to an Environmental Condition, the present value as of the Closing Date (using an annual discount rate of 10%) of the cost (net to Seller’s interest) of the most cost-effective Remediation of such Environmental Condition.

“Seller” is defined in the preamble.

“Seller Group” means Seller and its Affiliates and its and their respective employees, officers, directors, managers, agents, consultants and representatives.

“Seller’s Retained Liabilities” is defined in Section 2.3.2.

“Severance Taxes” means all federal, state or local taxes, assessments, levies or other charges, which are imposed upon production from the Properties, including excise taxes on production, severance or gross production, as well as any interest, penalties and fines assessed or due in respect of any such taxes, whether disputed or not.

“Surface Interests” is defined in Section 2.1.5.

“Tax Return” means any return, declaration, report, claim for refund, property rendition or information return or statement relating to Taxes, including any schedule or attachment thereto and including any amendment thereof, filed with any Taxing authority.

“Taxes” mean any income taxes or similar assessments or any sales, excise, occupation, use, ad valorem, property, production, severance, transportation, employment, payroll, franchise, or other tax imposed by any Governmental Authority, including any interest, penalties, or additions attributable thereto.

“Tax Contest” is defined in Section 19.5.

“Third Party” means, whether such term is capitalized or not, a Person other than Buyer and its Affiliates or Seller and its Affiliates.

“Title Arbitrator” is defined in Section 4.7.2.

“Title Defect” means any lien, charge, obligation (including contract obligation), defect, encumbrance or other matter that renders Seller’s title to any Oil and Gas Property less than Good and Defensible Title.

“Title Defect Deductible” means an amount equal to $3,150,000.

“Title Defect Notice” is defined in Section 4.2.

“Title Defect Property” is defined in Section 4.2.

“Title Defect Removal” means any Title Defect Property excluded from this Agreement pursuant to Section 4.4.2 (subject to Seller’s right to cure set forth in Section 4.4.2) or Section 4.7.4.

“Title Defect Value” means, with respect to each Oil and Gas Property that is agreed or determined to be subject to a Title Defect pursuant to Article 4, the amount determined in accordance with Article 4 with respect to such Title Defect.

“Transfer Requirement” means any waiver, consent, approval, authorization or permit of, or filing with or notification to, any Person that is required to be obtained, made or complied with for or in connection with any sale, assignment or transfer of any Property or any interest therein.

“Transfer Tax” is defined in Section 19.2.

“Uncured Title Defect” means any Title Defect for which (i) Seller has elected to reduce the Purchase Price by the applicable Title Defect Value pursuant to Section 4.4.1 or (ii) the applicable Title Defect Property is conveyed to Buyer after the Closing in accordance with Section 4.7.4 (provided, however, that if a Title Defect Value with respect to any Title Defect is disputed in accordance with Section 4.7, such Title Defect will not be considered an Uncured Title Defect until such time that the Title Defect Value for such Title Defect is finally determined in accordance with Section 4.7 and the applicable Title Defect Property is actually conveyed to Buyer).

“Uncured Title Defects Value” means the aggregate of the Title Defect Values for all Uncured Title Defects.

“Uncured/Unremedied Adjustment Amount” means (i) the amount, if any, by which the aggregate Uncured Titled Defects Value exceeds the Title Defect Deductible plus (ii) the amount, if any, by which the Unremedied Environmental Conditions Amount exceeds the Environmental Defect Deductible.

“Units” is defined in Section 2.1.4.

“Unremedied Environmental Condition” means any Environmental Condition (i) that has not been cured pursuant to Section 6.3, (ii) that has not been removed pursuant to Section 6.4.2 or indemnified under Section 6.4.3, and (iii) for which Seller has elected to reduce the Purchase Price by the applicable Remediation Amount pursuant to Section 6.4.1.

“Unremedied Environmental Conditions Amount” means the aggregate of the Remediation Amounts of all Unremedied Environmental Conditions.

“Upward Adjustment” is defined in Section 4.8.

“Well” and “Wells” is defined in Section 2.1.3.

“Working Interest” means the interest in and to a Property that is burdened with the obligation to bear and pay the costs and expenses associated with the exploration, drilling, development, operation and abandonment of such Property, but without regard to the effect of any royalties, overriding royalties, production payments, net profits interests and other similar burdens upon, measured by or payable out of the production of Hydrocarbons therefrom.

ARTICLE 2

SALE AND PURCHASE OF PROPERTIES; EXCLUDED ASSETS

2.1 Sale and Purchase of Properties. Subject to the terms and conditions of this Agreement, Seller agrees to sell, assign, convey and deliver to Buyer, and Buyer agrees to purchase and acquire from Seller, at the Closing, all of Seller’s right, title and interest in and to the following, except for the Excluded Assets:

2.1.1 All fee interests to the surface and in Hydrocarbons, including rights under grant deeds, mineral deeds, conveyances or assignments, as described on Exhibit A-1 (collectively, the “Fee Interests”);

2.1.2 All of the oil and/or gas leases; subleases and other leaseholds; carried interests; reversionary interests; net profits interests; royalty interests; overriding royalty interests; forced pooled interests; farmout rights; options; mineral interests and other properties and interests described on Exhibit A-1, subject to such depth limitations and other restrictions as may be set forth in the oil and gas leases or other agreements of record in respect thereof, together with all rights, privileges, benefits and powers conferred upon the holder of said interests with respect to the use and occupation of the lands covered thereby (collectively, the “Leases”), together with the lands covered by the Fee Interests or Leases and the interests currently pooled, unitized, communitized or consolidated therewith (collectively, the “Lands”);

2.1.3 All oil, gas, water or injection wells located in tracts on the Lands, whether producing, shut-in, or temporarily abandoned, and the interests in the tracts of wells shown on Exhibit A-2 (collectively, the “Wells”);

2.1.4 Existing pools or units which include any Lands or all or a part of any Leases or include any Wells, including those pools or units associated with the Wells shown on Exhibit A-2 (the “Units”; the Units, together with the Leases, Lands, and Wells, being hereinafter referred to as the “Oil and Gas Properties”), and including all interests of Seller in the production of Hydrocarbons from any such Units, whether such Unit production of Hydrocarbons comes from Wells located on or off of a Lease or Fee Interest, and all tenements, hereditaments and appurtenances belonging to the Leases, Fee Interests and Units;

2.1.5 All easements (including subsurface easements), permits, licenses, servitudes, rights-of-way, surface leases and other surface rights (collectively, “Surface Interests”) appurtenant to, and used or held for use exclusively in connection with the Oil and Gas Properties, whether part of the premises covered by the Leases or Units or otherwise (including those identified on Exhibit A-3), but excluding any permits and other rights to the extent the transfer thereof would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived by Buyer or satisfied pursuant to Article 5;

2.1.6 All equipment, machinery, fixtures and other tangible personal and mixed property and improvements, whether movable or immovable, located on the Oil and Gas Properties and that is used or held for use exclusively in connection with (i) the ownership, use, development, and operation of the Oil and Gas Properties or (ii) the production, treatment, gathering, storage, processing, transportation, and marketing of Hydrocarbons produced therefrom or allocable thereto, including those items identified on Exhibit A-4 (the “Facilities”);

2.1.7 All Hydrocarbons (i) produced from or allocable to the Oil and Gas Properties and existing in storage tanks or other storage facilities that constitute Facilities and that are upstream of the delivery points to the relevant purchasers as of the Effective Time, or (ii) produced from or allocable to the Oil and Gas Properties from and after the Effective Time;

2.1.8 Except to the extent transfer thereof would result in a violation of applicable Law and subject to Article 5, all farmout and farmin agreements, operating agreements, production sales and purchase contracts, processing contracts, gathering contracts, transportation contracts, storage contracts, saltwater disposal agreements, Surface Interests, division and transfer orders, areas of mutual interest, balancing contracts, unitization, pooling and communitization agreements, leases and subleases of any Facility and all other written contracts, contractual rights, interests, in each case, exclusively relating to any or all of the Oil and Gas Properties or Facilities or the production handling or transportation of Hydrocarbons, water or other substances attributable thereto or produced therefrom (the “Contracts”), including, for the avoidance of doubt, the Material Contracts identified on Schedule 7.9 and any such contracts, agreements or arrangements entered into between the date hereof and the Closing; provided, however, that “Contracts” shall not include the Leases or Permits;

2.1.9 To the extent transferable, all certificates, consents, permits, licenses, orders, authorizations, franchises and related instruments or rights issued by any Governmental Authority and exclusively relating to the ownership, operation or use of the Oil and Gas Properties and including any of the foregoing, to the extent obtained or renewed between the date hereof and the Closing (the “Permits”);

2.1.10 All Records;

2.1.11 All Equity Interests in Raven Ridge Pipeline Company;

2.1.12 To the extent assignable, except with respect to Casualty Losses as provided in Article 10 or to the extent relating to any of Seller’s Retained Liabilities, all insurance proceeds under existing policies of insurance issued by a Third Party, if any, relating to the Oil and Gas Properties, Surface Interests, Wells or Facilities, but only to the extent that such benefits relate to liabilities for which Buyer is responsible under this Agreement; and

2.1.13 Except to the extent relating to any of Seller’s Retained Liabilities, all intangibles and operating revenues and accounts receivable to the extent relating to the period after the Effective Time, in each case to the extent associated with the Oil and Gas Properties or the production of Hydrocarbons attributable thereto;

Except for the Excluded Assets, all of the real and personal properties, rights, titles, and interests described in Sections 2.1.1 through 2.1.13, subject to the limitations and terms expressly set forth herein and in Exhibit A-1, Exhibit A-2, Exhibit A-3, Exhibit A-4 and Exhibit B, are referred to herein as the “Properties”.

2.2 Excluded Assets. Notwithstanding anything to the contrary in this Agreement, Seller specifically excludes from this transaction all items, properties, liabilities and matters set

forth below, along with all items, properties, liabilities and matters excluded from this transaction pursuant to the terms and conditions of this Agreement (the “Excluded Assets”):

2.2.1 Except to the extent relating to any Assumed Liability, all intangibles and operating revenues and accounts receivable to the extent relating to the period prior to the Effective Time;

2.2.2 All rights to any refunds of Taxes or other costs or expenses borne by Seller or such Seller’s predecessors in interest and title attributable to periods prior to the Effective Time;

2.2.3 Anything excluded from “Records” as set forth in the definition thereof;

2.2.4 Computer or communications software or intellectual property (Clear SCADA, Field Direct, Flow Cal, AES, and other software and custom configurations of the same, as well as all tapes, codes, data and program documentation, and all tangible manifestations and technical information relating thereto);

2.2.5 All rights (i) under any policy or agreement of insurance or indemnity, (ii) under any bond, or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property, occurring prior to the Effective Time;

2.2.6 All exchange traded futures contracts and over-the-counter derivative hedge contracts of Seller;

2.2.7 All right, title and interest of Seller in and to vehicles used in connection with the Properties, other than those identified on Exhibit A-4;

2.2.8 Any Property removed from this Agreement pursuant to Article 4, Article 5, or Article 6;

2.2.9 those items listed in Schedule 2.2.9.

2.3 Assumed Liabilities and Seller’s Retained Liabilities.

2.3.1 Without limiting Buyer’s rights to be indemnified in accordance with Article 18, and except for Seller’s Retained Liabilities and other matters that are Seller’s or any of its Affiliates’ express obligations under this Agreement or any of the Operative Documents, Buyer expressly acknowledges that it is responsible for, and shall have no recourse against Seller or Seller Group for, the Liabilities arising under, related to, or in connection with the transfer, ownership, operation or use of the Properties acquired by it hereunder, and if Closing occurs, from and after the Closing Date, Buyer shall expressly assume, timely perform and discharge all such Liabilities (including Liabilities to Plug and Abandon), whether attributable to the period of time before or after the Effective Time (collectively, the “Assumed Liabilities”).

2.3.2 “Seller’s Retained Liabilities” means any and all Liabilities to the extent relating to:

(i) Seller’s ownership, operation or use of the Excluded Assets;

(ii) any personal injury (including death) to the extent related to Seller’s ownership or operation of the Properties and arising from events occurring prior to the Effective Time;

(iii) (a) the payment of any Lease Burdens, Property Taxes or Severance Taxes allocable to the period prior to the Effective Time and (b) any Taxes of the Seller or its Affiliates;

(iv) all suspended funds held by Seller and owed to Third Parties for royalties with respect to the Properties prior to and as of the Effective Time; and

(v) the Indebtedness of Seller.

ARTICLE 3

PURCHASE PRICE

3.1 Purchase Price; Deposit. The total purchase price for the Properties will be One Hundred Five Million Dollars ($105,000,000), subject to any applicable adjustments as hereinafter provided (the “Purchase Price”). Within one day following the execution of this Agreement, Buyer shall pay by wire transfer in immediately available funds to Escrow Agent an amount equal to 10% of the Purchase Price as an earnest money deposit (the “Deposit”, and together with any interest accrued while being held by Escrow Agent, the “Escrow Funds”) which shall be held by Escrow Agent in accordance with the terms and conditions of the Escrow Agreement and this Agreement. If Closing occurs, (i) the Escrow Funds shall be applied towards the Purchase Price at Closing in accordance with Section 14.2.2 and (ii) on the Closing Date, Buyer and Seller will execute and deliver to the Escrow Agent joint written instructions authorizing the Escrow Agent to release to Seller the Escrow Funds (the “Escrow Release”).

3.2 Increases in Purchase Price. In accordance with Article 16, the Purchase Price will be increased by the following amounts (without duplication):

3.2.1 the amount of any Operating Expenses that are paid by Seller at any time and attributable to the Properties for the period of time on or after the Effective Time, and a fixed overhead charge of $25,000 per month from the Effective Time through the Closing Date;

3.2.2 the amount of all proceeds, receipts (including producing receipts, drilling receipts and construction overhead receipts), reimbursements, credits, and income paid to or received by Buyer, including proceeds from the sale of Hydrocarbons (excluding the Inventory Hydrocarbons), in each case net of all applicable Property Taxes and Severance Taxes and royalties, overriding royalties or other similar burdens paid by Buyer, that are attributable to the Properties for the period of time prior to the Effective Time;

3.2.3 the amount of all Assignment Premiums pursuant to Section 9.3.4; and

3.2.4 the amount of all other upward adjustments to the Purchase Price provided for in this Agreement.

3.3 Decreases in Purchase Price. In accordance with Article 16, the Purchase Price will be decreased by the following amounts (without duplication):

3.3.1 the amount of any Operating Expenses that are unpaid as of the Closing Date and attributable to the Properties for the period of time prior to the Effective Time;

3.3.2 the amount of all proceeds, receipts (including producing receipts, drilling receipts and construction overhead receipts), reimbursements, credits, and income paid to or received by Seller, including proceeds from the sale of Hydrocarbons, net of all applicable Property Taxes, Severance Taxes, royalties, overriding royalties and other similar burdens paid by Seller, that are attributable to the Properties for the period of time on or after the Effective Time;

3.3.3 with respect to Title Defect Removals, if any, the Allocated Value for each Title Defect Property to which such Title Defect Removals relate;

3.3.4 with respect to Environmental Condition Removals, if any, the Allocated Value for each Environmental Condition Property to which such Environmental Condition Removals relate;

3.3.5 the Uncured/Unremedied Adjustment Amount;

3.3.6 the Allocated Value of all Properties subject to preferential rights to purchase or required consents from Third Parties that have been removed and not sold to Buyer at Closing pursuant to Article 5; and

3.3.7 the amount of all other downward adjustments to the Purchase Price provided for in this Agreement.

ARTICLE 4

TITLE MATTERS

4.1 Review of Title Records. After execution and delivery of this Agreement, Seller will make available (during Seller’s regular business hours and at its current location) for Buyer’s due diligence review, the Records in Seller Group’s possession or control relating to title to the Oil and Gas Properties and reasonable access to Seller’s personnel. If Buyer requests copies of such Records, Seller will use Commercially Reasonable Efforts to promptly provide the requested copies to Buyer at Buyer’s expense.

4.2 Title Defect Notice. Buyer will provide Seller with written notice (a “Title Defect Notice”) at or before 5:00 p.m. (Houston time) on July 12, 2017 (“Defect Notification Deadline”) of any matter that Buyer intends to assert as a Title Defect under this Article 4; provided, however, that Buyer will provide Seller with a preliminary Title Defect Notice each Friday at or before 5:00 p.m. (central standard time) until the Defect Notification Deadline if any officer of Buyer or its Affiliates discovers or learns of any Title Defect during each such one-week period; provided, further, that no delay on the part of the Buyer in notifying Seller on a weekly basis prior to the Defect Notification Deadline will relieve Seller of any liability or obligation hereunder or adversely affect any of Buyer’s rights hereunder. The Title Defect Notice must include, in reasonable detail, to the extent then reasonably known by Buyer and to the extent applicable, a description of (i) the Oil and Gas Property with respect to which the claimed Title Defect relates (the “Title Defect Property”), (ii) the nature of such claimed Title Defect, (iii) Buyer’s proposed calculation of each Title Defect Value in accordance with the guidelines set forth in Section 4.6, and (iv) such supporting documents reasonably necessary for Seller to verify the existence of such alleged Title Defect. Buyer shall not be entitled to assert hereunder any Title Defect that constitutes a Minimal Defect. Any Title Defect that is not identified in a timely delivered Title Defect Notice is thereafter forever waived by Buyer and such Title Defect will become a Permitted Encumbrance; provided, however, that the foregoing shall not modify or limit the special warranty of title included in the Conveyance. OTHER THAN SELLER’S SPECIAL WARRANTY OF TITLE IN THE CONVEYANCE, THE UNITS, AND WELLS ARE CONVEYED WITHOUT WARRANTY OF TITLE OF ANY KIND, EXPRESS, IMPLIED OR STATUTORY OR OTHERWISE. Buyer’s protection under Seller’s special warranty of title in the Conveyance is limited to the Allocated Value of the Properties as set forth on Exhibit B. Buyer is not entitled to protection under Seller’s special warranty of title in the Conveyance against any Title Defect reported by Buyer under this Section 4.2 and/or any Title Defect known by Buyer or any of its Affiliates prior to the Title Defect Deadline.

4.3 Seller’s Right to Cure Title Defects.

Subject to the provisions of this Section 4.3, Seller has the right, but not the obligation, to cure prior to Closing any Title Defect at Seller’s sole cost. If Seller elects to cure a Title Defect and such cure has not been completed to the reasonable satisfaction of Buyer on or before three days prior to the Closing Date, then Seller shall make an election pursuant to Section 4.4; provided, however, that Seller shall have a continuing right to cure after Closing under Section 4.4.2.

4.4 Remedies for Title Defects.

Subject to Seller’s continuing right to dispute the existence of a Title Defect or the Title Defect Value asserted with respect thereto, in the event that any Title Defect is timely asserted by Buyer in accordance with Section 4.2 and is not waived in writing by Buyer or cured pursuant to Section 4.3, then Seller shall, at its sole option, elect one of the following options:

4.4.1 Seller shall assign the Title Defect Property to Buyer at Closing and the Title Defect Value for such Title Defect Property determined pursuant to Sections 4.6 and Section 4.7 shall be taken into account in the calculation of the Uncured/Unremedied

Adjustment Amount; provided, however, that if the Title Defect Value or the existence of the Title Defect is still in dispute at Closing, then (i) the Title Defect Value for such Title Defect Property calculated by Buyer in the Title Defect Notice shall be taken into account in the calculation of the Uncured/Unremedied Adjustment Amount at Closing and (ii) within three Business Days after such dispute is resolved pursuant to Section 4.7, either Buyer shall make a true-up payment to Seller or Seller shall reimburse Buyer, for an amount equal to the difference, if any, between the Uncured/Unremedied Adjustment Amount applied at Closing and the Uncured/Unremedied Adjustment Amount determined after Closing in accordance with Section 4.7.

4.4.2 At Closing Seller shall retain the entirety of the Title Defect Property that is subject to such Title Defect, together with all Properties exclusively related thereto, and the Purchase Price shall be reduced by an amount equal to the sum of the Allocated Values for such Title Defect Property and related Properties pursuant to Section 3.3.3, and such Title Defect Property and related Properties shall be deemed Excluded Assets. Thereafter, Seller shall have 180 days in which to cure such Title Defect (the “Cure Period”). If such Title Defect is cured prior to expiration of the Cure Period, then such retained Properties shall be conveyed to Buyer in accordance with Section 4.9. In the event that Seller is unable to cure such Title Defect prior to expiration of the Cure Period, then the provisions of Section 4.4.1 shall apply and such retained Properties shall be conveyed to Buyer at a delayed closing in accordance with Section 4.9.

4.5 Exclusive Remedy. Except for Buyer’s rights under Seller’s special warranty of title in the Conveyance and Buyer’s right to terminate this Agreement pursuant to Section 15.1.7, the provisions set forth in Section 4.3 and Section 4.4 shall be the exclusive right and remedy of Buyer with respect to Seller’s failure to have Good and Defensible Title with respect to any of the Properties and any other title matters. Notwithstanding anything to the contrary in this Agreement, if any matter that could result in the breach of any representation or warranty of Seller set forth in Article 7 could also have been raised as a Title Defect under this Article 4, then Buyer may only assert such matter as a Title Defect to the extent permitted by this Article 4, and is precluded from also asserting such matter as the basis of the breach of any such representation or warranty.

4.6 Calculation of Title Defect Value. The amount of the Title Defect Value for a Title Defect Property shall be determined as follows:

4.6.1 If, because of the Title Defect, title to a particular Oil and Gas Property fails completely with the effect that Seller has no ownership interest in the relevant Oil and Gas Property, the Title Defect Value will be the Allocated Value of that Oil and Gas Property.

4.6.2 If a Title Defect results in a Net Reduction of Interest in an Oil and Gas Property and such Oil and Gas Property has an Allocated Value assigned specifically to it on Exhibit B, then the Title Defect Value will be the Allocated Value for such Oil and Gas Property multiplied by a fraction (i) the numerator of which is the net present value, as of the Effective Time, of Seller’s ownership interest in such Oil and Gas Property as

shown on Exhibit B (the “PV-NRI”) minus the net present value as of the Effective Time, of Seller’s actual ownership interest in such Oil and Gas Property calculated based upon the same production, cost, and assumed future price estimates and discount rate and such other methods, techniques and assumptions utilized in determining PV-NRI but taking into account the Title Defect, and (ii) the denominator of which is the PV-NRI.

4.6.3 If a Title Defect is a lien, encumbrance or other charge upon an Oil and Gas Property which is liquidated in amount, then the Title Defect Value for such Title Defect shall be the amount necessary to be paid to remove the Title Defect from the affected Oil and Gas Property.

4.6.4 If a Title Defect represents an obligation or burden upon an Oil and Gas Property of a type not described in Sections 4.6.1 through 4.6.3, then the Title Defect Value with respect to such Title Defect will be the sum the Parties mutually agree upon in good faith as the present value of the adverse economic effect such Title Defect will have on such Oil and Gas Property. If the Parties cannot reach an agreement as to such Title Defect Value, then the Parties will resolve such dispute in the manner set forth in Section 4.7.

4.6.5 Notwithstanding anything to the contrary under this Section 4.6 or Section 4.7, in no event will the aggregate Title Defect Values with respect to an Oil and Gas Property exceed the Allocated Value of such Oil and Gas Property, and if such Oil and Gas Property does not have an Allocated Value, the Allocated Value of such Oil and Gas Property shall be deemed to be $0.00.

4.7 Title Defect Dispute Resolution.

4.7.1 Within five Business Days after Seller’s receipt of a Title Defect Notice, Seller will notify Buyer as to whether Seller agrees with the Title Defects claimed therein and the proposed Title Defect Values. If Seller objects to any such claimed Title Defect or any such proposed Title Defect Values, then the Parties will promptly enter into good faith negotiations and subject to the limitations in Section 4.6.6, the value agreed by the Parties with respect to a Title Defect will be the Title Defect Value for such Title Defect.

4.7.2 If the Parties do not reach agreement concerning either the existence of a Title Defect or a Title Defect Value prior to Closing, then, upon either Party’s written request, the Parties will submit such dispute to an attorney or other consultant experienced in title examination of oil and gas properties in the state in which such Oil and Gas Property is located to arbitrate a prompt resolution (the “Title Arbitrator”). The Title Arbitrator shall be selected by (i) mutual agreement of Seller and Buyer within five Business Days after the Party’s written request to submit such dispute for resolution, or (ii) if the Parties cannot agree, by the Houston office of the American Arbitration Association; provided, however, that if at any time any Title Arbitrator fails or refuses to perform under this Section 4.7, the Parties will select a new Title Arbitrator in accordance with this sentence. The costs of any Title Arbitrator shall be borne by Seller and Buyer in inverse proportion as they may prevail on matters resolved by the Title Arbitrator, which inverse proportionate allocations shall also be determined by the Title Arbitrator at the time the determination of the Title Arbitrator is rendered on the merits of the matters submitted.

4.7.3 For any dispute resolution process under this Section 4.7, Seller and Buyer will present a written statement of their respective positions on the dispute to the Title Arbitrator within three Business Days after the Title Arbitrator is selected, and the Title Arbitrator will make a determination of all points of disagreement in accordance with the terms and conditions of this Agreement within ten Business Days of receipt of such statements. Absent manifest error, the Title Arbitrator will determine any Title Defect Value by selecting, with respect to each item in dispute, an amount equal to the Seller’s position or the Buyer’s position. The Title Arbitrator’s determination will be conclusive and binding on the Parties. Any court of competent jurisdiction may enforce the arbitration determination against either Party and the Title Arbitrator’s value determination will be the Title Defect Value for such Title Defect.

4.7.4 Subject to Seller’s right to cure pursuant to Section 4.3 and Section 4.4.2 and Seller’s right to assign any Title Defect Property with a disputed Title Defect pursuant to Section 4.4.1, if any Title Defect Property is subject to a dispute under this Section 4.7 at the time of Closing: (i) such Title Defect Property, together with all Properties exclusively related thereto, shall be deemed to be Excluded Assets and shall be retained by Buyer at Closing, and (ii) the Purchase Price will be reduced by the sum of the Allocated Values for such retained Properties. After the Title Arbitrator or the Parties resolve the disputed issues pursuant to this Article 4 with respect to any Title Defect Property that is retained by Seller pursuant to this Section 4.7.4, such retained Property shall be conveyed to Buyer in accordance with Section 4.9 (unless the subject Title Defect Value is equal to the Allocated Values of such retained Properties, in which event, Sellers may elect, in their sole discretion, to permanently retain such Properties).

4.8 Possible Upward Adjustment. Should Seller (or Buyer in the course of its diligence review pursuant to Section 4.1) determine that (i) the ownership of an Oil and Gas Property by Seller entitles Seller to a decimal share of the Hydrocarbons produced from such Oil and Gas Property greater than the applicable Net Revenue Interest set forth in Exhibit B, or (ii) that there is an increase in Seller’s Working Interest in an Oil and Gas Property described in Exhibit A greater than the Working Interest as set forth in Exhibit B for such Oil and Gas Property at any time during the productive life or abandonment thereof, as long as there is a corresponding proportionate increase in Seller’s Net Revenue Interest for such Oil and Gas Property relative to what is shown on Exhibit B for such Oil and Gas Property, then such Party shall calculate (in the same manner as set forth in Section 4.6 with respect to Title Defects) the amount by which the Allocated Value of such Oil and Gas Property is increased (an “Upward Adjustment”), and the aggregate Uncured Title Defect Value asserted by Buyer shall be reduced by such Upward Adjustment.

4.9 Delayed Closing. If any Properties are required to be conveyed to Buyer pursuant to Sections 4.4.2 or 4.7.4, then (i) such Properties shall be deemed to no longer be Excluded Assets and shall be Properties for all purposes under this Agreement, (ii) such Properties shall be conveyed on the date that is ten Business Days after such Title Defect is cured by Seller or after the Title Defect Value is finally determined (as applicable), (iii) such Properties

shall be conveyed pursuant to an assignment in the form of the Conveyance, subject to the terms and conditions of this Agreement and (iv) simultaneously with such conveyance, Buyer shall pay to Seller the Allocated Values for such Properties subject to adjustment pursuant to Section 3.3.5, solely to the extent not duplicative of adjustments already made to the Purchase Price.

ARTICLE 5

PREFERENTIAL RIGHTS AND CONSENTS

5.1 Preferential Rights to Purchase.

5.1.1 Without limitation on the rights and obligations of the Parties set forth in Section 9.3, Seller shall use Commercially Reasonable Efforts to promptly provide notices with respect to the Transfer Requirements that are preferential rights to purchase (“Preference Right”), and for the purpose of any Preference Right, the value of the applicable Property will be its Allocated Value.

5.1.2 If (i) the holder of a Preference Right does not elect to purchase the applicable Property or waives its right to do so, or (ii) the time in which the Preference Right may be exercised has expired, then such Property will be assigned to Buyer at the Closing in accordance with the terms and subject to the conditions of this Agreement.

5.1.3 If, prior to the Closing Date, a holder of a Preference Right notifies Seller that it elects to exercise its Preference Right with respect to the applicable Property, then (i) such Property, together with all Properties exclusively related thereto, will not be conveyed to Buyer at Closing and will be deemed an Excluded Asset, and (ii) the Purchase Price will be reduced by the applicable Allocated Values pursuant to Section 3.3.6 for such retained Properties, provided, however, if the holder of such Preference Right fails to complete the purchase of said Property (or portion thereof) within 180 days after the Closing Date, then Seller may elect, in its discretion and upon written notice to Buyer, to deliver such retained Properties at a delayed closing pursuant to the procedures in Section 5.3.

5.1.4 Seller shall promptly notify Buyer of the exercise of any Preference Right in respect of the Properties.

5.2 Transfer Requirements other than Preferential Rights to Purchase.

5.2.1 Without limitation on the rights and obligations of the Parties set forth in Section 9.3, Seller shall use Commercially Reasonable Efforts to promptly provide any required notifications with respect to the Transfer Requirements (other than Preference Rights), including those set forth on Schedule 7.5.

5.2.2 If, prior to the Closing, all Transfer Requirements with respect to any Property (i) are fully satisfied, have expired or are no longer applicable to the transactions contemplated hereby, or (ii) are Permitted Encumbrances (other than those Permitted

Encumbrances set forth in clause (a) of subsection (ix) of the definition of “Permitted Encumbrances”), then such Property will be assigned to Buyer at the Closing in accordance with the terms and subject to the conditions of this Agreement.

5.2.3 If, prior to the Closing Date, a holder of a Transfer Requirement notifies Seller that it refuses to consent (or waive its right to do so) to the transactions contemplated hereby with respect to the applicable Property, then (i) such Property, together with all Properties exclusively related thereto, will not be conveyed to Buyer at Closing and will be deemed an Excluded Asset, and (ii) the Purchase Price will be reduced by the applicable Allocated Values pursuant to Section 3.3.6 for such retained Properties, provided, however, if the holder of such Transfer Requirement provides such consent or waiver to satisfy the Transfer Requirement (or if such Transfer Requirement is otherwise fully satisfied, expires or is no longer applicable to the transactions contemplated hereby) within 180 days after the Closing Date, then Seller may elect, in its reasonable discretion and upon written notice to Buyer, to deliver such retained Properties at a delayed closing pursuant to the Section 5.3.

5.3 Delayed Closing. If any Properties are required to be conveyed to Buyer pursuant to Section 5.1.3 or Section 5.2.3, then (i) such Properties shall be deemed to no longer be Excluded Assets and shall be Properties for all purposes under this Agreement, (ii) such Properties shall be conveyed on the date that is ten Business Days after Buyer’s receipt of Seller’s written notice pursuant to Section 5.1.3 or Section 5.2.3 (as applicable), (iii) such Properties shall be conveyed pursuant to an assignment in the form of the Conveyance, subject to the terms and conditions of this Agreement and (iv) simultaneously with such conveyance, Buyer shall pay to Seller the Allocated Values for such Properties subject to adjustment pursuant to Section 3.3.5, solely to the extent not duplicative of adjustments already made to the Purchase Price.

ARTICLE 6

ENVIRONMENTAL MATTERS

6.1 Environmental Assessment. Buyer will have the opportunity to conduct, at its sole risk and expense, an environmental assessment of the Properties, including a Phase I assessment as such term is defined by the ASTM E1527-13 All Appropriate Inquiry Standard. Seller will provide reasonable access for this purpose to Properties operated by Seller. For any Property not operated by Seller, Seller will reasonably cooperate with Buyer in contacting the operators of any such non-operated Property directly to attempt to arrange for access for the purposes of environmental assessment. Buyer shall not conduct any test drilling or sampling activities without prior notice to and consent of Seller (in its sole discretion) and the operator of the affected Property. Buyer shall provide Seller with a minimum of three Business Days’ advance notice of its proposed environmental assessment activities prior to entering the Property to be assessed. If Buyer wishes to utilize any third party personnel or contractors to perform any activities on any Property, Buyer shall obtain Seller’s prior consent (in its sole discretion) to the use of such third party personnel or contractors, and shall provide Seller with evidence reasonably satisfactory to Seller that all such Persons have appropriate training and are covered by appropriate insurance.

6.2 Notice of Environmental Condition. Buyer will provide Seller with written notice (an “Environmental Condition Notice”) on or before the Defect Notification Deadline of any condition that Buyer intends to assert as an Environmental Condition under this Article 6 provided, however, Buyer agrees to use its good faith efforts to notify Seller of an Environmental Condition as promptly as possible after Buyer has discovered and made the decision to assert the same; provided that the failure to provide such good faith notice in advance of the Defect Notification Deadline shall not affect Buyer’s rights hereunder. Each Environmental Condition Notice must include, in reasonable detail, a description of (i) the Property with respect to which such Environmental Condition is claimed (the “Environmental Condition Property”), (ii) the nature of such claimed Environmental Condition (including the applicable Environmental Laws violated or implicated thereby), and (iii) Buyer’s proposed calculation of the Remediation Amount. Buyer shall not be entitled to assert hereunder any Environmental Condition that constitutes a Minimal Defect. Any Environmental Condition that is not identified in a timely delivered Environmental Condition Notice is thereafter forever waived and expressly assumed by Buyer.

6.3 Seller’s Right to Cure Environmental Conditions.

Subject to the provisions of this Section 6.3, Seller will have the right, but not the obligation, to conduct Remediation for any Environmental Condition prior to Closing at Seller’s sole cost in accordance with applicable Environmental Laws. If Seller elects to conduct Remediation and the Remediation has not been completed prior to the Closing Date, then Seller shall make an election pursuant to Section 6.4; provided, however, that the Seller shall have a continuing right to conduct Remediation after Closing under Section 6.4.2.

6.4 Remedies for Environmental Conditions.

Subject to Seller’s continuing right to dispute the existence of an Environmental Condition or the Remediation Amount asserted with respect thereto, in the event that any Environmental Condition other than a Minimal Defect is timely asserted by Buyer in accordance with Section 6.2 and is not waived in writing by Buyer or subject to Remediation completed prior to the Closing, then Seller shall, at its sole option, elect one of the following:

6.4.1 Seller shall assign the Environmental Condition Property to Buyer at Closing and the Remediation Amount for such Environmental Condition Property shall be taken into account in the calculation of the Uncured/Unremedied Adjustment Amount; provided, however, that if the Remediation Amount or the existence of an Environmental Condition is still in dispute at Closing, then (i) the Remediation Amount for such Environmental Condition Property calculated by Buyer in the Environmental Condition Notice shall be taken into account in the calculation of the Uncured/Unremedied Adjustment Amount at Closing and (ii) within three Business Days after such dispute is resolved pursuant to Section 6.6, Buyer shall make a true-up payment to Seller or Seller shall reimburse Buyer for an amount equal to the difference, if any, between the Uncured/Unremedied Adjustment Amount applied at Closing and the Uncured/Unremedied Adjustment Amount determined after Closing in accordance with Section 6.6.

6.4.2 At Closing, Seller shall retain the entirety of the Environmental Condition Property that is subject to such Environmental Condition, together with all Properties exclusively related thereto, and the Purchase Price shall be reduced by an amount equal to the sum of the Allocated Values for such Environmental Condition Property and related Properties pursuant to Section 3.3.4, and such Environmental Condition Property and related Properties shall be deemed Excluded Assets. If the Remediation is completed prior to expiration of the Cure Period, then such retained Properties shall be conveyed to Buyer in accordance with Section 6.7. In the event that Seller is unable to complete Remediation prior to expiration of the Cure Period, then Section 6.4.1 shall apply and such retained Properties shall be conveyed to Buyer at a delayed closing in accordance with Section 6.7.

6.5 Exclusive Remedy. Except for Buyer’s remedy for breach of Seller’s representation contained in Section 7.7 and Buyer’s right to terminate this Agreement pursuant to Section 15.1.7, the provisions set forth in Section 6.4 shall be the exclusive right and remedy of Buyer with respect to any environmental matter, including Environmental Conditions.

6.6 Environmental Condition Dispute Resolution.

6.6.1 Within five Business Days after Seller’s receipt of an Environmental Condition Notice, Seller will notify Buyer as to whether Seller agrees with the Environmental Conditions claimed therein and the proposed Remediation Amounts. If Seller objects to any such claimed Environmental Condition or any such proposed Remediation Amount, then the Parties will promptly enter into good faith negotiations and the amount agreed by the Parties with respect to an Environmental Condition will be the Remediation Amount for such Environmental Condition.

6.6.2 If the Parties do not reach agreement concerning either the existence of an Environmental Condition or a Remediation Amount prior to Closing, then, upon either Party’s written request, the Parties will submit such dispute to an environmental consultant or other consultant experienced in oil and gas producing property environmental remediation in the state in which such Property is located to arbitrate a prompt resolution (the “Environmental Arbitrator”). Such Environmental Arbitrator shall be selected by (i) mutual agreement of Seller and Buyer within five Business Days after the Party’s written request to submit such dispute for resolution, or (ii) if the Parties cannot agree, by the Houston office of the American Arbitration Association; provided, however, that if at any time any Environmental Arbitrator fails or refuses to perform under this Section 6.6, a new Environmental Arbitrator will be selected by the Parties in accordance with this sentence. The costs and expenses of any such Environmental Arbitrator shall be borne by Seller and Buyer in inverse proportion as they may prevail on matters resolved by the Environmental Arbitrator, which inverse proportionate allocations shall also be determined by the Environmental Arbitrator at the time the determination of the Environmental Arbitrator is rendered on the merits of the matters submitted.

6.6.3 For any dispute resolution under this Section 6.6, Seller and Buyer will present a written statement of their respective positions on the dispute to the

Environmental Arbitrator within three Business Days after the Environmental Arbitrator is selected, and the Environmental Arbitrator will make a determination of all points of disagreement in accordance with the terms and conditions of this Agreement within ten Business Days of receipt of such statements. Absent manifest error, the Environmental Arbitrator will determine any Remediation Amount by selecting, with respect to each item in dispute, an amount equal to the Seller’s position or the Buyer’s position. The Environmental Arbitrator’s determination will be conclusive and binding on the Parties and will be enforceable against either Party in any court of competent jurisdiction, and the Environmental Arbitrator’s value determination will be the Remediation Amount for such Environmental Condition.

6.6.4 Subject to Seller’s right to cure pursuant to Section 6.3 and Section 6.4.2 and Seller’s right to assign any Environmental Condition Property with a disputed Environmental Condition pursuant to Section 6.4.1, if any Environmental Condition Property is subject to a dispute under this Section 6.5 at the time of Closing: (i) such Environmental Condition Property, together with all Properties exclusively related thereto, shall be deemed to be Excluded Assets and shall be retained by Buyer at Closing, and (ii) the Purchase Price will be reduced by the sum of the Allocated Values for such retained Properties. After the Environmental Arbitrator or the Parties resolve the disputed issues pursuant to this Article 6 with respect to any Environmental Condition Property that is retained by Seller pursuant to this Section 6.6.4, such retained Properties shall be conveyed to Buyer in accordance with Section 6.7 (unless the subject Remediation Amount is equal to or greater than the Allocated Values of such retained Properties, in which event, Seller may elect, in its sole discretion, to permanently retain such Properties).

6.7 Delayed Closing. If any Properties are required to be conveyed to Buyer pursuant to Section 6.4.2 or Section 6.6.4, then (i) such Properties shall be deemed to no longer be Excluded Assets and shall be Properties for all purposes under this Agreement, (ii) such Properties shall be conveyed on the date that is ten Business Days after the Remediation is completed by Seller or after the Remediation Amount is finally determined (as applicable), (iii) such Properties shall be conveyed pursuant to an assignment in the form of the Conveyance, subject to the terms and conditions of this Agreement and (iv) simultaneously with such conveyance Buyer shall pay to Seller for such Properties the amount withheld by Buyer with respect to such Properties at Closing, subject to adjustment pursuant to Section 3.3.5, solely to the extent not duplicative of adjustments already made to the Purchase Price.

6.8 Presence of Wastes, NORM, Hazardous Substances and Asbestos. BUYER ACKNOWLEDGES THAT THE PROPERTIES HAVE BEEN USED TO EXPLORE FOR, DEVELOP AND PRODUCE HYDROCARBONS, AND THAT SPILLS OF WASTES, CRUDE OIL, PRODUCED WATER, HAZARDOUS SUBSTANCES AND OTHER MATERIALS MAY HAVE OCCURRED THEREON. ADDITIONALLY, THE PROPERTIES, INCLUDING PRODUCTION EQUIPMENT, MAY CONTAIN ASBESTOS, HAZARDOUS SUBSTANCES OR NORM. NORM MAY AFFIX OR ATTACH ITSELF TO THE INSIDE OF WELLS, MATERIALS AND EQUIPMENT AS SCALE OR IN OTHER FORMS, AND NORM-CONTAINING MATERIAL MAY HAVE BEEN BURIED OR OTHERWISE DISPOSED OF ON THE PROPERTIES. A HEALTH HAZARD MAY EXIST

IN CONNECTION WITH THE PROPERTIES BY REASON THEREOF. SPECIAL PROCEDURES MAY BE REQUIRED FOR REMEDIATION, REMOVING, TRANSPORTING AND DISPOSING OF ASBESTOS, NORM, HAZARDOUS SUBSTANCES AND OTHER MATERIALS FROM THE PROPERTY. With respect to the Properties actually acquired by Buyer hereunder, Buyer assumes from and after Closing all liability for the assessment, remediation, removal, transportation and disposal of these materials and any associated activities in accordance with applicable Laws, unless otherwise provided in this Article 6. The foregoing shall not modify or limit Seller’s indemnity and hold harmless obligations under Section 18.1.

ARTICLE 7

REPRESENTATIONS AND WARRANTIES OF SELLER

Except as set forth in the Schedules, Seller represents and warrants to Buyer that each of the statements made in this Article 7 is true and correct as of the date of this Agreement and will be true and correct as of the Closing Date.

7.1 Organization. Seller is a limited liability company duly organized, validly existing and in good standing under the laws of Delaware. Seller is in good standing and duly qualified to do business in each other jurisdiction in which the conduct of its business or ownership or leasing of its properties makes such qualification or registration necessary.

7.2 Authority. Seller has all requisite limited liability company power and authority to execute and deliver this Agreement and the Operative Documents to which it is a party, to consummate the transactions contemplated by this Agreement and the Operative Documents to which it is a party and to perform all of its obligations under this Agreement and the Operative Documents to which it is a party.

7.3 Enforceability. This Agreement has been duly executed and delivered on behalf of Seller and constitutes (and the Operative Documents to which it is a party, when executed and delivered at Closing, will constitute) a legal, valid and binding obligation of Seller, enforceable against it in accordance with its and their respective terms, except as limited by bankruptcy or other similar Laws applicable generally to creditors’ rights and as limited by general equitable principles.

7.4 No Conflict. Seller’s execution and delivery of this Agreement and the Operative Documents to which it is a party and the consummation of the transactions contemplated by this Agreement or such Operative Documents by it will not:

7.4.1 conflict with or require the consent of any Person under any of the terms, conditions or provisions of the governing documents of Seller;

7.4.2 violate any provision of, or require any consent or approval under any Laws (except for consents and approvals of Governmental Authorities customarily obtained subsequent to transfer);

7.4.3 result in the creation or imposition of any lien or encumbrance upon one or more of the Properties other than a Permitted Encumbrance.

7.5 Transfer Requirements. Except for the Transfer Requirements set forth on Schedule 7.5: Seller’s execution and delivery of this Agreement and the Operative Documents to which it is a party and the consummation of the transactions contemplated by this Agreement or such Operative Documents by it (including the assignment of any of the Properties to Buyer) will not conflict with, result in a breach of, constitute a default under or constitute an event that with notice or lapse of time, or both, would constitute a default under, accelerate or permit the acceleration of the performance required by, or require any consent, authorization, waiver or approval under any of the Material Contracts.

7.6 Compliance with Laws. Seller and its Affiliates are in material compliance with all Applicable Laws (excluding Environmental Laws, which are addressed in other provisions of this Agreement) with respect to the ownership and, if operated by Seller or its Affiliates, operation of the Properties. In the three year period immediately preceding the date of execution of this Agreement, no written notice of a material violation of or default has been received with respect to any Law applicable to the Properties (excluding Environmental Laws, which are addressed in other provisions of this Agreement).

7.7 Certain Environmental Notices and Obligations. Notwithstanding any provision to the contrary in this Agreement, the representations and warranties contained in this Section 7.7 are the sole and exclusive representations and warranties of Seller pertaining or relating to matter arising under or with respect to Environmental Laws, Environmental Conditions or any other environmental matter. Except as set forth on Schedule 7.7, in the three year period immediately preceding the date of execution of this Agreement, to Seller’s Knowledge, no unresolved written notice has been received from any Governmental Authority alleging that a violation of Environmental Law has occurred at any Property. Except as disclosed on Schedule 7.7, to Seller’s Knowledge, there is no agreement with any Governmental Authority that (a) is in existence as of the date of this Agreement, (b) is based on any Environmental Laws that relate to the present or future use of any of the Properties, and (c) requires any Remediation or imposes any material liability on the owner or operator of, any of the Properties.

7.8 Litigation and Claims. Except for the litigation, claims or other matters set forth on Schedule 7.8, no material suit, action, demand, proceeding, lawsuit or other litigation is pending or, to Seller’s Knowledge, threatened with respect to the Properties. There are no material Third Party claims, disputes pending or, to Seller’s Knowledge, threatened that would prevent the consummation of the transactions contemplated by this Agreement or the performance of its obligations hereunder.

7.9 Material Contracts.

7.9.1 Schedule 7.9 describes the following Contracts to which Seller or its Affiliate is a party and that apply to or burden the Properties as of the date of this Agreement:

(i) all area of mutual interests agreements and agreements that include non-competition restrictions or other similar restrictions on doing business, all purchase or sale agreements (other than with respect to production of Hydrocarbons in the ordinary course or the acquisition or disposition of Facilities with a value of less than $1,000,000), partnership agreements, joint venture and exploration or development program agreements;

(ii) all of the Hydrocarbons production sales or purchase, transportation, storage, marketing, supply, exchange and processing agreements with a value in excess of $1,000,000, other than such agreements that are terminable on not more than 30 days’ notice without penalty or the payment of money;

(iii) any contracts or agreements which could reasonably be expected to obligate Buyer to expend in excess of $1,000,000 in any calendar year;

(iv) other than contracts governing the sale of Hydrocarbons, any contracts or agreements under which Seller has received in excess of $1,000,000 of revenues net of direct expenses in any calendar year;

(v) any contracts or agreements providing for a call upon, option to purchase or similar right under any agreements with respect to the Hydrocarbons;

(vi) any contract or agreement for capital expenditures or the acquisition or construction of fixed assets that requires aggregate future payments in excess of $1,000,000;

(vii) other than (a) this Agreement and the Operative Documents, (b) contracts or agreements governing the sale of Hydrocarbons or (c) the disposition in the ordinary course of Facilities no longer suitable for Hydrocarbons field operation, any contract or agreement for, or that contemplates, the sale, exchange or transfer of any of Seller’s interest in the Properties;

(viii) any unit agreement and any operating agreement; and

(ix) any other contracts or agreements which involve future payments or obligations in excess of $1,000,000.

The contracts and agreements described in Sections 7.9.1(i) through (ix) above, together with any Contracts entered into after the date of execution of this Agreement that would have been required to be set forth on Schedule 7.9 if such Contracts had been entered into prior to the date of execution of this Agreement, are collectively referred to herein as the “Material Contracts”.

7.9.2 Except as disclosed in Schedule 7.9, Seller is not nor, to Seller’s Knowledge, is any other party, in breach or default under, or learned of the occurrence of any event that with notice or the passage of time would constitute a breach or default under, any of the Material Contracts, Leases or Surface Interests. Each of the Material Contracts, Leases and Surface Interests are in full force and effect (except, in the case of

Surface Interests, where any failure to be in full force and effect would not materially interfere with or prevent operations as currently conducted on the Property or Properties related thereto) and, except as permitted pursuant to Section 9.2, have not been modified or amended in any material respect. Prior to the execution of this Agreement, Seller furnished to Buyer true and complete copies of each Material Contract, Lease and Surface Interest and all amendments thereto.

7.10 Governmental Permits. The applicable operator has obtained all material Permits required to be obtained to own or operate each Well associated with the Properties.

7.11 Payment of Royalties; Suspense Funds. All delay rentals, royalties, shut-in royalties, overriding royalties, compensatory royalties and other payments due with respect to the Properties (other than royalties held in suspense and in good faith by Seller) have been properly and correctly paid. The suspended funds held by Seller and owed to Third Parties for royalties with respect to the Properties as of the Effective Time are set forth on Schedule 7.11.

7.12 Imbalances. To Seller’s knowledge, there are no Imbalances existing with respect to the Properties as of the date hereof.

7.13 Non-Consent Operations. There are no operations (including drilling operations) associated with the Properties with respect to which Seller is currently or will become a non-consenting or non-participating party.

7.14 Current Commitments. Schedule 7.14(a) contains a true and complete list, as of the date of execution of this Agreement, of (i) all authorizations for expenditures for all drilling operations applicable to the Properties in excess of $250,000 or for capital expenditures to such Properties in excess of $250,000 that have been proposed by any Person with respect to periods on or after the Effective Time and accepted by Seller and (ii) all authorizations for expenditure in excess of $250,000 and written commitments for all drilling operations in excess of $250,000 applicable to such Properties or for other capital expenditures to such Properties in excess of $250,000 for which all of the activities approved in such authorizations for expenditures or commitments have not been completed by the Effective Time. Schedule 7.14(b) contains a true and complete list, as of the execution date of this Agreement, of all such proposed authorizations for expenditure that have been rejected by Seller within the six-month period immediately prior to the date hereof.

7.15 Taxes.

7.15.1 All Property Taxes and Severance Taxes that are due by Seller have been timely paid or are being contested in good faith. All Tax Returns, reports, statements and similar filings required by applicable Law with respect to the Properties due on or prior to the Closing Date have been timely filed. There are no extensions or waivers of any statute of limitations with respect to such Taxes or Tax liens burdening the Properties except for liens for current Taxes not yet due and payable.

7.15.2 Except for the Raven Ridge Pipeline Company, none of the Properties are subject to tax partnership reporting requirements under applicable provisions of the Code.

7.15.3 Seller is not a “foreign person” within the meaning of Code Section 1445.

7.15.4 Notwithstanding any other provision in this Agreement to the contrary, the representations and warranties in this Section 7.15 are the only representations and warranties in this agreement with respect to Taxes.

7.16 Finder’s Fees. Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees with respect to this transaction for which Buyer will have any responsibility whatsoever.

7.17 Operation of the Properties. For the period between the Effective Time and the date of execution of this Agreement the Properties have been operated in the ordinary course of business consistent with past practices.

7.18 Title to Facilities. Seller has good and marketable title or a valid leasehold interest in all of the Facilities that are material to Seller’s ownership or operation of the Properties.

7.19 Guarantees. To Seller’s Knowledge, Schedule 7.19 sets forth a complete and accurate list of all bonds, letters of credit, guarantees or other surety arrangements posted or entered into by Seller to the extent exclusively in connection with the ownership or operation of the Properties.

7.20 Knowledge Qualifier for Non-Operated Assets. To the extent that Seller has made any representations or warranties in this Article 7 in connection with matters which are both (i) relating to Non-Operated Properties, and (ii) not within Seller’s control or administration, each and every such representation and warranty shall be deemed to be qualified by the phrase, “To Seller’s Knowledge.”

ARTICLE 8

REPRESENTATIONS AND WARRANTIES OF BUYER

Buyer represents and warrants to Seller that each of the statements made in this Article 8 is true and correct as of the date of this Agreement and will be true and correct as of the Closing Date.

8.1 Organization. Buyer is a limited liability company duly organized, validly existing and in good standing under the laws of Delaware. Buyer is in good standing and duly qualified to do business in each other jurisdiction in which the conduct of its business or ownership or leasing of its properties makes such qualification or registration necessary.

8.2 Authority. Buyer has all requisite limited liability company power and authority to execute and deliver this Agreement and the Operative Documents to which it is a party, to consummate the transactions contemplated by this Agreement and the Operative Documents to which it is a party and to perform all of its obligations under this Agreement and the Operative Documents to which it is a party.

8.3 Enforceability. This Agreement has been duly executed and delivered on behalf of Buyer and constitutes (and the Operative Documents to which it is a Party, when executed and delivered at Closing, will constitute) a legal, valid and binding obligation of Buyer, enforceable against it in accordance with its and their respective terms, except as limited by bankruptcy or other similar Laws applicable generally to creditors’ rights and as limited by general equitable principles.

8.4 No Conflicts. Neither the execution and delivery of this Agreement, nor the consummation of the transactions contemplated hereby, nor the compliance with the terms hereof will result in any default under any material agreement or instrument to which Buyer is a party (including its governing documents), or violate any order, writ, injunction, decree, statute, rule or regulation applicable to Buyer or any of its properties, except for consents and approvals of Governmental Authorities customarily obtained subsequent to transfer.

8.5 No Further Distribution. Buyer is not acquiring the Properties in contemplation of a distribution thereof in violation of the Securities Act of 1933, as amended, or any Laws pertaining to the distribution of securities.

8.6 Finder’s Fees. Buyer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees in respect to this transaction for which Seller will have any responsibility whatsoever.

8.7 Independent Evaluation. Buyer is an experienced and knowledgeable investor in the oil and gas industry and the business of owning and operating assets similar to the Properties. In making the decision to enter into this Agreement and to consummate the transactions contemplated hereby, Buyer has relied on its own independent due diligence investigation of the Seller and the Properties (including any physical or virtual data room materials), and has been advised by and has relied solely on its own expertise and legal, land, tax, reservoir engineering, and other professional counsel concerning this transaction, the Properties and the respective values thereof.

ARTICLE 9

COVENANTS OF THE PARTIES

9.1 Access.

9.1.1 Subject to Section 6.1, Seller will give Buyer and its authorized representatives reasonable access, at Buyer’s sole risk and expense, from the date hereof until the Closing Date during normal business hours, to (i) the Records and (ii) the Properties operated by Seller, and with respect to the Properties not operated by Seller, Seller shall use Commercially Reasonable Efforts to obtain access for Buyer to such Properties as it may reasonably request.

9.1.2 Buyer shall release, indemnify and hold harmless Seller Group from and against any and all Claims arising from Buyer’s or any of its authorized representatives’ inspection of or access to (including any access granted to Buyer and its authorized representatives pursuant to Section 6.1) the Properties (including Claims for personal injuries, property damage and reasonable attorneys’ and experts’ fees, and specifically to the extent of Claims arising out of or partially or fully caused by the negligence of Seller Group). Notwithstanding the foregoing, in no event shall Buyer be required to release, indemnify and hold harmless Seller Group for any Claims (i) to the extent that such indemnified event or occurrence is caused by or the result of gross negligence or willful misconduct of Seller Group, and (ii) with respect to any pre-existing Environmental Conditions identified by or on behalf of Buyer as a result of any physical inspection, due diligence activities or access granted to Buyer and its authorized representatives pursuant hereto, provided that Buyer does not exacerbate any such pre-existing Environmental Condition.

9.2 Conduct of Business Pending Closing. From the date hereof to the Closing Date, except (i) as provided herein, (ii) as required by Law or any obligation, agreement, Lease, contract or instrument referred to on any Exhibit or Schedule, (iii) as may be undertaken by Seller in order to transition and prepare the Properties for acquisition by Buyer and to consummate the transaction contemplated by this Agreement or any Operative Document or (iv) as otherwise consented to in writing by Buyer (such consent not to be unreasonably withheld, conditioned or delayed), Seller will:

9.2.1 operate and maintain the Properties in the normal and customary manner, consistent with prior practice;

9.2.2 not dispose of or relinquish any of the Properties (other than relinquishment resulting from the expiration of a non-producing Lease still in its primary term, the abandonment of a Lease not operated by a Seller or the disposition of any Facility in the normal and customary manner, consistent with prior practice employed by Seller with respect to the Properties);

9.2.3 not waive, compromise or settle, or violate, breach or default under, any material right or Claim with respect to any of the Properties;

9.2.4 not, except with respect to those matters identified in Schedule 7.14, make or enter into an agreement to make, terminate or amend an agreement for capital expenditures or workover expenditures with respect to the Properties in excess of $250,000 (net to Seller’s interest), except when required by an emergency when there is insufficient time to obtain advance consent (provided, that Seller will promptly notify Buyer of any such emergency expenditures);

9.2.5 not incur Liabilities with respect to the Properties for which Buyer would be responsible after Closing, other than transactions in the normal and customary manner, of a nature and in an amount (not to exceed $100,000), consistent with past practices employed by Seller with respect to the Properties (counting Liabilities arising from one transaction or a series of similar transactions, and all periodic installments or payments under any lease or other agreement providing for periodic installments or payments, as a single Liability);

9.2.6 not permit, allow or suffer any of the Properties to be subject to any encumbrances that would impose any Liability, other than Permitted Encumbrances;

9.2.7 not cancel any indebtedness owed to Seller or its Affiliates that is fairly attributable to the Properties for the period of time on or after the Effective Time;

9.2.8 maintain insurance coverage on the Assets presently furnished by nonaffiliated Third Parties in the amounts and of the types set forth on Schedule 9.2.8,

9.2.9 not, except as otherwise provided in this Agreement or in the normal and customary manner, consistent with past practices employed by Seller with respect to the Properties, (i) amend or terminate, or violate, breach, or default under, any Material Contract, or (ii) enter into any Material Contract.

9.3 Consents and Approvals. Each Party will:

9.3.1 use Commercially Reasonable Efforts to give notices to, make filings with, and obtain (other than by the payment of money by Seller, unless to be reimbursed by Buyer pursuant to Section 9.3.4) authorizations, consents and approvals of any Third Parties, in each case, to the extent necessary for the consummation of the transactions contemplated hereby;

9.3.2 provide such other information and communications to Governmental Authorities or other Persons as the other Party may reasonably request in connection with such transactions;

9.3.3 cooperate with the other Party as promptly as practicable in obtaining all consents, approvals or actions of, making all filings with, and giving all notices to, Third Parties required of Buyer to consummate such transactions; and

9.3.4 Notwithstanding anything to the contrary in this Agreement, if the Closing occurs, Buyer shall be responsible for, and shall reimburse Seller for, all assignment, consent or transfer payments, premiums, fees or penalties that Seller is required to pay to any Third Party to the extent set forth in any agreement, Lease, contract or instrument referred to on any Exhibit or Schedule (collectively, the “Assignment Premiums”).

9.4 Confidentiality. The Parties will remain subject to the Confidentiality Agreement until Closing, at which time the Confidentiality Agreement will terminate (except as to (i) such portion of the Assets that are not conveyed to Buyer pursuant to the provisions of this Agreement, (ii) the Excluded Assets and (iii) information related to assets other than the Properties).

9.5 Public Announcements. The Parties agree that prior to making any public announcement or statement with respect to the transactions contemplated by this Agreement, the

Party desiring to make such public announcement or statement will obtain approval of the other Party to the text of a public announcement or statement to be made solely by Seller, on the one hand, or Buyer, on the other, as the case may be, which approval shall not be unreasonably withheld or delayed; provided, however, if Seller, on the one hand, or Buyer, on the other are required by Law or the rules of a national securities exchange to make such public announcement or statement, then the same may be made without the approval of (but with concurrent written notice to) the other Party provided such announcement or statement provides only such information as is reasonably determined by the disclosing Party to be required, advisable or customary.

9.6 Affiliate Contracts. Schedule 9.6 sets forth, as of the date hereof, all contracts or agreements with any Affiliate of Seller that relate to the Properties or by which the Properties are bound. Seller will terminate or cause its respective Affiliates to terminate, effective as of the Closing Date, any contracts or agreements between Seller and its respective Affiliates to the extent relating to or binding the Properties.

9.7 Satisfaction of Conditions. Each Party will use Commercially Reasonable Efforts to take all actions and to do all things necessary to consummate, make effective and comply with all of the terms of this Agreement (including satisfaction, but not waiver, of the Closing conditions for which they are responsible or otherwise in control).

9.8 Successor Operator. While Buyer acknowledges that it desires to succeed Seller as operator of those Properties or portions thereof that Seller may presently operate, Buyer acknowledges and agrees that Seller cannot and does not covenant or warrant that Buyer shall become successor operator of such Properties because the Properties or portions thereof may be subject to operating or other agreements that control the appointment of a successor operator. Seller agrees, however, that as to the Properties it operates, it shall use its Commercially Reasonable Efforts to support Buyer’s efforts to become successor operator of such Properties (to the extent permitted under any applicable operating agreement) effective as of Closing (at Buyer’s sole cost and expense) and to designate and/or appoint, to the extent legally possible and permitted under any applicable operating agreement, Buyer as successor operator of such Properties effective as of Closing.

9.9 Replacement of Bonds. Buyer acknowledges that none of the bonds, letters of credit, guarantees or other surety arrangements, if any, posted or obtained by Seller or its Affiliates relating to the ownership or operation of the Properties are transferable to Buyer. On or before the Closing Date, Buyer shall obtain, or cause to obtained in the name of Buyer, replacements for the bonds, letters of credit, guarantees and other surety arrangements set forth on Schedule 7.19, to the extent such replacements are necessary to permit the cancellation and release of such bonds, letters of credit, guarantees or other surety arrangements. In addition, at or prior to Closing, Buyer shall deliver to Seller evidence of the posting or obtaining of such bonds, letters of credit, guarantees and other surety arrangements.

9.10 Amendment of Schedules. Each Party agrees that, with respect to the representations and warranties of such Party contained in this Agreement, such Party shall have the continuing right until Closing to add, supplement or amend the Schedules to its representations and warranties with respect to any matter hereunder arising or discovered which,

if existing or known at the date hereof or thereafter, would have been required to be set forth or described in such Schedules. For all purposes of this Agreement, including for purposes of determining whether the conditions set forth in Article 12 or Article 13, as applicable, have been fulfilled, the Schedules shall be deemed to include only the information contained therein on the date of this Agreement and shall be deemed to exclude all information contained in any addition, supplement or amendment thereto; provided, however, that if Closing occurs, then any such disclosed matters that gave rise to a right of termination of this Agreement by the other Party shall be deemed waived by the other Party, and the other Party shall not be entitled to make a claim thereon under this Agreement or otherwise with respect to such matters.

ARTICLE 10

CASUALTY LOSS

10.1 Notice of Casualty Loss Prior to Closing. If, between the date hereof and the Closing, any portion of the Properties are damaged or destroyed by fire or other casualty (not including normal wear and tear, downhole mechanical failure or reservoir changes) or if any portion of the Properties are taken by condemnation or under the right of eminent domain and such damage, destruction or condemnation has an adverse affect on the value of the affected Properties in an amount that exceeds $1,000,000 (all of which are herein called “Casualty Loss” and are limited to property damage or taking only), Seller shall notify Buyer promptly after Seller learns of such event.

10.2 Casualty Loss.

10.2.1 Seller shall have the right, but not the obligation, to cure a Casualty Loss that consists of property damage by repairing the affected Property to the state existing immediately prior to the Casualty Loss no later than the Closing Date.

10.2.2 If any uncured Casualty Loss exists at the Closing, Seller and Buyer shall (i) convey the affected Properties as of Closing without an adjustment to the Purchase Price and (ii) Seller shall assign to Buyer any and all insurance proceeds, Third Party Claims and other payments associated with or attributable to such Casualty Loss.

ARTICLE 11

[RESERVED]

ARTICLE 12

CONDITIONS PRECEDENT TO THE OBLIGATIONS OF SELLER

The obligations of Seller to be performed at the Closing are subject to the fulfillment (or waiver by Seller in its sole discretion), before or at the Closing, of each of the following conditions:

12.1 Representations and Warranties. The representations and warranties by Buyer set forth in Article 8, without giving effect to any “materiality” qualifications therein, shall be true and correct on and as of the date hereof and as of the Closing Date as though made on and as of the Closing Date (except for representations and warranties that expressly speak as of a specified date, which representations and warranties shall be true and correct as of such specified date), except for such failures to be true and correct as would not in the aggregate have a material effect on the ability of Buyer to consummate the transactions contemplated by this Agreement.

12.2 Covenants. Buyer shall have performed and complied with in all material respects all covenants and agreements required to be performed and satisfied by it at or prior to Closing.

12.3 No Litigation, Orders or Laws. There shall be no legal action or proceeding instituted by a Governmental Authority having appropriate jurisdiction or any other Person seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated under the terms of this Agreement. There shall be no Laws, order (including temporary restraining order), decree or judgment of any Governmental Authority having appropriate jurisdiction restraining, enjoining or otherwise prohibiting the consummation of the transactions contemplated herein.

12.4 Right to Terminate. Neither Party is entitled to and has exercised its right to terminate this Agreement pursuant to Article 15.

ARTICLE 13

CONDITIONS PRECEDENT TO THE OBLIGATIONS OF BUYER

The obligations of Buyer to be performed at the Closing are subject to the fulfillment (or waiver by Buyer in its sole discretion), before or at the Closing, of each of the following conditions:

13.1 Representations and Warranties. The representations and warranties of Seller set forth in Article 7, without giving effect to any “materiality” or “Material Adverse Effect” qualifications therein, shall be true and correct on the date hereof and as of the Closing Date as though made on and as of the Closing Date (except for representations and warranties that expressly speak as of a specified date, which representations and warranties shall be true and correct as of such specified date), except for such failures to be true and correct as would not in the aggregate have a Material Adverse Effect.

13.2 Covenants. Seller shall have performed and complied with in all material respects all covenants and agreements required to be performed and satisfied by it at or prior to Closing.

13.3 No Litigation, Orders or Laws. There shall be no legal action or proceeding instituted by a Governmental Authority having appropriate jurisdiction or any other Person seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated under the terms of this Agreement. There shall be no Laws, order (including

temporary restraining order), decree or judgment of any Governmental Authority having appropriate jurisdiction restraining, enjoining or otherwise prohibiting the consummation of the transactions contemplated herein.

13.4 Right to Terminate. Neither Party is entitled to and has exercised its right to terminate this Agreement pursuant to Article 15.

ARTICLE 14

CLOSING

14.1 The Closing. The closing of the purchase and sale of the Properties pursuant to this Agreement (“Closing”) will be held at Seller’s offices at 425 Houston Street, Suite 300, Fort Worth, Texas 76102 on the fifth day after the later to occur of (i) August 1, 2017 or (ii) the date that the conditions to the Closing set forth in Article 12 and Article 13 have been satisfied or waived (other than the conditions which by their nature can be satisfied only at the Closing) or such other Business Day as may be mutually agreed by the Parties (subject to Section 4.7.2 and Section 6.6.2, the “Closing Date”).

14.2 Closing Deliveries. At Closing the following events will occur, each event under the control of one Party being a condition precedent to the events under the control of the other Party, and the Parties will treat each event as if it occurred simultaneously with the other events:

14.2.1 Seller will execute and deliver to Buyer, and Buyer will execute and receive, one or more instruments of assignment, in substantially the form of the Conveyance, Assignment and Bill of Sale set forth as Exhibit C (the “Conveyance”);

14.2.2 Buyer will deliver via wire transfer to an account specified by Seller, in immediately available funds, the Closing Purchase Price minus the amount of the Escrow Funds;

14.2.3 Seller will execute and deliver to Buyer any applicable governmental transfer form required by the Governmental Authority with jurisdiction over the Properties;

14.2.4 Seller will execute and deliver a non-foreign tax affidavit in substantially the form set forth in Exhibit D and Form W9 (Request for Taxpayer Identification Number and Certification);

14.2.5 Buyer will deliver to Seller a certificate, dated as of the Closing Date and executed by an officer of Buyer, that the conditions set forth in Section 12.1 and Section 12.2 have been fulfilled;

14.2.6 Buyer will deliver to Seller a certificate, dated as of the Closing Date, and executed by the Secretary or any Assistant Secretary of Buyer:

(i) certifying and attaching current organizational documents of Buyer;

(ii) certifying and attaching current good standing documents of Buyer;

(iii) certifying and attaching current resolutions of Buyer approving this Agreement and the transactions under this Agreement; and

(iv) certifying the incumbency of the officers executing this Agreement and all related agreements, in form and substance reasonably satisfactory to Seller.

14.2.7 Seller will deliver to Buyer a certificate, dated as of the Closing Date, and executed by an officer of Seller that the conditions set forth in Section 13.1 and Section 13.2 have been fulfilled;

14.2.8 Seller will deliver to Buyer a certificate, dated as of the Closing Date, and executed by the Secretary or any Assistant Secretary of Seller:

(i) certifying and attaching current organizational documents of Seller;

(ii) certifying and attaching current good standing documents of Seller;

(iii) certifying and attaching current resolutions of Seller approving this Agreement and the transactions under this Agreement; and

(iv) certifying the incumbency of the officers executing this Agreement and all related agreements, in form and substance reasonably satisfactory to Buyer.

14.2.9 Each Party will execute and deliver to the other Party a copy of the Preliminary Settlement Statement.

14.2.10 Each Party will execute and deliver to the other Party and to the Escrow Agent joint written instructions authorizing the Escrow Agent to release to Seller the Escrow Funds.

14.2.11 Seller will deliver to Buyer evidence of the release of all encumbrances on the Properties (other than Permitted Encumbrances) that secure any Indebtedness of Seller.

14.2.12 Seller will execute and deliver to Buyer any other instruments and agreements (including ratification or joinder instruments required to transfer Properties from Seller to Buyer) as are necessary or appropriate to comply with Seller’s obligations under this Agreement.

ARTICLE 15

TERMINATION AND REMEDIES

15.1 Termination. This Agreement may be terminated prior to Closing as provided below.

15.1.1 The Parties may terminate this Agreement by mutual written consent at any time prior to the Closing Date.

15.1.2 Buyer may terminate this Agreement at any time prior to the Closing Date if there has been a material breach of any of the representations, warranties, agreements or covenants set forth in this Agreement by Seller that (i) has rendered the satisfaction of any conditions set forth in Article 13 permanently incapable of fulfillment, (ii) has not been waived by Buyer, and (iii) is not capable of being cured prior to the Outside Date or is not cured by the earlier of (a) 10 days following Buyer’s written notice to Seller of such breach and (b) the Outside Date; provided that the right to terminate this Agreement under this Section 15.1.2 shall not be available to Buyer if it is then in material breach of any representation, warranty, covenant, or other agreement contained herein.

15.1.3 Seller may terminate this Agreement at any time prior to the Closing Date if there has been a material breach of any of the representations, warranties, agreements or covenants set forth in this Agreement by Buyer that (i) has rendered the satisfaction of any conditions set forth in Article 12 permanently incapable of fulfillment, (ii) has not been waived by Seller, and (iii) is not capable of being cured prior to the Outside Date or is not cured by the earlier of (a) 10 days following Seller’s written notice to Buyer of such breach and (b) the Outside Date; provided that the right to terminate this Agreement under this Section 15.1.3 shall not be available to Seller if it is then in material breach of any representation, warranty, covenant, or other agreement contained herein.

15.1.4 Either Party may terminate this Agreement if there occurs Casualty Losses that decrease the value of the Properties by more than 20% of the Purchase Price;

15.1.5 Either Party may terminate this Agreement if Closing has not occurred on or before the Outside Date; provided, however, that no Party may terminate this Agreement pursuant to this Section 15.1.5 if such Party’s failure to comply with its obligations under this Agreement caused the Closing not to occur on or before the Outside Date.

15.1.6 Either Party may terminate this Agreement, if consummation of the transaction contemplated by this Agreement would violate any non-appealable final order, decree or judgment of any Governmental Authority permanently enjoining, restraining, prohibiting or awarding substantial damages in connection with (i) Seller’s proposed sale of Properties to Buyer, or (ii) consummation of the transactions contemplated by this Agreement.

15.1.7 Either Party may terminate this Agreement if the aggregate of the following amounts exceeds 25% of the Purchase Price: (i) the Uncured Title Defects Value plus (ii) the Unremedied Environmental Conditions Amount plus (iii) the aggregate reduction in Purchase Price pursuant to Title Defect Removals and Environmental Condition Removals; provided, however, that any Title Defects or Environmental Defects that Seller has remediated shall not be included in such calculation.

15.2 Notice of Termination. A Party exercising its right of termination hereunder shall deliver notice to the other Party in accordance with Section 20.1 and within any applicable time periods contemplated by Section 15.1.

15.3 Effect of Termination

15.3.1 If this Agreement is terminated pursuant to Section 15.1, all obligations of the Parties under this Agreement will terminate and the Parties shall have no liability or obligation hereunder, except that the obligations of the Parties in this Section 15.3 and in Section 9.4, Section 9.5, Section 18.5, Section 20.11 and Article 19 will survive.

15.3.2 If Seller is entitled to terminate this Agreement pursuant to Section 15.1.3, then, in such event, Seller shall have the option to either (i) terminate this Agreement and cause the Escrow Agent to release to Seller the Escrow Funds (and if Seller so elects, Buyer and Seller shall promptly deliver duly executed joint written instructions to the Escrow Agent directing the Escrow Agent to make such release), in which event such Escrow Funds shall constitute liquidated damages hereunder and shall be the sole and exclusive remedy available to Seller for any such wrongful failure to perform at Closing or other uncured material breach of this Agreement by Buyer, or (ii) be entitled to all rights and remedies available at law or in equity for any breach of this Agreement by Buyer, including the right to specific performance and injunctive relief. Seller and Buyer acknowledge and agree that if Seller exercises the option under Section 15.3.2(i) to receive the Escrow Funds, then (a) Seller’s actual damages are difficult to ascertain with any certainty, (b) the Escrow Funds are a fair and reasonable estimate by the Parties of such actual damages of the Seller and (c) such liquidated damages do not constitute a penalty.

15.3.3 If Buyer is entitled to terminate this Agreement pursuant to Section 15.1.2, then, in such event, Buyer shall have the option to either (i) terminate this Agreement and cause the Escrow Agent to release to Buyer the Escrow Funds (and if Buyer so elects, Seller and Buyer shall promptly deliver duly executed joint written instructions to the Escrow Agent directing the Escrow Agent to make such release) or (ii) be entitled to all rights and remedies available at law or in equity for any breach of this Agreement by Seller, including the right to specific performance and injunctive relief. Buyer and Seller acknowledge and agree that if Buyer exercises the option under Section 15.3.3(i) to receive the Escrow Funds, then (a) the Escrow Funds shall constitute liquidated damages hereunder and shall be the sole and exclusive remedy available to Buyer for any breach of this Agreement by Seller, and (b) (1) Buyer’s actual damages are difficult to ascertain with any certainty, (2) the Escrow Funds are a fair and reasonable estimate by the Parties of such actual damages of the Buyer and (3) such liquidated damages do not constitute a penalty.

15.3.4 If this Agreement is terminated pursuant to Section 15.1.1, or if either Party is entitled to terminate this Agreement pursuant to Sections 15.1.4, 15.1.5, 15.1.6, or 15.1.7, then, in such event, either Party may cause the Escrow Agent to release to Buyer the Escrow Funds (and if either Party so elects, Seller and Buyer shall promptly deliver duly executed joint written instructions to the Escrow Agent directing the Escrow Agent to make such release), free of any claims by either Party against the other with respect thereto.

ARTICLE 16

ACCOUNTING MATTERS

16.1 Preliminary Settlement Statement. Seller will prepare, in accordance with this Agreement, a statement (“Preliminary Settlement Statement”), and deliver a copy to Buyer no later than five days prior to the Closing Date, setting forth Seller’s good faith estimate of each adjustment to the Purchase Price and the calculations of such adjustments in accordance with Article 3. Buyer will have three days after receipt of the Preliminary Settlement Statement to review such statement and to object to any item therein by written notice to Seller. To the extent reasonably requested by Buyer and reasonably available to Seller, Seller shall provide any data and documentation supporting the calculations set forth in the Preliminary Settlement Statement. Buyer’s notice will clearly identify any item(s) objected to and the reasons and support for the objection(s). The Parties shall attempt to agree on the amount of the Closing Purchase Price to be paid at the Closing no later than one Business Day prior to Closing. If the Parties do not agree by that date, Seller’s good faith estimate shall be used to determine the adjustments to the Purchase Price. If Buyer does not provide written objection(s) within the three day period, the Parties will treat the Preliminary Settlement Statement as correct and agreed for purposes of determining the Closing Purchase Price.

16.2 Final Settlement Statement.

16.2.1 After the Closing, Seller will prepare, in accordance with this Agreement, a settlement statement (“Final Settlement Statement”), and deliver a copy to Buyer no later than 180 days after the Closing Date, setting forth its determination of each adjustment to the Purchase Price necessary to determine the Final Purchase Price and showing the calculation of such adjustments in accordance with Article 3. Buyer will have 30 days after receipt of the Final Settlement Statement to review such statement and to object to any item therein by written notice to Seller. To the extent reasonably requested by Buyer and reasonably available to Seller, Seller shall provide any data and documentation supporting the calculations set forth in the Final Settlement Statement. Buyer’s notice will clearly identify the item(s) objected to and the reasons and support for the objection(s). If Buyer does not provide written objection(s) within the 30 day period, the Parties will treat the Final Settlement Statement as correct and the Final Purchase Price will not be subject to further adjustment. If Buyer timely objects, the Parties will

treat the Final Settlement Statement as correct with respect to the items not objected to, and Buyer and Seller will meet to negotiate and resolve the objections within 15 days of Seller’s receipt of Buyer’s objections. If the Parties agree on all objections, the Parties will treat the adjusted Final Settlement Statement as correct and the Final Purchase Price will not be subject to further adjustment. Any items not agreed to at the end of the 15-day period may, upon either Party’s written request, be resolved by arbitration in accordance with Section 16.2.2.

16.2.2 If the Parties do not agree upon the Final Settlement Statement, the Parties will promptly submit the disputed matters to the Independent Accounting Firm, which will act as an arbitrator and promptly decide all points of disagreement with respect to the Final Settlement Statement. Absent manifest error, the Independent Accounting Firm will determine the Final Purchase Price by selecting, with respect to each item in dispute, an amount equal to the Seller’s position or the Buyer’s position. The Independent Accounting Firm will act for the limited purpose of determining the specific disputed matters submitted by either Party and may not award damages or penalties to either Party with respect to any matter. The Independent Accounting Firm’s decision will be final and binding on the Parties and shall not be subject to appeal or further review. Any court of competent jurisdiction may enforce the decision against either Party. The costs and expenses of such arbitrator shall be borne by Seller and Buyer in inverse proportion as they may prevail on matters resolved by the Independent Accounting Firm, which inverse proportionate allocations shall also be determined by the Independent Accounting Firm at the time the determination of the Independent Accounting Firm is rendered on the merits of the matters submitted.

16.2.3 If the Final Purchase Price is more than the Closing Purchase Price, Buyer will pay such difference to Seller via wire transfer to an account specified by Seller, in immediately available funds, within five Business Days after the Final Settlement Statement has been agreed by the Parties or decided by arbitration, as applicable. If the Final Purchase Price is less than the Closing Purchase Price, Seller will pay such difference to Buyer via wire transfer to an account specified by Buyer, in immediately available funds, within five Business Days after the Final Settlement Statement has been agreed by the Parties or decided by arbitration, as applicable.

16.3 Post-Closing Revenues. Buyer shall pay to Seller any and all amounts received after Closing by Buyer (to the extent not accounted for in the Preliminary Settlement Statement or the Final Settlement Statement) that are attributable to the ownership of the Properties prior to the Effective Time. Seller shall pay to Buyer any and all amounts received after Closing by Seller (to the extent not accounted for in the Preliminary Settlement Statement or the Final Settlement Statement) that are attributable to the ownership of the Properties on or after the Effective Time. The Party responsible for the payment of amounts received shall reimburse the other Party within 15 Business Days after the end of the month in which such amounts were received by the Party responsible for payment and no further adjustments shall be made with respect to such amounts in the Final Settlement Statement.

16.4 Post-Closing Expenses. Seller shall reimburse Buyer for any and all costs and disbursements paid after Closing by Buyer that are attributable to the ownership of the Properties

prior to the Effective Time, but solely to the extent (i) such costs and disbursements should have been accounted for in the Preliminary Settlement Statement or the Final Settlement Statement as adjustments to the Purchase Price pursuant to Section 3 and (ii) not duplicative of any adjustments to the Purchase Price already made pursuant to Section 3 or disputed and finally resolved by the Independent Accounting Firm pursuant to Section 16.2.2. Buyer shall reimburse Seller for any and all costs and expenses paid after Closing by Seller that are attributable to the ownership of the Properties on or after the Effective Time, but solely to the extent (i) such costs and expenses should have been accounted for in the Preliminary Settlement Statement or Final Settlement Statement as adjustments to the Purchase Price pursuant to Section 3 and (ii) not duplicative of any adjustments to the Purchase Price already made pursuant to Section 3 or disputed and finally resolved by the Independent Accounting Firm pursuant to Section 16.2.2. The Party responsible for the payment of such costs and expenses shall reimburse the other Party within 15 Business Days after the end of the month in which the applicable invoice and proof of payment of such invoice were received by the Party responsible for payment and no further adjustments shall be made with respect to such amounts in the Final Settlement Statement.

16.5 Audits. Subject to and in coordination with Section 19.4, (i) Seller Group shall have the right to conduct, control and participate in audits related to joint operations provided for under any operating or other agreement relating to the Properties in accordance with the terms thereof to the extent any such audit relates to the period of time prior to the Effective Time or related to periods starting prior to the Effective Time and ending after the Effective Time, (ii) after the Closing, Buyer Group shall have the right to conduct, control and participate in audits related to joint operations provided for under any operating or other agreement relating to the Properties in accordance with the terms thereof to the extent any such audit relates to the period of time on or after the Effective Time and is not subject to clause (i) above, and (iii) no audit Claim or audit Liability of Seller Group or Buyer Group related to joint operations under any operating or other agreement relating to the Properties in accordance with the terms thereof is waived or released by Seller Group or Buyer Group under this Agreement, nor shall any indemnity in this Agreement affect any such audit Claim or audit Liability by Seller Group or Buyer Group related to joint operations under any operating or other agreement relating to the Properties in accordance with the terms thereof to the extent any such audit relates to the period prior to the Closing Date.

ARTICLE 17

CERTAIN POST-CLOSING COVENANTS

17.1 Further Assurances. The Parties acknowledge and agree that the Oil and Gas Properties (other than Wells) include all of the First PSA Properties that were acquired by Seller pursuant to the First PSA. To the extent that any of the First PSA Properties are not included in the Oil and Gas Properties, the Parties agree to make such modifications or take such actions as are necessary to include such First PSA Properties. Similarly, to the extent that any of the Oil and Gas Properties (other than Wells) were not included in the First PSA Properties, the Parties agree to make such modifications or take such actions as are necessary to remove such Oil and Gas Properties (other than Wells). After the Closing, the Parties will execute, acknowledge and deliver or cause to be executed, acknowledged and delivered such instruments and take such

other action as may be reasonably necessary or advisable to carry out its obligations under this Agreement and under any exhibit, document, certificate or other instrument delivered pursuant hereto. Without limiting the generality of the foregoing, after the Closing, Seller will promptly execute and deliver, or cause to be executed and delivered, at Seller’s expense, to Buyer all instruments of transfer, powers of attorney and other documents, in addition to those otherwise required by this Agreement, as may be required by Buyer in form and substance reasonably satisfactory to Buyer, and take all other action necessary or advisable, to (i) vest in Buyer title to, or rights, privileges, powers and franchises in, the Properties in accordance with this Agreement, and (ii) perfect or confirm and record the sale to Buyer of the Properties. Seller will use Commercially Reasonable Efforts to cooperate with Buyer’s efforts to obtain all approvals and consents required by or necessary for the transactions contemplated by this Agreement.

17.2 Delivery of Records by Seller. Within ten days after Closing, Seller will deliver to Buyer the originals of all Records, except that Seller may retain (i) the originals of all Records which are related to properties other than the Properties being sold herein, in which case Seller will deliver duplicate copies of any such retained originals to Buyer, and (ii) the originals of all accounting Records, in which case Seller will deliver duplicate copies of any such retained originals which relate to the Properties to Buyer. For a period of three years after the date of Closing, Buyer will retain the Records delivered to them pursuant hereto and will make such Records available to Seller upon reasonable notice at Buyer’s offices at reasonable times and during office hours.

17.3 Use of Seller’s Name. Buyer agree that within 60 days after Closing they will remove or cause to be removed the names and marks of Seller and its Affiliates, including “Titan”, “ARP” or “Atlas” and all variations and derivatives thereof and logos relating thereto from the Properties of which they have assumed operations and will not thereafter make any use whatsoever of such names, marks and logos.

17.4 Suspense Funds. Within 90 days after the Closing, Seller will provide to Buyer a listing showing all funds from production attributable to the Properties that are currently held in suspense by Seller. At Closing, Seller will assign to Buyer all of its rights in and to such suspense funds created after the Effective Time (the “Post-Effective Time Suspense Funds”). After Closing, Buyer will be responsible for proper distribution of all the Post-Effective Time Suspense Funds attributable to the Properties to the parties lawfully entitled to them, and hereby agrees to indemnify, defend, and hold harmless Seller from and against any and all Claims arising out of or relating to Buyer’s retention or distribution of the Post-Effective Time Suspense Funds. Notwithstanding the foregoing, this Section 17.4 shall not apply to Seller’s Retained Liabilities or suspense funds that are or were required by Laws to be escheated to Governmental Authorities prior to or as of the Effective Time.

ARTICLE 18

INDEMNIFICATION

18.1 Seller’s Indemnity. After Closing, Seller will release, defend, indemnify and hold harmless Buyer Group, subject to and in accordance with this Article 18, from and against

any and all Claims brought against or suffered by Buyer Group arising from, relating to or connected with, directly or indirectly, any of the following:

18.1.1 any breach of the representations and warranties of Seller in this Agreement;

18.1.2 any breach of any covenant set forth in this Agreement; and

18.1.3 Seller’s Retained Liabilities.

18.2 Limitations on Seller’s Indemnity.

18.2.1 Seller shall have no obligation to indemnify Buyer Group for any Claims arising pursuant to Sections 18.1.1 or 18.1.2 with respect to which Buyer has not delivered written notice thereof to Seller within six months after Closing.

18.2.2 With respect to Seller’s indemnification obligations under Section 18.1.1 Seller shall have no obligation to indemnify Buyer Group:

(i) with respect to any individual Claim of less than $200,000, provided that if a Claim for which indemnification is permitted exceeds such amount, then the entire amount of such Claim shall be counted towards the threshold set forth in Section 18.2.2(ii); and

(ii) unless and until the amount of aggregate Claims for which indemnification is permitted pursuant to Section 18.2.2(i) exceeds $3,150,000, and then Seller shall be obligated to indemnify Buyer Group only to the extent of the amount by which such aggregate Claims exceeds $3,150,000.

18.2.3 Seller’s aggregate indemnification liability under Section 18.1.1 shall be limited to an amount equal to 10,500,000.

18.2.4 Notwithstanding any provision of this Agreement to the contrary, Section 18.2.1, Section 18.2.2 and Section 18.2.3 shall not apply to Seller’s indemnification obligations for any breach of Seller’s (i) representations and warranties in Section 7.1, Section 7.2, Section 7.3, Section 7.4 and Section 7.16, which shall survive Closing indefinitely, (ii) representations and warranties in Section 7.15 and covenants with respect to Taxes in Article 19, which shall survive the Closing for the applicable statute of Tax limitations plus 30 days, and (iii) covenants in Article 17, which shall survive the Closing in accordance with their respective terms.

18.2.5 Seller’s aggregate indemnification liability under this Agreement shall be limited to an amount equal to the Purchase Price.

18.2.6 Seller shall not be required to indemnify and hold harmless Buyer Group for any Claim pursuant to Section 18.1 to the extent the matter giving rise to such Claim was taken into account in the computation of the Final Purchase Price.

18.3 Survival of Seller’s Representations and Warranties. The representations and warranties made by Seller in this Agreement shall survive Closing for the period contemplated by Section 18.2.1 and Section 18.2.4, and shall be actionable during such period (but not thereafter, excluding claims made in good faith prior to the end of such period) in accordance with this Article 18.

18.4 Buyer’s Indemnity. Except to the extent of Seller’s Indemnification Obligations set forth in Section 18.1, after Closing, Buyer will release, defend, indemnify and hold harmless Seller Group, subject to and in accordance with this Article 18, from and against any and all Claims brought against or suffered by Seller Group arising from, relating to or connected with, directly or indirectly, any of the following:

18.4.1 any breach of the representations and warranties of Buyer in this Agreement;

18.4.2 any breach of any covenant set forth in this Agreement; and

18.4.3 the Assumed Liabilities.

18.5 Limitations of Warranties.

18.5.1 Except as otherwise set forth in this Agreement or in the Conveyance, the Properties are being sold by Seller to Buyer without warranty of any kind, express, implied, or statutory. Without limiting the generality of the immediately preceding sentence and except as set forth in this Agreement, Seller conveys the Properties as-is, where-is and with all faults and expressly disclaims and negates any implied or express warranty of (i) merchantability, (ii) fitness for a particular purpose, (iii) conformity to models or samples of materials and (iv) freedom from redhibitory vices or defects. Except as otherwise set forth in this Agreement, Seller also expressly disclaims and negates any implied or express warranty at common law, by statute or otherwise relating to the accuracy of any of the information furnished with respect to the existence or extent of reserves or the value of the Properties based thereon, the condition or state of repair of any of the Properties; this disclaimer and denial of warranty also extends to the express or implied representation or warranty as to the prices Buyer and Seller are or will be entitled to receive from production of Hydrocarbons from the Properties, it being understood that all reserve, price and value estimates upon which Buyer has relied or is relying have been derived by the individual evaluation of Buyer. Buyer hereby waives any warranty or representation, express or implied, with respect to the accuracy, completeness or materiality of the information, reports, projections, materials, records, and data now, heretofore, or hereafter furnished or made available to Buyer in connection with the Properties, except as set forth in this Agreement (including any description of the quality or quantity of Hydrocarbon reserves (if any), production rates, recompletion opportunities, decline rates, pricing assumptions, ability or potential for production of Hydrocarbons from the Properties, environmental condition of the Properties, or any other matters contained in any other material furnished or made available to Buyer by Seller or

by Seller’s agents or representatives). Other than as set forth in this Agreement, any and all such information, reports, projections, materials, records, and data now, heretofor or hereafter furnished by Seller is provided as a convenience only and any reliance on or use of same is at Buyer’s sole risk. Without limiting the foregoing, Buyer hereby releases and disclaims any and all causes of action that Buyer may have against Seller with respect to any Environmental Condition or any other rights that Buyer may have against Seller pursuant to any Environmental Law, including any right of contribution or claim for response costs pursuant to CERCLA. With respect to the Surface Interests, Seller expressly disclaims any representations or warranties that they are contiguous; that the Facilities lie within the Surface Interests, or that they grant the right to lay, maintain, repair, replace, operate, construction, or remove any Facilities. Subject to the provisions of this Agreement, if necessary, Buyer shall secure its own rights and permits to operate and maintain any Facilities on the land of others at its own expense. There are no warranties that extend beyond the face of this Agreement and the Conveyance.

18.5.2 Buyer acknowledges and affirms that it has reviewed the foregoing disclaimer and other provisions and agrees that such disclaimer and provisions are “conspicuous.”

18.6 Notice of Claims. If a Claim is asserted against a Party for which the other Party may have an obligation of indemnity and defense (whether under this Article 18 or any other provision of this Agreement), the Party seeking indemnification (“Indemnified Party”) shall give the Party from which the Indemnified Party seeks indemnification (“Indemnifying Party”) prompt written notice of the Claim, setting forth the particulars associated with the claim (including a copy of the written Claim, if any) as then known by the Indemnified Party (“Claim Notice”); provided, however, that no delay on the part of the Indemnified Party in notifying the Indemnifying Party will relieve the Indemnifying Party of any liability or obligation hereunder, except to the extent that the Indemnifying Party clearly demonstrates that the defense of any Third Party suit, action or proceeding has been materially prejudiced by the Indemnified Party’s failure to promptly give such notice.

18.7 Defense of Claims. Within 30 days after the Indemnifying Party receives a Claim Notice, the Indemnifying Party shall notify the Indemnified Party whether or not the Indemnifying Party will assume responsibility for defense and payment of the Claim. The Indemnified Party is authorized, prior to and during such 30-day period, to file any motion, pleading or other answer that it deems necessary or appropriate to protect its interests, or those of the Indemnifying Party, and that is not prejudicial to the Indemnifying Party. If the Indemnifying Party elects not to assume responsibility for defense and payment of the Claim, the Indemnified Party may defend against, or enter into any settlement with respect to, the Claim as it deems appropriate without relieving the Indemnifying Party of any indemnification obligations the Indemnifying Party may have with respect to such Claim. The Indemnifying Party’s failure to respond in writing to a Claim Notice within the 30-day period shall be deemed an election by the Indemnifying Party not to assume responsibility for defense and payment of the Claim. If the Indemnifying Party elects to assume responsibility for defense and payment of the Claim: (i) the Indemnifying Party shall defend the Indemnified Party against the Claim with counsel of the Indemnifying Party’s choice (reasonably acceptable to the Indemnified Party, which shall

cooperate with the Indemnifying Party in all reasonable respects in such defense); (ii) the Indemnifying Party shall pay any judgment entered or settlement with respect to such Claim; (iii) the Indemnifying Party shall not consent to entry of any judgment or enter into any settlement with respect to the Claim that (a) does not include a provision whereby the plaintiff or claimant in the matter releases the Indemnified Party from all liability with respect to the Claim or (b) contains terms that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity); and (iv) the Indemnified Party shall not consent to entry of any judgment or enter into any settlement with respect to the Claim without the Indemnifying Party’s prior written consent. In instances where an actual conflict arises between the Indemnifying Party and the Indemnified Party, the Indemnified Party may employ separate counsel and participate in defense of a Claim and the Indemnified Party shall bear all fees and expenses of counsel employed by the Indemnified Party.

18.8 Specific Performance; Scope of Remedies. Each Party hereby acknowledges that the rights of each Party to consummate the transactions contemplated hereby are special, unique and of extraordinary character and that, in the event that either Party materially breaches any of its representations, warranties, agreements or covenants set forth in this Agreement that (i) has rendered the satisfaction of any conditions set forth in Article 12 or Article 13 (as applicable) permanently incapable of fulfillment, (ii) has not been waived by the other Party, and (iii) is not capable of being cured prior to the Outside Date or is not cured by the earlier of (a) 10 days following the other Party’s written notice to such Party of such breach and (b) the Outside Date, the other Party may be without an adequate remedy at law. In such event, provided that the other Party has not elected to receive the Escrow Funds under Section 15.3.2(i) or Section 15.3.3(i), as applicable, the other Party is entitled to, subject to the other terms hereof and in addition to any remedy at law for damages or other relief, institute and prosecute an action in any court of competent jurisdiction to enforce specific performance of such covenant or agreement or seek any other equitable relief. If Closing occurs, the indemnities set forth in this Agreement shall be the exclusive remedy under, arising out of or relating to this Agreement, whether based in contract, tort, strict liability, statute, common law or otherwise; provided, however, that the foregoing shall not in any way limit Seller’s liability with respect to Seller’s special warranty of title set forth in the Conveyance. Seller and Buyer acknowledge that, following the Closing, the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for any breach of any representation, warranty, covenant or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated hereby. As the payment of money shall be adequate compensation, following Closing, Seller and Buyer waive any right to rescind this Agreement or any of the transactions contemplated hereby. Notwithstanding the foregoing, nothing in this Section 18.8 is intended to limit the rights of the Parties under applicable Laws in the event of fraud or intentional misrepresentation.

18.9 Extent of Indemnification. Without limiting or enlarging the scope of the indemnification, defense, release, disclaimer and assumption provisions set forth in this Agreement, to the fullest extent permitted by Law, an Indemnified Party shall be entitled to indemnification pursuant to the provisions of this Article 18 in accordance with the terms hereof, regardless of whether the indemnifiable loss giving rise to any such indemnification obligation is the result of the sole, active, passive, concurrent or comparative negligence, strict liability, breach of duty (statutory or otherwise), or other fault or violation of any Law of or by any such Indemnified Party, or any pre-existing defect; provided, that no

indemnification pursuant to any provision of this Agreement shall be applicable to the extent that gross negligence or willful misconduct of the Indemnified Party caused or contributed to the indemnifiable loss.

18.10 Tax Treatment of Indemnification Payments. Except as otherwise required by applicable law, the Parties shall treat any indemnification payment made hereunder as an adjustment to the Purchase Price.

ARTICLE 19

TAXATION

19.1 Responsible Party. All Taxes attributable to the ownership or operation of the Properties prior to the Effective Time are Seller’s responsibility and all deductions, credits or refunds pertaining to the aforementioned Taxes, no matter when received, belong to Seller. All Taxes attributable to the ownership or operation of the Properties on or after the Effective Time (excluding Seller’s income taxes, franchise taxes or margin taxes through Closing, and excluding income or capital gains taxes from the sale of the Properties) are the responsibility of Buyer, and all deductions, credits or refunds pertaining to the aforementioned Taxes, no matter when received, belong to Buyer. Property Taxes not based on production shall be prorated based on a percentage of the assessment period occurring before the Effective Time. Property Taxes based on production (other than Severance Taxes) shall be deemed by the Parties to apply to production in the Tax period for which the Tax is levied. The Parties shall estimate all Taxes (excluding Seller’s income taxes, franchise taxes or margin taxes) attributable to the ownership or operation of the Properties to the extent they relate to the period on and after the Effective Time and prior to Closing and incorporate such estimate into the Preliminary Settlement Statement. The actual amounts (to the extent the same differ from the estimate included in the Preliminary Settlement Statement) shall be accounted for in the Final Settlement Statement. All Tax Returns required to be filed with respect to the Properties for a Taxable period ending prior to or including the Closing Date shall be filed by Seller. Seller shall consult in good faith with Buyer regarding any Tax Returns required to be filed by Seller after the Effective Time that include periods starting before the Effective Time and ending after the Effective Time. Unless required by applicable law, (i) no amended Tax Return with respect to a Pre-Closing Tax Period shall be filed by or with respect to the Properties and (ii) no Tax election shall be made what has retroactive effect on or with respect to Seller or the Properties for any Pre-Closing Tax period, without the prior written consent of Seller.

19.2 Transfer Taxes. Notwithstanding anything to the contrary herein, it is acknowledged and agreed by and between Seller and Buyer that the Purchase Price excludes any sales taxes or other Taxes of a similar nature in connection with the sale of property pursuant to this Agreement. Buyer and Seller will use Commercially Reasonable Efforts and cooperate in good faith to exempt the sale, conveyance, assignments and transfers to be made to Buyer from any sales, use, stamp, real estate transfer, documentary, registration, recording and other similar Taxes (each a “Transfer Tax”). If a determination is ever made that a Transfer Tax applies, Buyer will bear such Transfer Tax.

19.3 Allocation of Values. Seller and Buyer agree that the transaction under this Agreement is subject to the reporting requirement of Code Section 1060 and, therefore IRS Form 8594 (Asset Acquisition Statement Under Section 1060) is required to be and will be filed for this transaction. No later than 30 days after delivery of the Final Settlement Statement, Seller will prepare a draft Form 8594 and deliver a copy thereof to Buyer. Thereafter, Seller and Buyer will confer and cooperate in good faith in the preparation and filing of their respective forms to reflect a consistent reporting of the agreed upon allocation. In the event that the allocation is disputed by any Taxing authority, the Party receiving notice of such dispute will promptly notify and consult with the other Party in good faith and keep the other Party apprised of material developments concerning resolution of such dispute.

19.4 Tax Contests. Seller shall have the right, at the sole expense of Seller, to control any audit or examination by any Taxing authority, initiate any claim for refund, and contest, resolve and defend against any assessment, notice of deficiency, or other adjustment or proposed adjustment relating to any and all Taxes for which Seller has any responsibility under this Agreement (“Tax Contest”). Buyer agrees to cooperate with Seller with respect to any Tax Contest, as and to the extent reasonably requested by Seller, and shall furnish or cause to be furnished to Seller, upon request, as promptly as practicable and at Seller’s expense, such information and assistance relating to such Tax Contest (including access to books and records) as is reasonably necessary for the preparation for any Tax Contest. Buyer shall not settle, compromise or otherwise resolve any audit, examination, assessment or other adjustment or proposed adjustment relating to any Taxes for which Seller has any responsibility under this Agreement without Seller’s prior written consent, which shall not be unreasonably withheld.

ARTICLE 20

MISCELLANEOUS

20.1 Notice. All notices required or permitted under this Agreement must be in writing and delivered personally, by email (with confirmation of delivery) or by certified mail, postage prepaid and return receipt requested as follows:


Seller:		Titan Energy, LLC
		1845 Walnut Street, Suite 1000
		Philadelphia, PA 19103
		Attention: Joel S. Heiser
		Email: jheiser@atlasenergy.com

		with a copy to:

		Titan Energy, LLC
		1845 Walnut Street, Suite 1000
		Philadelphia, PA 19103
		Attention: Lisa Washington
		Email: lwashington@atlasenergy.com


		with a copy (which shall not constitute notice) to:

		Jones Day
		717 Texas, Suite 3300
		Houston, TX 77002
		Attention: Omar Samji
		Email: osamji@jonesday.com

Buyer:		MMGJ Colorado, LLC
		13727 Noel Road, Ste. 1200
		Dallas, Texas 75240
		Attention: Legal Department
		Email: chris.hagge@meritenergy.com

		with a copy to:

		MMGJ Colorado, LLC
		13727 Noel Road, Ste. 1200
		Dallas, Texas 75240
		Attention: Acquisitions Department
		Email: jason.lindmark@meritenergy.com

or to such other place within the United States of America as either Party may designate as to itself by written notice to the other. All notices given by personal delivery or mail will be effective on the date of actual receipt at the appropriate address or on the date receipt is rejected at such address.

20.2 Governing Law. This Agreement, the obligations of the Parties under this Agreement and all other matters arising out of or relating to this Agreement and the transactions it contemplates, will be governed by and construed in accordance with the Laws of the State of Texas, without giving effect to any conflicts of law principles that would cause the laws of another jurisdiction to apply. Any dispute arising out of or relating to this Agreement which cannot be amicably resolved by the Parties, shall be brought in a federal or state court of competent jurisdiction sitting in Harris County of the State of Texas and the Parties irrevocably submit to the jurisdiction of any such court solely for the purpose of any such suit, action or proceeding.

20.3 Assignment. This Agreement will be binding upon and will inure to the benefit of the Parties and their respective permitted successors and assigns. Notwithstanding the preceding sentence, except as permitted below, prior to Closing neither Party may assign this Agreement or its rights under this Agreement or delegate any performance obligations under this Agreement without the other Party’s written consent, which will not be unreasonably withheld. Buyer will, without the obligation to obtain the prior written consent of Seller but with the obligation to provide contemporaneous or prior notice to Seller, be entitled to assign this Agreement or all or any part of its respective rights or and delegate its respective performance obligations under this Agreement to one or more Affiliates of Buyer, but no such assignment will

release or discharge Buyer from any of its obligations as the “Buyer” under this Agreement or any certificate, document, instrument or writing delivered pursuant hereto. Any purported assignment or delegation in violation of this Section 20.3 will provide the non-assigning party the right to void the assignment ab initio.

20.4 Entire Agreement. This Agreement, together with (i) the Exhibits and Schedules hereto, (ii) the certificates, documents, instruments and writings that are delivered pursuant hereto, and (iii) the Confidentiality Agreement, effective as of April 4, 2017, between Titan Energy Operating, LLC, an Affiliate of Seller, and Merit Energy Company, an Affiliate of Buyer (the “Confidentiality Agreement”), constitute the entire, complete and exclusive agreement and understanding of the Parties in respect of its respective subject matters and expressly supersedes all prior understandings, agreements or representations by or among the Parties, written or oral, to the extent they relate in any way to the subject matter hereof or the transactions contemplated hereby. The provisions of this Agreement may not be explained, supplemented or qualified through evidence of trade usage or a prior course of dealings. In entering into this Agreement, neither Party has relied upon a statement, representation, warranty or agreement of the other Party except for those expressly contained in this Agreement.

20.5 Amendment; Waiver. No amendment, modification, replacement, rescission, termination or cancellation of any provision of this Agreement will be valid, unless the same is in writing and signed by Buyer and Seller. No waiver by either Party of any default, misrepresentation or breach of warranty or covenant under this Agreement or course of dealing between the Parties, whether intentional or not, will extend to any prior or subsequent default, misrepresentation, or breach of warranty or covenant under this Agreement or affect in any way any rights arising because of any prior or subsequent such occurrence. No single or partial exercise of any right or remedy under this Agreement precludes the simultaneous or subsequent exercise of any other right or remedy.

20.6 Severability. If any term or other provision of this Agreement is held invalid or unenforceable by any court of competent jurisdiction, the other provisions of this Agreement shall remain in full force and effect. The Parties further agree that if any provision contained herein is, to any extent, held invalid or unenforceable in any respect under the Laws governing this Agreement, they shall take any actions necessary to render the remaining provisions of this Agreement valid and enforceable to the fullest extent permitted by applicable Law and, to the extent necessary, shall amend or otherwise modify this Agreement to replace any provision contained herein that is held invalid or unenforceable with a valid and enforceable provision giving effect to the intent of the Parties to the greatest extent legally permissible.

20.7 Construction. The Parties have participated jointly in the negotiation and drafting of this Agreement. If an ambiguity or question of intent or interpretation arises, this Agreement will be construed as if drafted jointly by the Parties and no presumption or burden of proof will arise favoring or disfavoring either Party because of the authorship of any provision of this Agreement. The Parties will treat the words “include,” “includes” and “including” as if followed by “without limitation.” Pronouns in masculine, feminine, and neuter genders will be construed to include any other gender, and words in the singular form will be construed to include the plural and vice versa, unless the context otherwise requires. All references to “$” or “dollars” shall be deemed references to U.S. dollars. Where a date or time period is specified, it

will be deemed inclusive of the last day in such period or the date specified, as the case may be. Unless expressly provided to the contrary, the word “or” is not exclusive. The words “this Agreement,” “herein,” “hereof,” “hereby,” “hereunder” and words of similar import refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited. The words “this Article,” “this Section,” “this subsection,” “this clause,” and words of similar import, refer only to the Article, Section, subsection and clause hereof in which such words occur. References herein to any Section or Article are references to a Section or Article of this Agreement unless the context clearly requires otherwise.

20.8 Headings. The Article and Section headings contained in this Agreement are inserted for convenience only and will not affect in any way the meaning or interpretation of this Agreement.

20.9 Counterparts. This Agreement may be executed in two (2) or more counterparts, each of which the Parties will treat as an original but all of which together will constitute one and the same instrument. The signatures of all the Parties need not appear on the same counterpart and delivery of an executed counterpart signature page of this Agreement (including by means of facsimile or email attaching a copy in portable document format (.pdf)) will be equally as effective as delivery of an original executed counterpart of this Agreement in the presence of the other Party. This Agreement is effective on the delivery of one (1) executed counterpart from each Party to the other Party.

20.10 Expenses and Fees. Except as expressly set forth herein, each Party will pay its own fees and expenses incident to the negotiation and preparation of this Agreement and consummation of the transactions contemplated hereby, including brokers’ fees. Buyer will be responsible for the cost of all fees for the recording of transfer documents and all fees charged by the Escrow Agent pursuant to the Escrow Agreement. The Party incurring any other costs will bear them.

20.11 Limitation on Damages. NOTWITHSTANDING ANY TERM OR PROVISION OF THIS AGREEMENT TO THE CONTRARY, IN NO EVENT WILL EITHER PARTY TO THIS AGREEMENT BE LIABLE TO THE OTHER PARTY FOR ANY CONSEQUENTIAL, INDIRECT, SPECIAL, EXEMPLARY, PUNITIVE OR SIMILAR DAMAGES ARISING OUT OF OR RELATING TO THIS AGREEMENT, EXCEPT TO THE EXTENT ANY SUCH PARTY WAS ACTUALLY REQUIRED TO PAY SUCH DAMAGES TO A THIRD PARTY IN CONNECTION WITH A CLAIM, IN WHICH EVENT SUCH DAMAGES SHALL BE RECOVERABLE HEREUNDER.

20.12 Third Party Beneficiaries. Nothing contained in this Agreement entitles anyone other than Buyer or Seller or their respective permitted successors and assigns to any rights under this Agreement, except with respect to waivers and indemnities that expressly provide for waivers or indemnification of Seller Group, Buyer Group or another Person, in which case members of such groups and such other Persons are considered third party beneficiaries for the sole purposes of those waiver and indemnity provisions and are bound by the procedures and limitations therein. The immediately preceding sentence notwithstanding, any claim for indemnity or defense under this Agreement may only be brought and administered by a Party to this Agreement. Each Party may elect to exercise or not exercise the indemnification and

defense rights under this Agreement on behalf of any member of Seller Group or Buyer Group, as applicable, and no member of any such group shall have any rights under this Agreement except to the extent exercised on its or his behalf by Seller or Buyer, as the case may be.

20.13 Survival of Certain Obligations. Except as expressly provided otherwise in this Agreement, (i) waivers, disclaimers, releases and obligations of indemnity and defense contained in this Agreement will survive the Closing in accordance with their terms, and (ii) to the extent performable after Closing, covenants contained in this Agreement (including any covenants set forth in Article 9 and Article 17) will survive Closing.

20.14 Bulk Transfer Laws. Buyer hereby waives compliance by Seller with the provisions of any so-called bulk transfer laws of any jurisdiction in connection with the transfer and conveyance of the Properties. For the avoidance of doubt, the term “bulk transfer laws” in this Section 20.14 shall not include any tax clearance or similar provisions.

20.15 Schedules. Any matter disclosed in any Section of the Schedules shall be considered disclosed with respect to each other Section of this Agreement to the extent the relevance thereto is reasonably apparent on its face. The inclusion of information in any Section of the Schedules shall not be construed as an admission that such information is material or that such matter actually constitutes compliance with, or a violation of, any Law, Permit, Contract or Lease or other topic to which such disclosure is applicable.

20.16 Conspicuousness. Each of the Parties hereto specifically acknowledges and agrees (i) that it has a duty to read this Agreement and that it is charged with notice and knowledge of the terms hereof, and (ii) that it has in fact read this Agreement and is fully informed and has full notice and knowledge of the terms, conditions and effects of this Agreement. Each Party hereto further agrees that it will not contest the validity or enforceability of any such provisions of this Agreement on the basis that the Party had no notice or knowledge of such provisions or that such provisions are not “conspicuous”. The Parties expressly hereby acknowledge and agree that the provisions contained in this Agreement that are set out in “bold” or in “ALL CAPS” satisfy the requirement of the “express negligence rule” and any other requirement at law or in equity that provisions contained in a contract be conspicuously marked or highlighted.

[Signature page follows.]

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first set forth above.


SELLER:

ARP RANGELY PRODUCTIONS, LLC

By:
Name:		Mark Schumacher
Title:		President

BUYER:

MMGJ COLORADO, LLC

By:
Name:
Title:

[Signature Page to PSA]

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first set forth above.


SELLER:

ARP RANGELY PRODUCTIONS, LLC

By:
Name:
Title:

BUYER:

MMGJ COLORADO, LLC

By:
Name:		Christopher S. Hagge
Title:		Vice President

[Signature Page to PSA]

Exhibit 99.1

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION

The following sets forth unaudited pro forma condensed consolidated financial information of Titan Energy, LLC (the “Company”) prepared in accordance with Article 11 of Regulation S-X. You should read this information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors,” and the Company’s consolidated financial statements and related notes and other financial information included in its most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. The unaudited pro forma condensed consolidated financial information is based on, and has been derived from, the Company’s historical consolidated financial statements.

On June 12, 2017, ARP Rangely Production, LLC, a wholly owned subsidiary of the Company, entered into a purchase and sale agreement with MMGJ Colorado, LLC, an affiliate of Merit Energy Company, LLC (the “Rangely Agreement”). Pursuant to the Rangely Agreement, the Company agreed to sell its 25% interest in the Rangely Field, a CO2 flood located in Rio Blanco County, Colorado and operated by Chevron, as well as its 22% interest in Raven Ridge Pipeline, a CO2 transportation line, and surrounding acreage in Rio Blanco and Moffat Counties, Colorado (collectively, the “Rangely Assets”). The Rangely Agreement provided for aggregate consideration of $105 million. On August 7, 2017, the Company completed the sale of the Rangely Assets for net cash proceeds of approximately $103.5 million, after giving effect to customary preliminary purchase price adjustments.

As previously disclosed, on May 4, 2017, the Company and certain of its subsidiaries entered into a purchase and sale agreement with Diversified Energy, LLC to sell its conventional Appalachia and Marcellus assets (the “Appalachia Assets”) for an aggregate of $84.2 million (the “Appalachia Asset Sale”). On June 30, 2017, the Company completed a majority of the Asset Sale for cash proceeds of approximately $66.6 million, which included customary purchase price adjustments. The Company expects to complete the remainder of the Appalachia Asset Sale for additional cash proceeds of approximately $11.4 million by September 2017. However, there can be no assurance that the conditions to the remainder of the Appalachia Asset Sale will be satisfied or waived on terms satisfactory to the parties or that the remainder of the Appalachia Asset Sale will ultimately be completed in whole or in part.

Also as previously disclosed, on September 1, 2016, Atlas Resource Partners, L.P., the Company’s predecessor (the “Predecessor”), substantially consummated its plan of reorganization (the “Plan”) and emerged from Chapter 11. Upon the consummation of the Plan, the Company adopted fresh-start accounting in accordance with ASC 852. Upon adoption of fresh-start accounting, the Company’s assets and liabilities were recorded at their fair values as of the effective date. The fair values of the Company’s assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in the Company’s historical consolidated balance sheets.

The unaudited pro forma condensed consolidated balance sheet as of March 31, 2017 and statements of operations for the year ended December 31, 2016 and the three months ended March 31, 2017 give pro forma effect to the following events as if they occurred on March 31, 2017 (in the case of the balance sheet) or January 1, 2016 (in the case of the statements of operations):

•

the previously disclosed adoption of fresh start accounting;

•

the initial Appalachia Asset Sale closing on June 30, 2017 (the “Appalachia Properties Sold”);

•

the remainder of the Appalachia Asset Sale, which is expected to occur by September 2017 (the “Appalachia Properties Subject to 2^nd Closing”); and

•

the completion of the sale of the Rangely Assets.

The unaudited pro forma condensed consolidated statements of operations for the years ended December 31, 2015 and 2014 give pro forma effect to the discontinued operations treatment of the Appalachia Assets (“Discontinued Operations”) as if such treatment had commenced on January 1, 2014.

The unaudited pro forma condensed consolidated financial information includes unaudited pro forma adjustments that are factually supportable and directly attributable to the respective transactions. In addition, the unaudited pro forma adjustments are expected to have a continuing impact on the Company’s results. The Company has prepared the unaudited pro forma condensed consolidated financial information for illustrative purposes only and it does not purport to represent what the results of operations or financial condition would have been had the respective transactions actually occurred on the dates indicated, nor does the Company purport to project the results of operations or financial condition for any future period or as of any future date. The actual results of operations may differ significantly from the pro forma amounts reflected herein due to a variety of factors.

TITAN ENERGY, LLC

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

MARCH 31, 2017

(in thousands)


			Appalachia Assets
	Historical March 31, 2017		Properties Sold Pro Forma Adjustments			Properties Subject to 2^nd Close Pro Forma Adjustments			Rangely Assets Pro Forma Adjustments			Pro Forma March 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	28,966	$	—		$	—		$	—		$	28,966
Accounts receivable		27,786	$	(2,238	)(a)		(218	)(a)		(7,429	)(s)		17,901
Advances to affiliates		10,251		—			—			—			10,251
Prepaid expenses and other		19,408		(480	)(a)					(4,562	)(s)		14,366

Total current assets		86,411		(2,718	)		(218	)		(11,991	)		71,484

Property, plant and equipment, net		780,930		(91,594	)(a)		(16,554	)(a)		(138,363	)(s)		534,419
Long-term derivative asset		1,227		(453	)(b)					685	(t)		1,459
Other assets, net		10,670		(551	)(c)		(657	)(c)		(3,661	)(u)		5,801

Total assets	$	879,238	$	(95,316	)	$	(17,429	)	$	(153,330	)	$	613,163

LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable	$	30,191	$	(3,734	)(a)	$	(794	)(a)	$	(3,876	)(s)	$	21,787
Liabilities associated with drilling contracts		5,787								—			5,787
Current portion of derivative liability		17,235		(2,737	)(b)					(2,221	)(t)		12,277
Accrued well drilling and completion costs		7,092								—			7,092
Accrued interest		1,643		(235	)(c)		(40	)(c)		(366	)(u)		1,002
Accrued liabilities		15,734		(501	)(a)		(274	)(a)		(1,262	)(s)		13,697
Current portion of long-term debt		701,602		(66,643	)(d)		(11,379	)(d)		(103,500	)(v)		520,080

Total current liabilities		779,284		(73,850	)		(12,487	)		(111,225	)		581,722

Long-term derivative liability		163		(9	)(b)					(76	)(t)		78
Asset retirement obligations		77,159		(60,929	)(a)		(894	)(a)		(1,015	)(s)		14,321
Other long-term liabilities		2,238		(1,501	)(a)		(403	)(a)		—			334
Commitments and contingencies
Members’ Equity (Deficit):
Series A Preferred members’ equity (deficit)		393		819	(e)		(73	)(e)		(820	)(w)		334
Common shareholders’ equity (deficit)		20,001		40,154	(e)		(3,572	)(e)		(40,194	)(w)		16,374

Total members’ equity (deficit)		20,394		40,973			(3,645	)		(41,014	)		16,708

Total liabilities and members’ equity (deficit)	$	879,238	$	(95,316	)	$	(17,429	)	$	(153,330	)	$	613,163

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

TITAN ENERGY, LLC

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2017

(in thousands, except per share and unit data)


	Three Months			Appalachia Assets									Pro Forma
	Ended March 31, 2017 Successor Titan			Properties Sold Pro Forma Adjustments			Properties Subject to 2^nd Close Pro Forma Adjustments			Rangely Assets Pro Forma Adjustments			Three Months Ended March 31, 2017
Revenues:
Gas and oil production	$	70,593		$	(10,783	)(f)	$	(1,164	)(f)	$	(10,706	)(x)	$	47,940
Drilling partnership management and other		10,050			(2,159	)(f)		(575	)(f)		(72	)(x)		7,244
Gain on mark-to-market derivatives		29,493			(4,565	)(g)					(4,185	)(y)		20,743

Total revenues		110,136			(17,507	)		(1,739	)		(14,963	)		75,927

Costs and expenses:
Gas and oil production		29,987			(3,199	)(f)		(337	)(f)		(6,504	)(x)		19,947
Drilling partnership management		8,171			(2,122	)(f)		(606	)(f)		—			5,443
General and administrative		13,758			(1,752	)(h)		(111	)(h)		—			11,895
Depreciation, depletion and amortization		16,492			(2,519	)(i)		(178	)(i)		(1,112	)(z)		12,683

Total costs and expenses		68,408			(9,592	)		(1,232	)		(7,616	)		49,968

Operating income		41,728			(7,915	)		(507	)		(7,347	)		25,959
Interest expense		(13,985	)		903	(j)		154	(j)		1,423	(aa)		(11,505	)
Loss on sale of assets		(207	)											(207	)
Other Loss		(447	)											(447	)

Income before income taxes		27,089			(7,012	)		(353	)		(5,924	)		13,800
Income tax provision (benefit)		180												180

Net income attributable to common shareholders and Series A preferred member	$	26,909		$	(7,012	)	$	(353	)	$	(5,924	)	$	13,620

Allocation of net income attributable to:
Series A Preferred member	$	538											$	272
Common shareholders	$	26,371											$	13,348

Net income attributable to common shareholders per share:
Basic	$	5.10											$	2.58

Diluted	$	4.81											$	2.43

Weighted average shares:
Basic		5,170												5,170

Diluted		5,486												5,486

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

TITAN ENERGY, LLC

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2016

(in thousands, except per share and unit data)


										Appalachia Assets
	Period from January 1 through August 31, 2016 Predecessor ARP			Period from September 30 through December 31, 2016 Successor Titan			Fresh Start Accounting Adjustments			Properties Sold Pro Forma Adjustments			Properties Subject to 2^nd Close Pro Forma Adjustments			Rangely Assets Pro Forma Adjustments			Pro Forma Year Ended December 31, 2016
Revenues:
Gas and oil production	$	139,094		$	86,936		$	(10,758	)(m)	$	(20,289	)(f)	$	(2,305	)(f)	$	(38,679	)(x)	$	153,999
Well construction and completion		19,157			2,236												—			21,483
Gathering and processing		3,929			2,159						(3,150	)(f)		(1,007	)(f)		—			1,931
Administration and oversight		1,263			708						(104	)(f)		(134	)(f)		—			1,733
Well services		11,226			3,704						(12,831	)(f)		(115	)(f)		—			1,984
Loss on mark-to-market derivatives		(23,916	)		(43,892	)					8,270	(g)					11,848	(y)		(47,690	)
Other, net		317			247												(190	)(x)		374

Total revenues		151,070			52,188			(10,758	)		(28,104	)		(3,561	)		(27,021	)		(133,814	)

Costs and expenses:
Gas and oil production		86,566			39,418						(9,932	)(f)		(620	)(f)		(26,073	)(x)		89,359
Well construction and completion		16,658			2,023												—			18,681
Gathering and processing		5,893			3,048						(4,990	)(f)		(1,824	)(f)		—			2,127
Well services		4,677			2,036						(3,106	)(f)		(345	)(f)		—			3,262
General and administrative		58,004			18,496			(858	)(n)		(15,808	)(h)		(169	)(h)		—			59,665
Depreciation, depletion and amortization		82,331			23,877			(31,300	)(o)		(9,431	)(i)		(812	)(i)		(3,805	)(z)		60,860

Total costs and expenses		254,129			88,898			(32,158	)		(43,267	)		(3,770	)		(29,878	)		233,954

Operating loss		(103,059	)		(36,710	)		21,400			15,163			209			2,857			(100,140	)
Interest expense		(74,587	)		(18,327	)		43,018	(p)		3,427	(j)		585	(j)		5,371	(aa)		(40,153	)
Gain (loss) on asset sales and disposal		(479	)		180												—			(299	)
Gain on early extinguishment of debt		26,498						(26,498	)(q)								—			—
Reorganization items, net		(16,614	)		(870	)		17,484	(r)								—			—
Other income (loss)		(9,189	)		22,413						(16,287	)(k)		3,063	(l)		—			—

		(74,371	)		3,396			34,004			(12,860	)		3,648			8,228			(140,952	)

Net loss
Preferred member / limited partner dividends		(4,013	)		—			4,013												—
Net loss attributable to common shareholders and preferred member	$	—		$	(33,314	)													$	(140,952	)

Net loss attributable to common limited partners and the general partner	$	(181,443	)	$	—															—

Allocation of net loss attributable to:
Series A Preferred member	$	—		$	(666	)													$	(2,819	)

Common shareholders	$	—		$	(32,648	)													$	(138,133	)

Common limited partners’ interest	$	(177,814	)	$	—														$	—

General partner interest	$	(3,629	)	$	—														$	—

Net loss attributable to common shareholders per share / common limited partner per unit:
Basic and diluted	$	(1.72	)	$	(6.03	)													$	(25.50	)

Weighted average shares / common limited partner units outstanding:
Basic and diluted		102,912			5,418														$	5,418

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

TITAN ENERGY, LLC

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2015

(in thousands, except per share and unit data)


	Predecessor Year Ended December 31, 2015			Discontinued Operations Adjustments			Predecessor Pro Forma Year Ended December 31, 2015
Revenues:
Gas and oil production	$	356,999		$	(16,522	)(f)	$	340,477
Well construction and completion		76,505			—			76,505
Gathering and processing		7,431			(5,046	)(f)		2,385
Administration and oversight		7,812			(1,784	)(f)		6,028
Well services		23,822			(14,135	)(f)		9,687
Gain on mark-to-market derivatives		267,223			(27,962	)(g)		239,261
Other, net		241			—			241

Total revenues		740,033			(65,449	)		674,584

Costs and expenses:
Gas and oil production		169,653			(16,201	)(f)		153,452
Well construction and completion		66,526						66,526
Gathering and processing		9,613			(8,512	)(f)		1,101
Well services		9,162			(8,890	)(f)		272
General and administrative		65,968			(9,099	)(h)		56,869
Depreciation, depletion and amortization		157,978			(8,396	)(i)		149,582
Asset impairment		966,635			(25,725	)(i)		940,910

Total costs and expenses		1,445,535			(76,823	)		1,368,712

Operating loss		(705,502	)		11,374			(694,128	)
Interest expense		(102,133	)		2,562	(j)		(99,571	)
Loss on asset sales and disposal		(1,181	)		—			(1,181	)

Net loss		(808,816	)		13,936			(794,880	)
Preferred limited partner dividends		(16,469	)					(16,469	)
Net loss attributable to common limited partners and the general partner	$	(825,285	)				$	(811,349	)

Allocation of net loss attributable to:
Common limited partners’ interest	$	(811,266	)				$	(795,122	)

General partner’s interest	$	(14,019	)				$	(16,227	)

Net loss attributable to common limited partners per unit:
Basic and diluted	$	(8.65	)				$	(8.48	)

Weighted average common limited partner units outstanding:
Basic and diluted		93,745						93,745

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

TITAN ENERGY, LLC

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2014

(in thousands, except per share and unit data)


	Predecessor Year Ended December 31, 2014			Discontinued Operations Adjustments			Predecessor Pro Forma Year Ended December 31, 2014
Revenues:
Gas and oil production	$	470,051		$	(56,808	)(f)	$	413,243
Well construction and completion		173,564			—			173,564
Gathering and processing		14,107			(11,903	)(f)		2,204
Administration and oversight		15,564			(2,019	)(f)		13,545
Well services		24,959			(15,263	)(f)		9,696
Gain on mark-to-market derivatives		2,819			—			2,819
Other, net		590			—			590

Total revenues		701,654			(85,993	)		615,661

Costs and expenses:
Gas and oil production		182,226			(23,118	)(f)		159,108
Well construction and completion		150,925			—			150,925
Gathering and processing		15,525			(14,422	)(f)		1,103
Well services		10,007			(9,735	)(f)		272
General and administrative		72,349			(5,200	)(h)		67,149
Depreciation, depletion and amortization		239,923			(31,853	)(i)		208,070
Asset impairment		573,774			(222,988	)(i)		350,786

Total costs and expenses		1,244,729			(307,316	)		937,413

Operating loss		(543,075	)		221,323			(321,752	)
Interest expense		(62,144	)		2,347	(j)		(59,797	)
Loss on asset sales and disposal		(1,869	)		—			(1,869	)

Net loss		(607,088	)		223,670			(383,418	)
Preferred limited partner dividends		(19,267	)					(19,267	)
Net loss attributable to common limited partners and the general partner	$	(626,355	)				$	(402,685	)

Allocation of net loss attributable to:
Common limited partners’ interest	$	(628,926	)				$	(394,631	)

General partner’s interest	$	2,571					$	(8,054	)

Net loss attributable to common limited partners per unit:
Basic and diluted	$	(8.42	)				$	(5.28	)

Weighted average common limited partner units outstanding:
Basic and diluted		74,716						74,716

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

TITAN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Appalachia Asset Sale Adjustments to the Unaudited Pro Forma Condensed Consolidated Balance Sheet

The following adjustments have been made to the accompanying unaudited pro forma condensed consolidated balance sheet as of March 31, 2017:

(a)	Reflects the elimination of assets and liabilities related to the Properties Sold and the Properties Subject to 2^nd Close.

(b)	Reflects the elimination of derivative activity allocated to the Properties Sold, which was based on the relative proportion of the natural gas and oil volumes produced by the Properties Sold to the Company’s total natural gas and oil volumes produced.

(c)

Other assets consists of pro forma adjustments of $0.6 million and $0.7 million of estimated deferred financing costs for Properties Sold and Properties Subject to 2^nd Close, respectively. Accrued interest consists of estimated pro forma adjustments of $0.2 million and $0.1 million for the Properties Sold and Properties Subject to 2^nd Close, respectively.

(d)

Reflects the receipt of net proceeds from the sale of the properties of $66.6 million, which included customary purchase price adjustments, and $11.4 million for Properties Sold and Properties Subject to 2^nd Close, respectively, the majority of which was used and will be used to repay a portion of the outstanding borrowings under the Company’s first lien credit facility.

(e)	Reflects the change in Members’ Equity due to the Properties Sold and Properties Subject to 2^nd Close pro forma adjustments.

Appalachia Asset Sale Adjustments to the Unaudited Pro Forma Condensed Consolidated Statement of Operations

The following adjustments have been made to the accompanying unaudited pro forma condensed consolidated statements of operations for the three months ended March 31, 2017 and the years ended December 31, 2016, 2015, and 2014:

(f)	Represents the elimination of gas and oil production revenues and expenses and drilling partnership management revenues and expenses for the Properties Sold, Properties Subject to 2^nd Close, and Discontinued Operations.

(g)

Reflects the elimination of the gain (loss) on mark-to-market activity allocated to each the Properties Sold and Discontinued Operations, which was based on the relative proportion of the natural gas and oil volumes produced by each the Properties Sold and the Discontinued Operations to the Company’s total natural gas and oil volumes produced.

(h)

Reflects the elimination of the direct general and administrative expenses associated with the Properties Sold, which includes a $10.9 million provision for losses on drilling partnership receivables related to the write down of certain receivables to their estimated net realizable values recognized during the Predecessor period January 1, 2016 through August 31, 2016, the Properties Subject to 2^nd Close and Discontinued Operations.

(i)

Represents the elimination of depreciation, depletion, and amortization expense, which includes accretion expenses for asset retirement obligations, related to the Properties Sold, Properties Subject to 2^nd Close, and Discontinued Operations. Represents the elimination of impairment expense related to Discontinued Operations for the years ended December 31, 2015 and 2014.

(j)	Reflects the reduction of interest expense associated with the repayment of borrowings outstanding under the Company’s first lien credit facility using proceeds from the Properties Sold, Properties Subject to 2^nd Close, and Discontinued Operations.

(k)

Represents the elimination of a $22.4 million non-cash gain recognized in other income (loss) during the Successor period September 1, 2016 through December 31, 2016 and a $6.1 million non-cash loss recognized in other income (loss) during the Predecessor period from January 1, 2016 through August 31, 2016 associated with certain drilling partnership consolidations that were directly attributable to the Properties Sold and are not expected to have a continuing effect on the results of operations.

(l)

Represents the elimination of a $3.1 million provision for losses recognized in other income (loss) during the Predecessor period from January 1, 2016 through August 31, 2016 associated with the adjustment of notes receivable with certain investors in the Company’s drilling partnerships to their net realizable value that are directly attributable to the Properties Subject to 2^nd Close and are not expected to have a continuing effect on the results of operations.

Fresh Start Accounting Adjustments:

(m)

Reflects the elimination from oil and gas revenues of the portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets, due to the Predecessor’s application of hedge accounting through December 31, 2014 as a result of the sale of the Predecessor’s commodity hedge positions pursuant to the restructuring support agreement entered into among the Predecessor and its creditors, pursuant to which the parties thereto agreed to support the Plan. Our Predecessor discontinued hedge accounting on January 1, 2015.

(n)	Reflects the change in general and administrative expense as a result of the Plan, as set forth in more detail below:


	For the Period from January 1, 2016 through August 31, 2016
Elimination of historical compensation expense related to Predecessor’s 2012 Long-Term Incentive Plan	$	(484	)
Elimination of historical compensation expense related to Successor’s MIP awards immediately vested		(669	)
Pro forma compensation expense related to Successor’s MIP awards not fully vested		295

Net pro forma adjustment to general and administrative expense	$	(858	)

(o)	Reflects the adjustments to depreciation, depletion and amortization expense for property, plant and equipment and asset retirement obligations accretion expense due to recording balances at fair value as a result of the adoption of fresh-start accounting, as follows:


	For the Period from January 1, 2016 through August 31, 2016
Elimination of historical depletion	$	(64,049	)
Elimination of historical accretion		(4,598	)
Pro forma depletion		33,030
Pro forma accretion		4,317

Net pro forma adjustment to depreciation, depletion and amortization expense	$	(31,300	)

(p)	Reflects the change in interest expense as a result of the Plan, as set forth in more detail below:


	For the Period from January 1, 2016 through August 31, 2016
Elimination of historical interest expense associated with:
7.75% Notes and 9.25% Notes	$	(32,566	)
Senior secured revolving credit facility		(15,517	)
Second lien credit agreement		(17,445	)
Capitalized interest		6,478
Amortization of deferred financing costs and debt discounts		(15,386	)
Pro forma interest expense associated with:
First Lien Exit Facility	$	14,541
Second Lien Exit Facility		23,853
Amortization of deferred financing costs		845
Capitalized interest		(7,821	)

Net pro forma adjustment to interest expense	$	(43,018	)

(q)	Reflects the elimination of the gain on extinguishment of debt as a result of the Plan.

(r)

Reflects the elimination of $16.6 million and $0.9 million of net reorganization items for the Predecessor period from January 1, 2016 through August 31, 2016 and the Successor period from September 1, 2016 through December 31, 2016 that were directly attributable to the consummation of the Plan and are not expected to have a continuing effect on the results of operations.

Rangely Asset Sale Adjustments to the Unaudited Pro Forma Condensed Consolidated Balance Sheet

The following adjustments have been made to the accompanying unaudited pro forma condensed consolidated balance sheet as of March 31, 2017:

(s)	Reflects the elimination of assets and liabilities related to the Rangely Assets. Accrued liabilities reflects the elimination of $2.6 million offset by a $1.3 million increase related to an estimated contingent liability resulting from the Rangely Assets sale.

(t)	Reflects the elimination of derivative activity allocated to the Rangely Assets, which was based on the relative proportion of the oil volumes produced by the Rangely Assets to the Company’s total oil volumes produced.

(u)

Reflects the elimination of other assets, which includes pro forma adjustments of $0.9 million of estimated deferred financing costs and $2.8 million related to the Company’s 22% investment in the Raven Ridge Pipeline for the Rangely Assets. Reflects the elimination of accrued interest, which consists of estimated pro forma adjustments of $0.4 million for the Rangely Assets.

(v)	Reflects the receipt of net proceeds from the sale of the properties of $103.5 million, which included customary purchase price adjustments for the Rangely Assets, all of which was used to repay a portion of the outstanding borrowings under the Company’s first lien credit facility.

(w)	Reflects the change in Members’ Equity due to the Rangely Assets pro forma adjustments.

Rangely Asset Sale Adjustments to the Unaudited Pro Forma Condensed Consolidated Statement of Operations

(x)	Represents the elimination of oil and natural gas liquids production revenues and expenses and other revenues for the Rangely Assets.

(y)	Reflects the elimination of the gain (loss) on mark-to-market activity allocated to the Rangely Assets, which was based on the relative proportion of the oil volumes produced by the Rangely Assets to the Company’s total oil volumes produced.

(z)	Represents the elimination of depreciation, depletion, and amortization expense, which includes accretion expenses for asset retirement obligations, related to the Rangely Assets.

(aa)	Reflects the reduction of interest expense associated with the repayment of borrowings outstanding under the Company’s first lien credit facility using proceeds from the Rangely Assets.

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 June 30, 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.

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 August 17, 2017 was 5,469,798.

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 June 30, 2017 and December 31, 2016		5
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2017 and 2016		6
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2017 and 2016		7
	Condensed Consolidated Statement of Changes in Members’ Equity (Deficit) for the Six Months Ended June 30, 2017		8
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 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		29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		42
Item 4.	Controls and Procedures		43
PART II. OTHER INFORMATION
Item 6.	Exhibits		44
SIGNATURES			45

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)


	June 30, 2017		December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents		16,247	$	24,446
Accounts receivable		20,908		26,472
Advances to affiliates		6,486		4,145
Subscriptions receivable		—		5,656
Prepaid expenses and other		12,578		17,108
Current assets held for sale (Note 3)		124,657		8,271

Total current assets		180,876		86,098
Property, plant and equipment, net		538,418		670,769
Long-term derivative asset		1,606		—
Other assets, net		7,250		10,562
Non-current assets held for sale (Note 3)		—		114,405

Total assets	$	728,150	$	881,834

LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	25,454	$	27,647
Liabilities associated with drilling contracts		—		10,656
Current portion of derivative liability		890		30,519
Accrued well drilling and completion costs		6,044		4,933
Accrued interest		1,287		1,503
Accrued liabilities		15,266		17,171
Current portion of long-term debt		643,378		694,810
Current liabilities held for sale (Note 3)		2,296		9,461

Total current liabilities		694,615		796,700
Long-term derivative liability		1		13,208
Asset retirement obligations		14,486		15,031
Other long-term liabilities		1,628		1,431
Non-current liabilities held for sale (Note 3)		—		62,405
Commitments and contingencies (Note 9)
Members’ Equity (Deficit):
Series A Preferred member’s equity (deficit)		323		(145	)
Common shareholders’ equity (deficit)		17,097		(6,796	)

Total members’ equity (deficit)		17,420		(6,941	)

Total liabilities and members’ equity (deficit)	$	728,150	$	881,834

See accompanying notes to condensed consolidated financial statements.

TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)


	Successor			Predecessor			Successor			Predecessor
	Three Months Ended June 30,						Six Months Ended June 30,

	2017			2016			2017			2016
Revenues:
Gas and oil production	$	53,939		$	47,527		$	113,506		$	92,787
Drilling partnership management		7,610			748			15,390			5,668
Gain (loss) on mark-to-market derivatives		14,788			(67,162	)		40,993			(25,601	)

Total revenues		76,337			(18,887	)		169,889			72,854

Costs and expenses:
Gas and oil production		25,077			29,188			52,722			62,411
Drilling partnership management		5,310			(837	)		9,778			1,306
General and administrative		10,929			20,934			22,819			36,808
Depreciation, depletion and amortization		12,806			25,311			26,468			52,687
Loss on divestiture		38,192			—			38,192			—

Total costs and expenses		92,314			74,596			149,979			153,212

Operating income (loss)		(15,977	)		(93,483	)		19,910			(80,358	)
Interest expense		(13,615	)		(30,545	)		(26,548	)		(56,972	)
Gain on early extinguishment of debt		—			—			—			26,498
Other income (loss)		(181	)		(543	)		(41	)		(533	)

Loss from continuing operations before income taxes		(29,773	)		(124,571	)		(6,679	)		(111,365	)
Income tax provision (benefit)		(9,653	)		—			(11,301	)		—

Net income (loss) from continuing operations		(20,120	)		(124,571	)		4,622			(111,365	)
Net income (loss) from discontinued operations		16,628			(16,998	)		18,789			(17,441	)

Net income (loss)		(3,492	)		(141,569	)		23,411			(128,806	)
Preferred limited partner dividends		—			(365	)		—			(4,013	)

Net income (loss) attributable to common shareholders and Series A preferred member	$	(3,492	)	$	—		$	23,411		$	—

Net loss attributable to common limited partners and the general partner		—			(141,934	)		—			(132,819	)

Allocation of net income (loss) attributable to :
Series A Preferred member		(70	)		—			468			—
Common shareholders		(3,422	)		—			22,943			—

Common limited partners’ interest	$	—		$	(139,096	)	$	—		$	(130,163	)
General partner’s interest		—			(2,838	)		—			(2,656	)
Net income (loss) attributable to common shareholders per share / common limited partners per unit (Note 2):
Basic income (loss) continuing operations	$	(3.81	)	$	(1.20	)	$	0.88		$	(1.10	)

Diluted income (loss) continuing operations	$	(3.81	)	$	(1.20	)	$	0.83		$	(1.10	)

Basic income (loss) from discontinued operations	$	3.15		$	(0.16	)	$	3.56		$	(0.17	)

Diluted income (loss) from discontinued operations	$	3.15		$	(0.16	)	$	3.37		$	(0.17	)

Weighted average common limited partner units outstanding (Note 2):
Basic		5,181			102,430			5,175			102,416

Diluted		5,181			102,430			5,467			102,416

See accompanying notes to condensed consolidated financial statements.

TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)


	Successor			Predecessor			Successor		Predecessor
	Three Months Ended June 30,						Six Months Ended June 30,

	2017			2016			2017		2016
Net income (loss)	$	(3,492	)	$	(141,569	)	$	23,411	$	(128,806	)
Other comprehensive loss:
Derivative instruments designated as cash flow hedges:
Reclassification to net income (loss) of mark-to-market gains		—			(5,555	)		—		(9,070	)

Total other comprehensive loss		—			(5,555	)		—		(9,070	)

Comprehensive income (loss) attributable to Series A Preferred member and common shareholders	$	(3,492	)	$	—			23,411		—

Comprehensive loss attributable to common and preferred limited partners and the general partner	$	—		$	(147,124	)	$	—	$	(137,876	)

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		—		—			22,011		950			950
Net income		—		468			—		22,943			23,411

Balance at June 30, 2017		1	$	323			5,469,798	$	17,097		$	17,420

See accompanying notes to condensed consolidated financial statements.

TITAN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Successor			Predecessor
	Six Months Ended June 30,

	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	23,411		$	(128,806	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Net (income) loss from discontinued operations		(18,789	)		17,441
Depreciation, depletion and amortization		26,468			52,687
Loss on divestiture		38,192			—
(Gain) loss on derivatives		(29,470	)		34,731
(Gain) on extinguishment of debt		—			(26,498	)
Other loss		452			533
Non-cash compensation expense		950			(298	)
Non-cash interest expense		13,911			—
Deferred income taxes (benefit)		(11,301	)		—
Amortization of deferred financing costs and debt discount		1,303			9,127
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(11,015	)		76,419
Accounts payable and accrued liabilities		(14,046	)		(51,980	)

Net cash provided by (used in) continuing operating activities		20,066			(16,644	)

Net cash provided by discontinued operating activities		4,189			(665	)

Net cash provided by (used in) operating activities		24,255			(17,309	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(32,635	)		(18,820	)

Net cash used in continuing investing activities		(32,635	)		(18,820	)

Net cash provided by discontinued investing activities		66,629			—

Net cash provided by (used in) investing activities		33,994			(18,820	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facility		—			135,000
Repayments under revolving credit facility		(65,609	)		(57,500	)
Senior note repurchases		—			(5,528	)
Distributions paid to shareholders/unitholders		—			(12,578	)
Net proceeds from issuance of common limited partner units		—			204
Deferred financing costs, distribution equivalent rights and other		(839	)		(564	)

Net cash provided by (used in) financing activities		(66,448	)		59,034

Net change in cash and cash equivalents		(8,199	)		22,905
Cash and cash equivalents, beginning of period		24,446			1,353

Cash and cash equivalents, end of period	$	16,247		$	24,258

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 June 30, 2017, we had 5,469,798 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 5 – 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 5 – 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 discontinued operations (see Note 3) and our segment information on the condensed consolidated statement of operations and segment footnote disclosures (see Note 11).

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 and Ability to Continue as a Going Concern

Since the Plan Effective Date, we have funded our operations through cash flows generated from our operations and cash on hand. We currently do not have the capacity to access additional liquidity from our First Lien Credit Facility and our ability to access public equity and debt markets may be limited. 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 continue to 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, since the Plan Effective Date, our ability to raise capital through our Drilling Partnerships has been challenged. The decline in the fee-income generated from our Drilling Partnerships business has 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 $643.4 million of outstanding indebtedness under our credit facilities, which is net of $1.8 million of deferred financing costs, as current portion of long term debt, net within our condensed consolidated balance sheet as of June 30, 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. 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 5 – Debt for further information regarding the specific amended terms and provisions). As part of our overall business strategy, we have continued to execute on our sales of non-core assets, which has included the sale of our Appalachia and Rangely operations. The proceeds of the consummated asset sales were used to repay borrowings under our First Lien Credit Facility. Our strategy is to continue to sell non-core assets to reduce our leverage position, which will also help us to comply with the requirements of our First Lien Credit Facility amendment.

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.

On May 4, 2017, we entered into a definitive agreement to sell our conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC (“Diversified”), for $84.2 million. The transaction included 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”). We retained our Utica Shale position, Indiana assets and West Virginia CBM assets in the region. On June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. We expect

to complete the remainder of the Appalachia Assets sale for additional cash proceeds of approximately $11.4 million by September 2017, which will be used to repay a portion of outstanding borrowings under our First Lien Credit Facility.

On June 12, 2017, we entered into a definitive agreement to sell our 25% interest in Rangely Field to an affiliate of Merit Energy Company, LLC for $105 million. Rangely is a CO₂ flood located in Rio Blanco County, Colorado, and operated by Chevron. The transaction includes the sale of our interest in Rangely Field, its 22% interest in Raven Ridge Pipeline, a CO₂ transportation line, as well as surrounding acreage in Rio Blanco and Moffat Counties, Colorado (collectively, the “Rangely Assets”). On August 7, 2017, we completed the Rangely Assets sale for net cash proceeds of $103.5 million, subject to customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility and achieve compliance with the requirement to reduce our First Lien Credit Facility borrowings below $360 million, as required by August 31, 2017.

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.

We cannot assure you that we will be able to implement the above actions, if necessary, on commercially reasonable terms, or at all, in a manner that will 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 will allow us to meet our debt obligations and capital requirements.

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, fair value of derivative instruments, and the fair value of assets held for sale. 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.

Assets Held For Sale

Assets are classified as held for sale when we commit to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent changes to the fair value less estimated costs to sell impact the measurement of assets held for sale, with any gain or loss reflected in the loss on divestitures line item in our condensed consolidated statements of operations. See Note 3 for additional disclosures regarding assets held for sale.

Discontinued Operations

A disposal of a component of our entity is classified as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on our operations and financial results. For components classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities held for sale on the condensed consolidated balance sheet and to net income (loss) from discontinued operations on the condensed consolidated statement of operations for all periods presented. The gains or losses associated with these divested components are recorded in net income (loss) from discontinued operations on the condensed consolidated statement of operations. See Note 3 for additional disclosures regarding discontinued operations.

Income Taxes

Our effective tax rate for the Successor three and six months ended June 30, 2017 was 0.6% and 1.14%, respectively, 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. For the Successor three and six months ended June 30, 2017, we recognized a provision for income taxes of $9.7 million and $11.6 million, respectively, in net income (loss) from discontinued operations on our condensed consolidated statement of operations. For the Successor three and six months ended June 30, 2017, we recognized a corresponding income tax benefit of $9.7 million and $11.6 million, respectively, in net income (loss) from continuing operations on our condensed consolidated statement of operations, which represents a direct offset of the provision for income taxes included within our discontinued operations.

Predecessor’s 2012 Long-Term Incentive Plan

On May 12, 2016, due to the income tax ramifications of the potential options our Predecessor was considering, our Predecessor’s Board of Directors delayed the vesting date of approximately 110,000 units granted to employees, directors and officers until March 2017. The phantom units were set to vest between May 15, 2016 and August 31, 2016. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the three and six months ended June 30, 2016 or our Predecessor’s remaining unrecognized compensation expense related to such awards. As a result of the Chapter 11 Filings, our Predecessor’s 2012 LTIP phantom units were cancelled.

Successor’s Net Income Attributable to Common Shareholders Per Share

The 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. The 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. We determine if potentially dilutive shares are anti-dilutive based on their impact to net income (loss) from continuing operations.

The following is a reconciliation of net income attributable to our Successor’s common shareholders for purposes of calculating net income attributable to our Successor’s common shareholders per share (in thousands):


	Successor
	Three Months ended June 30, 2017			Six Months Ended June 30, 2017
Net income (loss) from continuing operations	$	(20,120	)	$	4,622
Less: Series A Preferred member interest in income (loss) from continuing operations		(402	)		92

Net income (loss) from continuing operations utilized in the calculation of net income (loss) attributable to common shareholders per share	$	(19,718	)	$	4,530

Net income from discontinued operations	$	16,628		$	18,789
Less: Series A Preferred member interest in net income from discontinued operations		332			376

Net income from discontinued operations utilized in the calculation of net income attributable to common shareholders per share	$	16,296		$	18,413

The following table is a reconciliation of the 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):


	Successor
	Three Months Ended June 30, 2017		Six Months Ended June 30, 2017
Weighted average number of common shares—basic⁽¹⁾		5,181		5,175
Add dilutive effect of share based awards at end of period⁽²⁾		—		292

Weighted average number of common shares—diluted		5,181		5,467

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

(2)

We determine if potentially dilutive shares are anti-dilutive based on their impact to net income (loss) from continuing operations. Since the three months ended June 30, 2017 resulted in net loss from continuing operations attributable to common shareholders, potentially dilutive shares were excluded because their inclusion would have been anti-dilutive.

Predecessor’s Net Income (Loss) Per Common Unit

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


	Predecessor
	Three Months ended June 30, 2016			Six Months Ended June 30, 2016
Net loss from continuing operations	$	(124,571	)	$	(111,365	)
Preferred limited partner dividends		(365	)		(4,013	)

Net loss from continuing operations attributable to common limited partners and the general partner		(124,936	)		(115,378	)
Less: General partner’s interest in net loss from continuing operations		(2,498	)		(2,308	)

Net loss from continuing operations attributable to common limited partners		(122,438	)		(113,070	)
Less: Net income from continuing operations attributable to participating securities – phantom units		—			—

Net loss from continuing operations utilized in the calculation of net loss attributable to common limited partners per unit – Basic		(122,438	)		(113,070	)
Plus: Convertible preferred limited partner dividends⁽¹⁾		—			—

Net loss from continuing operations utilized in the calculation of net loss attributable to common limited partners per unit – Diluted	$	(122,438	)	$	(113,070	)

Net loss from discontinued operations attributable to common limited partners and the general partner	$	(16,998	)	$	(17,441	)
Less: General partner’s interest in net loss from discontinued operations		(340	)		(349	)

Net loss from discontinued operations attributable to common limited partners		(16,658	)		(17,092	)
Less: Net income from discontinued operations attributable to participating securities – phantom units		—			—

Net loss from discontinued operations utilized in the calculation of net loss attributable to common limited partners per unit – Basic		(16,658	)		(17,092	)
Plus: Convertible preferred limited partner dividends⁽¹⁾		—			—

Net loss from discontinued operations utilized in the calculation of net loss attributable to common limited partners per unit – Diluted	$	(16,658	)	$	(17,092	)

(1)	For the periods 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 (loss) attributable to our Predecessor’s common limited partners per unit with those used to compute diluted net income attributable to our Predecessor’s common limited partners per unit (in thousands):


	Predecessor
	Three Months Ended June 30, 2016		Six Months Ended June 30, 2016
Weighted average number of common limited partner units—basic		102,430		102,416
Add effect of dilutive incentive awards⁽¹⁾		—		—
Add effect of dilutive convertible preferred limited partner units⁽²⁾		—		—

Weighted average number of common limited partner units—diluted		102,430		102,416

(1)	For the three and six months ended June 30, 2016, 274,000 and 283,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

(2)

For the 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. We intend to adopt the new standard using the modified retrospective method, which is expected to have an immaterial impact on our financial statements. The 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.

NOTE 3 – DISCONTINUED OPERATIONS AND DIVESTITURES

Appalachia Divestiture – Discontinued Operations

As disclosed in Note 2, on June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. We expect to complete the remainder of the Appalachian Assets sale for additional cash proceeds of approximately $11.4 million by September 2017, which will be used to repay a portion of outstanding borrowings under our First Lien Credit Facility.

We determined the Appalachian Assets represent discontinued operations as they constitute a disposal of a group of components and a strategic shift that will have a major effect on our operations and financial results. We evaluated the Appalachian Assets sale on our gas and oil production and Drilling Partnership management segments’ results of operations and cash flows, as well as expected asset retirement obligations, and concluded the impact will have a major effect on our expected operations and financial results. As a result, we reclassified the Appalachian Assets from their historical presentation to assets and liabilities held for sale on the condensed consolidated balance sheet and to net income (loss) from discontinued operations on the condensed consolidated statement of operations for all periods presented.

The remainder of our Appalachian Assets are classified as held for sale in our condensed consolidated balance sheet at June 30, 2017. We determined that the carrying value of the remainder of our Appalachian Assets exceeded the fair value less costs to sell,

which resulted in an impairment of $4.3 million recognized in net income (loss) from discontinued operations on our condensed consolidated statement of operations during the three and six months ended June 30, 2017.

The following table reconciles the major classes of line items from the discontinued operations of the Appalachian Assets included within net income (loss) from discontinued operations in thousands:


	Successor			Predecessor			Successor			Predecessor
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Revenues:
Gas and oil production	$	9,892		$	3,880		$	20,925		$	7,120
Drilling partnership management		4,731			4,539			7,996			8,479
Gain (loss) on mark-to-market derivatives		1,666			(6,101	)		4,955			(1,542	)
Other, net		702			—			—			—

Total revenues		16,991			2,318			33,876			14,057

Costs and expenses:
Gas and oil production	$	5,118		$	1,967		$	8,167		$	4,790
Drilling partnership management		3,729			3,350			7,896			7,489
Depreciation, depletion and amortization		2,226			3,696			5,055			6,366
General and administrative		2,245			2,827			4,080			4,032
(Gain) loss on sale of assets		(28,564	)		(88	)		(28,602	)		(22	)
Impairment on assets held for sale		4,272			—			4,272			—
Interest expense		1,600			1,408			2,654			2,687
Other (income) loss		—			6,156			—			6,156

Total costs and expenses	$	(9,374	)	$	19,316		$	3,522		$	31,498

Income (loss) from discontinued operations before income taxes		26,365			(16,998	)		30,354			(17,441	)
Income tax provision (benefit)		9,737			—			11,565			—

Net income (loss) from discontinued operations	$	16,628		$	(16,998	)	$	18,789		$	(17,441	)

We allocated First Lien Credit Facility interest expense to our discontinued operations based on the relative proportion of the net cash proceeds from the sale (and expected sale) of the Appalachian Assets used to repay (and expected to repay) outstanding indebtedness under our First Lien Credit Facility to the total outstanding indebtedness under our First Lien Credit Facility for the periods presented.

We allocated gain (loss) on mark-to-market natural gas commodity derivatives to our discontinued operations based on the relative proportion of the Appalachian Assets’ natural gas production volumes to our total natural gas production volumes for the periods presented.

Rangely Divestiture

As disclosed in Note 2, on August 7, 2017, we completed the Rangely Assets sale for net cash proceeds of $103.5 million, subject to customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. The Rangely Assets were classified as held for sale in our condensed consolidated balance sheet at June 30, 2017. We determined that the carrying value of the Rangely Assets exceeded the fair value less costs to sell, which resulted in an impairment of $38.2 million recognized in loss on divesture on our condensed consolidated statement of operations during the three and six months ended June 30, 2017.

We considered the Rangely Assets to be an individually significant component of our operations. The following table presents the net income (loss) before income taxes of the Rangely Assets held for sale for the periods presented, in thousands:


	Successor			Predecessor			Successor			Predecessor
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Income (loss) before income taxes ⁽¹⁾	$	(37,251	)	$	(1,227	)	$	(34,087	)	$	8,199

(1)	Income (loss) before income taxes reflects gas and oil production revenues less gas and oil production expenses, general and administrative expenses, depletion, depreciation, amortization expenses, and loss on divestitures of $38.2 million as disclosed above.

Assets Held For Sale

The following table details the major classes of assets and liabilities of the Appalachian Assets and Rangely Assets classified as held for sale for the periods presented, in thousands:


	June 30, 2017		December 31, 2016
	June 30, 2017		December 31, 2016
Current assets:
Accounts receivable	$	—	$	7,254
Prepaid expenses and other		—		1,017
Property, plant and equipment, net		11,405		—

Total current assets of Appalachian Assets discontinued operations held for sale		11,405		8,271

Rangely Assets held for sale		113,252		—

Total current assets classified as held for sale		124,657		8,271
Property, plant and equipment, net		—		113,956
Other assets		—		449

Total non-current assets of Appalachian Assets discontinued operations held for sale		—		114,405

Total assets classified as held for sale	$	124,657	$	122,676

Current liabilities:
Accounts payable	$	—	$	2,516
Current portion of derivative liability		—		4,279
Accrued liabilities and other		296		2,666
Asset retirement obligations		593		—
Other long-term liabilities		368		—

Total current liabilities of Appalachian Assets discontinued operations held for sale		1,257		9,461

Rangely Assets held for sale		1,039		—

Total current liabilities classified as held for sale		2,296		9,461

Long-term derivative liability		—		1,407
Asset retirement obligations		—		60,316
Other long-term liabilities		—		682

Total non-current liabilities of Appalachian Assets discontinued operations held for sale		—		62,405

Total liabilities classified as held for sale	$	2,296	$	71,866

We allocated natural gas commodity derivatives assets and liabilities to our discontinued operations held for sale based on the relative proportion of the Appalachian Assets’ natural gas production volumes to our total natural gas production volumes as of December 31, 2016.

NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

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


	June 30, 2017			December 31, 2016
Natural gas and oil properties:
Proved properties	$	518,886		$	608,901
Unproved properties		52,767			73,057
Support equipment and other		8,376			8,081

Total natural gas and oil properties		580,029			690,039
Less – accumulated depreciation, depletion and amortization		(41,611	)		(19,270	)

Total property, plant and equipment, net	$	538,418		$	670,769

During the Successor six months ended June 30, 2017 and the Predecessor six months ended June 30, 2016, we recognized $1.2 million and $15.5 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 June 30, 2017 and the Predecessor three months ended June 30, 2016, was 8.0% and 6.6%, respectively. The aggregate amount of interest capitalized during the Successor three months ended June 30, 2017 and the Predecessor three months ended June 30, 2016 was $0.2 million and $2.4 million, respectively. The weighted average interest rate used to capitalize interest on borrowed funds during the Successor six months ended June 30, 2017 and the Predecessor six months ended June 30, 2016, was 7.8% and 6.7%, respectively The aggregate amount of interest capitalized by us was $0.2 million and $4.8 million for the Successor six months ended June 30, 2017 and the Predecessor six months ended June 30, 2016, respectively.

For the Successor three months ended June 30, 2017 and the Predecessor three months ended June 30, 2016, we recorded $0.4 million and $0.7 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 Successor six months ended June 30, 2017 and the Predecessor six months ended June 30, 2016, we recorded $0.7 million and $1.4 million, respectively, of accretion expense related to our asset retirement obligations within depreciation, depletion and amortization in our condensed consolidated statements of operations.

NOTE 5 – DEBT

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


	June 30,			December 31,
	2017			2016
First Lien Credit Facility	$	370,200		$	435,809
Second Lien Credit Facility		274,933			261,022
Deferred financing costs, net of accumulated amortization of $505 and $172, respectively		(1,755	)		(2,021	)

Total debt, net		643,378			694,810
Less current maturities		(643,378	)		(694,810	)

Total long-term debt, net	$	—		$	—

Cash Interest. Total cash payments for interest for the Successor three months ended June 30, 2017, and the Predecessor three months ended June 30, 2016, were $7.1 million and $12.5 million, respectively. Total cash payments for interest for the Successor six months ended June 30, 2017, and the Predecessor six months ended June 30, 2016, were $13.9 million and $53.7 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 June 30, 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.

On June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. On August 7, 2017, we completed the Rangely Assets sale for net cash proceeds of $103.5 million, subject to customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility and achieve compliance with the requirement to reduce our First Lien Credit Facility borrowings below $360 million, as required by August 31, 2017.

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 6 – DERIVATIVE INSTRUMENTS

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

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

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			Successor			Predecessor
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets⁽¹⁾	$	—		$	5,477		$	—		$	8,926
Portion of settlements attributable to subsequent mark-to-market gains (losses)		(678	)		35,805			(3,975	)		77,164

Total cash settlements on commodity derivative contracts	$	(678	)	$	41,282		$	(3,975	)	$	86,090

Gains (losses) recognized on cash settlement⁽²⁾	$	1,236		$	(2,291	)	$	11,523		$	9,130
Gains (losses) recognized on open derivative contracts⁽²⁾		13,552			(64,871	)		29,470			(34,731	)

Gains (losses) on mark-to-market derivatives	$	14,788		$	(67,162	)	$	40,993		$	(25,601	)

(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):


	Gross Amounts Recognized			Gross Amounts Offset			Net Amount Presented
Offsetting Derivatives as of June 30, 2017
Current portion of derivative assets	$	4,213		$	(3,688	)	$	525
Long-term portion of derivative assets		1,898			(292	)		1,606

Total derivative assets	$	6,111		$	(3,980	)	$	2,131

Current portion of derivative liabilities	$	(4,578	)	$	3,688		$	(890	)
Long-term portion of derivative liabilities		(293	)		292			(1	)

Total derivative liabilities	$	(4,871	)	$	3,980		$	(891	)

Offsetting Derivatives as of December 31, 2016
Current portion of derivative assets	$	7		$	(7	)	$	—
Long-term portion of derivative assets		677			(677	)		—

Total derivative assets	$	684		$	(684	)	$	—

Current portion of derivative liabilities	$	(30,526	)	$	7		$	(30,519	)
Long-term portion of derivative liabilities		(13,885	)		677			(13,208	)

Total derivative liabilities	$	(44,411	)	$	684		$	(43,727	)

At June 30, 2017, we had the following commodity derivatives instruments:


Type	Production Period Ending December 31,		Volumes⁽¹⁾			Average Fixed Price⁽²⁾		Fair Value Asset / (Liability)			Total Type
								(in thousands)⁽²⁾			(in thousands)
Natural Gas – Fixed Price Swaps		2017		25,839,800	⁽³⁾	$	3.140	$	1,116
		2018		43,947,300		$	2.959	$	(1,465	)
											$	(349	)
Crude Oil – Fixed Price Swaps		2017		392,900	⁽³⁾	$	47.441	$	383
		2018		588,200		$	50.284	$	1,206
											$	1,589

									Total net asset		$	1,240

(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 six months of 2017 beginning July 1, 2017.

NOTE 7 – 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 June 30, 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 June 30, 2017	Level 1		Level 2			Level 3		Total
Assets, gross
Commodity swaps	$	—	$	6,111		$	—	$	6,111

Total derivative assets, gross		—		6,111			—		6,111

Liabilities, gross
Commodity swaps		—		(4,871	)		—		(4,871	)

Total derivative liabilities, gross		—		(4,871	)		—		(4,871	)

Total derivatives, fair value, net	$	—	$	1,240		$	—	$	1,240


Derivatives, Fair Value, as of December 31, 2016	Level 1		Level 2			Level 3		Total
Assets, gross
Commodity swaps	$	—	$	684		$	—	$	684

Total derivative assets, gross		—		684			—		684

Liabilities, gross
Commodity swaps		—		(44,411	)		—		(44,411	)

Total derivative liabilities, gross		—		(44,411	)		—		(44,411	)

Total derivatives, fair value, net	$	—	$	(43,727	)	$	—	$	(43,727	)

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 June 30, 2017, which consists of our First Lien Credit Facility and Second Lien Credit Facility, approximated carrying value of $645.1 million. At June 30, 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.

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

We estimated the fair value less estimated costs to sell of our remaining Appalachia Assets and Rangely Assets held for sale as of June 30, 2017 (see Note 3) based on the respective negotiated purchase prices that were derived from discounted cash flow models, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves, external estimates of recovery values, and other market multiples. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

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

Our Predecessor’s management estimated the fair value of asset retirement obligations transferred to our Predecessor upon consolidation of certain Drilling Partnerships (see Note 8) based on discounted cash flow projections using our Predecessor’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future considering inflation rates, federal and state regulatory requirements, and our Predecessor’s assumed credit-adjusted risk-free interest rate. These estimates of fair value were Level 3 measurements as they were based on unobservable inputs.

NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with ATLS. Except for our named executive officers, we do not directly employ any persons to manage or operate our business. These functions are provided by employees of ATLS and/or its affiliates. As of June 30, 2017 and December 31, 2016, we had receivables of $6.3 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 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. On June 30, 2017, in connection with the completion of the sale of the majority of the Appalachian Assets, we delegated the operational activities to an affiliate of Diversified for all the Drilling Partnerships’ natural gas and oil wells in Pennsylvania and Tennessee.

In March 2016, our Predecessor transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by our Predecessor to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, our Predecessor transferred $3.8 million of funds to certain of the Drilling Partnerships that were projected to make monthly or quarterly distributions to their limited partners over the next several months and/or quarters to ensure accessible distribution funding coverage in accordance with the respective Drilling Partnerships’ operations and partnership agreements in the event that our Predecessor experienced a prolonged restructuring period as our Predecessor performed all administrative and management functions for the Drilling Partnerships.

During the quarter ended June 30, 2016, our Predecessor recorded $7.2 million and $12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to our Predecessor as a result of certain Drilling Partnership consolidations. The gas and oil properties and asset retirement obligations were recorded at their fair values on the respective dates of the Drilling Partnerships’ consolidation and transfer to our Predecessor (see Note 7) and resulted in a non-cash loss of $6.2 million, net of consolidation and transfer adjustments, for the three and six months ended June 30, 2016, which was recorded in net income (loss) from discontinued operations in the condensed consolidated statements of operations.

As of each of June 30, 2017 and December 31, 2016, we had trade receivables of $0.1 million from certain of the Drilling Partnerships, which were recorded in accounts receivable in our condensed consolidated balance sheets. As of June 30, 2017 and December 31, 2016, we had trade payables of $2.7 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 June 30, 2017 and December 31, 2016, we had receivables of $0.2 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 9 – COMMITMENTS AND CONTINGENCIES

Drilling Partnership Commitments

As of June 30, 2017, we are committed to expend approximately $2.8 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 June 30, 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 10 – 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 six months ended June 30, 2016, our Predecessor paid four monthly cash distributions totaling $5.1 million to its common limited partners ($0.0125 per unit per month); $2.5 million to its Preferred Class C limited partners ($0.0125 per unit per month); and $0.2 million to its General Partner Class A holder ($0.0125 per unit per month).

During the Predecessor six months ended June 30, 2016, our Predecessor paid a distribution of $4.4 million to its Class D Preferred limited partners ($0.5390625 per unit) for the period October 15, 2015 through April 14, 2016. During the Predecessor six months ended June 30, 2016, our Predecessor paid a distribution of $0.3 million to its Class E Preferred limited partners ($0.671875 per unit) for the period October 15, 2015 through April 14, 2016. On June 16, 2016, our Predecessor’s Board of Directors elected to suspend its quarterly distributions on its Class D Preferred Units and our Class E Preferred Units, beginning with the second quarter 2016 distribution, due to the continued lower commodity price environment. The Class D Preferred Units and Class E Preferred Units accrued distributions of $1.9 million and $0.1 million, respectively, from April 15, 2016 through June 30, 2016. However, due to the distribution suspension and our Predecessor’s Chapter 11 filings, these amounts were not earned as the preferred units were cancelled without receipt of any consideration on the Plan Effective Date.

NOTE 11 – 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			Successor			Predecessor
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Gas and oil production:
Gas and oil production revenues ⁽¹⁾	$	68,727		$	(19,635	)	$	154,499		$	67,186
Gas and oil production costs		(25,077	)		(29,188	)		(52,722	)		(62,411	)
Depreciation, depletion and amortization		(12,494	)		(22,677	)		(25,809	)		(47,419	)
Loss on divestiture		(38,192	)		—			(38,192	)		—

Segment income (loss)	$	(7,036	)	$	(71,500	)	$	37,776		$	(42,644	)
Drilling partnership management:⁽²⁾
Drilling partnership management revenues	$	7,610		$	748		$	15,390		$	5,668
Drilling partnership management expenses		(5,310	)		837			(9,778	)		(1,306	)
Depreciation, depletion and amortization		(312	)		(2,634	)		(659	)		(5,268	)

Segment income (loss)	$	1,988		$	(1,049	)	$	4,953		$	(906	)
Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Gas and oil production	$	(7,036	)	$	(71,500	)	$	37,776		$	(42,644	)
Drilling partnership management ⁽²⁾		1,988			(1,049	)		4,953			(906	)

Total segment income (loss)		(5,048	)		(72,549	)		42,729			(43,550	)
General and administrative expenses ⁽³⁾		(10,929	)		(20,934	)		(22,819	)		(36,808	)
Interest expense⁽³⁾		(13,615	)		(30,545	)		(26,548	)		(56,972	)
Gain on early extinguishment of debt ⁽³⁾		—			—			—			26,498
Other income (loss) ⁽³⁾		(181	)		(543	)		(41	)		(533	)
Income tax (provision) benefit ⁽³⁾		9,653			—			11,301			—

Net income (loss) from continuing operations		(20,120	)		(124,571	)		4,622			(111,365	)

Reconciliation of segment revenues to total revenues:
Gas and oil production	$	68,727		$	(19,635	)	$	154,499		$	67,186
Drilling partnership management		7,610			748			15,390			5,668

Total revenues	$	76,337		$	(18,887	)	$	169,889		$	72,854

Capital expenditures:
Gas and oil production	$	21,999		$	5,210		$	31,912		$	17,155
Drilling partnership management		101			416			521			1,550
Corporate and other		91			24			202			115

Total capital expenditures	$	22,191		$	5,650		$	32,635		$	18,820

(1)	Includes gain (loss) on mark-to-market derivatives. For the Predecessor three months ended June 30, 2016, a $67.2 million loss on mark-to-market derivatives is included related to increases in commodity future prices relative to our commodity fixed price swaps.

(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.


	June 30, 2017		December 31, 2016
Balance sheet:
Total assets:
Gas and oil production	$	564,464	$	703,243
Drilling partnership management		5,598		11,786
Corporate and other⁽¹⁾		33,431		44,129
Assets held for sale		124,657		122,676

Total assets	$	728,150	$	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 12 – SUBSEQUENT EVENTS

Rangely Divestiture. On August 7, 2017, we completed the Rangely Asset sale for net cash proceeds of $103.5 million, subject to customary preliminary price adjustments (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.

LIQUIDITY AND ABILITY TO CONTINUE AS A GOING CONCERN

On April 19, 2017, we entered into an amendment to our First Lien Credit Facility. 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). As part of our overall business strategy, we have continued to execute on our sales of non-core assets, which has included the sale of our Appalachia and Rangely operations (see “Recent Developments”). The proceeds of the consummated asset sales were used to repay borrowings under our First Lien Credit Facility. Our strategy is to continue to sell non-core assets to reduce our leverage position, which will also help us to comply with the requirements of our First Lien Credit Facility amendment.

financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders.

RECENT DEVELOPMENTS

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 (“Diversified”), 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”). We retained our Utica Shale position, Indiana assets and West Virginia CBM assets in the region. On June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. We expect to complete the remainder of the Appalachia Assets sale for additional cash proceeds of approximately $11.4 million by September 2017, which will be used to repay a portion of outstanding borrowings under our First Lien Credit Facility.

Rangely Divestiture

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 continue 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 Appalachian Assets presented as discontinued operations in the condensed consolidated financial statements and footnote disclosures and our segment information on the condensed consolidated statement of operations and segment footnote disclosures.

Discontinued operations. We determined the Appalachian Assets represent discontinued operations as they constitute a disposal of a group of components and a strategic shift that will have a major effect on our operations and financial results. We evaluated the Appalachian Assets sale on our gas and oil production and Drilling Partnership management segments’ results of operations and cash flows, as well as expected asset retirement obligations, and concluded the impact will have a major effect on our expected operations and financial results. As a result, we reclassified the Appalachian Assets from their historical presentation to assets and liabilities held for sale on the condensed consolidated balance sheet and to net income (loss) from discontinued operations on the condensed consolidated statement of operations for all periods presented.

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 Appalachia Basin assets, including the Utica Shale, 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, and the Mississippi Lime and Hunton plays in northwestern Oklahoma.

We also had a production position in the Rangely field in northwest Colorado, a mature tertiary CO2 flood with low-decline oil production, where we had a 25% non-operated net working interest position which we acquired in 2014 and subsequently sold in August 2017.

At June 30, 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		Successor		Predecessor
	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		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		4		—		4		—
Net wells turned in line^(1)(2)(3):
Eagle Ford		3		—		3		—

(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		Successor		Predecessor
	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Production volumes per day:^(1) (2)
Eagle Ford:
Natural gas (Mcfd)		584		471		626		430
Oil (Bpd)		1,988		1,188		1,998		1,275
NGLs (Bpd)		128		98		137		90

Total (Mcfed)		13,284		8,188		13,436		8,618

Coalbed Methane:
Natural gas (Mcfd)		105,486		116,743		106,934		118,646
Oil (Bpd)		—		—		—		—
NGLs (Bpd)		—		—		—		—

Total (Mcfed)		105,486		116,743		106,934		118,646

Utica / Indiana:
Natural gas (Mcfd)		4,156		5,561		4,290		5,954
Oil (Bpd)		19		47		29		49
NGLs (Bpd)		14		25		17		25

Total (Mcfed)		4,353		5,991		4,567		6,398

Mid-Continent:
Natural gas (Mcfd)		30,897		36,616		31,511		39,341
Oil (Bpd)		240		385		242		469
NGLs (Bpd)		1,225		1,571		1,242		1,726

Total (Mcfed)		39,686		48,352		40,413		52,513

Rangely:⁽³⁾
Natural gas (Mcfd)		—		—		—		—
Oil (Bpd)		1,890		2,269		2,070		2,312
NGLs (Bpd)		181		235		213		245

Total (Mcfed)		12,426		15,026		13,699		15,341

Total production volumes per day:⁽²⁾
Natural gas (Mcfd)		141,123		159,390		143,361		164,373
Oil (Bpd)		4,137		3,889		4,339		4,104
NGLs (Bpd)		1,548		1,929		1,610		2,087

Total (Mcfed)		175,235		194,300		179,049		201,519

Total production:⁽²⁾
Natural gas (MMcf)		12,842		14,505		25,948		29,916
Oil (MBbls)		376		354		785		747
NGLs (MBbls)		141		176		291		380

Total (MMcfe)		15,946		17,681		32,408		36,676

(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.

(3)	We subsequently sold our interest in Rangely on August 7, 2017 (see “Recent Developments”).

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			Successor			Predecessor
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Production revenues (in thousands):⁽¹⁾
Eagle Ford:
Natural gas revenue	$	163		$	116		$	349		$	206
Oil revenue		8,509			6,802			17,554			12,662
Natural gas liquids revenue		179			133			448			219

Total revenues	$	8,851		$	7,051		$	18,351		$	13,087

Coalbed Methane:
Natural gas revenue	$	27,421		$	22,557		$	57,086		$	47,281
Oil revenue		—			—			—			—
Natural gas liquids revenue		—			—			—			—

Total revenues	$	27,421		$	22,557		$	57,086		$	47,281

Utica / Indiana:
Natural gas revenue	$	1,096		$	818		$	2,293		$	1,784
Oil revenue		79			174			235			301
Natural gas liquids revenue		25			14			75			41

Total revenues	$	1,200		$	1,006		$	2,603		$	2,126

Mid-Continent:
Natural gas revenue	$	5,987		$	2,376		$	12,366		$	5,936
Oil revenue		992			688			2,006			1,215
Natural gas liquids revenue		1,765			1,644			3,781			2,940

Total revenues	$	8,744		$	4,708		$	18,153		$	10,091

Rangely:⁽⁶⁾
Natural gas revenue	$	—		$	—		$	—		$	—
Oil revenue		8,011			11,746			17,902			19,490
Natural gas liquids revenue		583			616			1,398			1,105

Total revenues	$	8,594		$	12,362		$	19,300		$	20,595

Total production revenues:⁽¹⁾
Natural gas revenue	$	34,667		$	25,867		$	72,094		$	55,207
Oil revenue		17,591			19,410			37,697			33,668
Natural gas liquids revenue		2,552			2,407			5,702			4,305
Subordinated revenue⁽²⁾		(881	)		(157	)		(1,987	)		(393	)

Total revenues	$	53,929		$	47,527		$	113,506		$	92,787

Average sales price:
Natural gas (per Mcf):
Total realized price, after hedge^(3) (4)	$	2.66		$	3.52		$	2.61		$	3.50
Total realized price, before hedge⁽⁴⁾	$	2.63		$	1.70		$	2.70		$	1.78
Oil (per Bbl):
Total realized price, after hedge⁽³⁾	$	46.15		$	84.07		$	45.86		$	81.84
Total realized price, before hedge	$	46.72		$	42.22		$	48.00		$	35.52
Natural gas liquids (per Bbl):
Total realized price, after hedge	$	18.11		$	13.71		$	19.57		$	11.34
Total realized price, before hedge	$	18.11		$	13.71		$	19.57		$	11.34


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Production costs (per Mcfe):
Eagle Ford:
Lease operating expenses	$	1.15	$	1.74	$	1.15	$	1.75
Production taxes		0.48		0.47		0.46		0.42
Transportation		0.07		0.14		0.08		0.12

Total production costs (per Mcfe)	$	1.70	$	2.35	$	1.69	$	2.29

Coalbed Methane:
Lease operating expenses	$	1.03	$	0.98	$	1.01	$	1.01
Production taxes		0.25		0.16		0.25		0.16
Transportation		0.11		0.22		0.13		0.27

Total production costs (per Mcfe)	$	1.39	$	1.36	$	1.39	$	1.45

Utica / Indiana:
Lease operating expenses	$	0.49	$	0.32	$	0.45	$	0.39
Production taxes		0.09		0.06		0.10		0.06
Transportation		0.12		0.12		0.12		0.12

Total production costs (per Mcfe)	$	0.69	$	0.49	$	0.67	$	0.57

Mid-Continent:
Lease operating expenses	$	0.98	$	0.90	$	0.96	$	0.99
Production taxes		0.14		0.17		0.15		0.16
Transportation		—		0.29		0.11		0.25

Total production costs (per Mcfe)	$	1.12	$	1.36	$	1.22	$	1.40

Rangely:⁽⁶⁾
Lease operating expenses	$	5.40	$	4.37	$	4.80	$	4.36
Production taxes		0.57		0.60		0.54		0.58
Transportation		0.01		0.01		0.01		0.01

Total production costs (per Mcfe)	$	5.98	$	4.98	$	5.35	$	4.95

Total production costs:
Lease operating expenses⁽⁵⁾	$	1.32	$	1.24	$	1.28	$	1.27
Production taxes		0.26		0.20		0.26		0.20
Transportation		0.08		0.22		0.11		0.24

Total production costs (per Mcfe)⁽⁵⁾	$	1.66	$	1.66	$	1.66	$	1.71

⁽¹⁾

For the Predecessor three months ended June 30, 2016 and six months ended June 30, 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 $26.0 million for natural gas and $9.8 million for oil for the Predecessor three months ended June 30, 2016, $50.6 million for natural gas and $26.5 million in oil for the Predecessor six months ended June 30, 2016.

⁽²⁾

Represents the amount of subordination of our production revenue to investor partners within certain of our Drilling Partnerships. In addition to recognizing subordinated revenues, we also subordinate a corresponding proportionate share of subordinated lease operating expenses to investor partners within certain of our Drilling Partnerships, which lowers our overall production costs. The corresponding subordinated lease operating expenses for the Successor three and six months ended June 30, 2017 was $0.5 million and $0.9 million, respectively, and for the Predecessor three and six months ended June 30, 2016 was $0.1 million and $0.3 million, respectively.

⁽³⁾

For the Successor three months ended June 30, 2017 and six months ended June 30, 2017, calculation includes the impact of cash settlements on commodity derivative contracts, consisting of $0.5 million in payments for natural gas derivative contracts and $0.2 million in payments for crude oil derivative contracts for the Successor three months ended June 30, 2017 and $2.3 million in payments for natural gas derivative contracts and $1.7 million in payments for crude oil derivative contracts for the Successor six months ended June 30, 2017. For the Predecessor three and six months ended June 30, 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 $26.0 million and $50.6 million in receipts associated with natural gas derivative contracts and $9.8 million and $26.5 million in receipts associated with crude oil derivative contracts.

⁽⁴⁾

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 $2.60 per Mcf ($2.63 per Mcf before the effects of financial hedging) for the Successor period three months ended June 30, 2017 and $3.52 per Mcf ($1.70 per Mcf before the effects of financial hedging) for the Predecessor three months ended June 30, 2016, and for the Successor six months ended June 30, 2017, the average realized gas sales price was $2.61 per Mcf ($2.70 per Mcf before the effects of financial hedging) and $3.49 per Mcf ($1.77 per Mcf before the effects of financial hedging) for the Predecessor six months ended June 30, 2016.

⁽⁵⁾

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, total lease operating expenses per Mcfe were $1.29 per Mcfe ($1.63 per Mcfe for total production costs) and $1.23 per Mcfe ($1.65 per Mcfe for total production costs) for the Successor period three months ended

June 30, 2017 and the Predecessor period three months ended June 30, 2016 respectively, and for the Successor period six months ended June 30, 2017, and the Predecessor period six months ended June 30, 2016, they were $1.26 per Mcfe ($1.63 per Mcfe for total production costs) and $1.27 per Mcfe ($1.70 per Mcfe for total production costs), respectively.

⁽⁶⁾	We subsequently sold our interest in Rangely on August 7, 2017 (see “Recent Developments”).


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
(in thousands)
Gas and oil production revenues	$	53,939	$	47,527	$	113,506	$	92,787
Gas and oil production costs	$	25,077	$	29,188	$	52,722	$	62,411

Our gas and oil production revenues were higher in the current quarter due to an increase of $10.5 million due to higher average realized sales prices before hedging activities resulting from the improved commodity pricing environment and an increase $3.1 million due to 19 wells turned inline in our Eagle Ford operating area since the end of the second quarter 2016, partially offset by an increase of $0.7 million related to subordinated revenues at our Drilling Partnerships and a decrease of $6.5 million due to lower production volumes resulting from natural decline and cost control operating decisions.

Our gas and oil production revenues were higher in the six months ended June 30, 2017, due to an increase of $31.6 million due to higher average realized sales prices before hedging activities resulting from the improved commodity pricing environment and an increase of $2.4 million due to 19 wells turned inline in our Eagle Ford operating area since the end of the second quarter 2016, partially offset by an increase of $1.6 million related to subordinated revenues at our Drilling Partnerships and a decrease of $11.7 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 $1.4 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 and a $3.4 million decrease in transportation costs due to contract negotiations for lower rates, partially offset by a $0.7 million increase in production taxes due to higher realized sales prices.

Our total production costs were lower in the six months ended June 30, 2017, due to a $5.8 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 area and a $5.0 million decrease in transportation costs due to contract negotiations for lower rates, partially offset by a $1.2 million increase in production taxes due to 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.

As previously disclosed in the “Ability to Continue as a Going Concern” section, since the Plan Effective Date, our ability to raise capital through our Drilling Partnerships has been challenged. The decline in the fee-income generated from our Drilling Partnerships business has negatively impacted our ability to remain in compliance with the covenants under our credit facilities. See the “Ability to Continue as a Going Concern” section for further discussion regarding our liquidity and capital resources.


	Successor		Predecessor			Successor		Predecessor
	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017		2016
(in thousands)
Drilling partnership management revenues	$	7,610	$	748		$	15,390	$	5,668
Drilling partnership management expenses	$	5,310	$	(837	)	$	9,778	$	1,306

Drilling partnership management revenues. Our Drilling partnership management revenues were higher in the current quarter and in the six months ended June 30, 2017 due to an increase of $7.1 million and $9.9 million, respectively, in well construction and completion revenues related to the timing of drilling and completion activities for the partnership wells, which are recognized on a cost plus basis.

Drilling partnership management expenses. Our drilling partnership management expenses were higher in the current quarter and in the six months ended June 30, 2017 due to an increase of $6.2 million and $8.6 million, respectively, in well construction and completion expenses related to the timing of drilling and completion activities for the partnership wells, which are recognized on a percentage of completion basis.

OTHER REVENUES AND EXPENSES


	Successor			Predecessor			Successor			Predecessor
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
(in thousands)
Other Revenues
Gain (loss) on mark-to-market derivatives	$	14,788		$	(67,162	)	$	40,993		$	(25,601	)
Other Expenses
General and administrative	$	10,929		$	20,934		$	22,819		$	36,808
Depreciation, depletion and amortization		12,806			25,311			26,468			52,687
Loss on divestiture		38,192			—			38,192			—
Interest expense		13,615			30,545			26,548			56,972
Gain on extinguishment of debt		—			—			—			26,498
Other income (loss)		(181	)		(543	)		(41	)		(533	)
Income tax provision (benefit)		(9,653	)		—			(11,301	)		—

Gain (Loss) on Mark-to-Market Derivatives. We recognize changes in the fair value of our derivatives immediately within gain (loss) on mark-to-market derivatives on our condensed consolidated statements of operations. The gains on mark-to-market derivatives during the Successor three and six months ended June 30, 2017 were due to decreases in commodity future prices relative to our derivative positions as of the respective prior period end. The losses on mark-to-market derivatives during the Predecessor period three and six months ended June 30, 2016 were due to increases in commodity future prices relative to our Predecessor’s derivative positions as of the respective prior period end.

General and Administrative. Our general and administrative expenses were lower in the three months ended June 30, 2017 due to a $6.6 million decrease in non-recurring transaction costs primarily due to our restructuring, a $1.7 million decrease in syndication expenses related to lower investment partnership program fundraising activities and employee reductions in 2017, a $1.0 million decrease in salaries and benefits expenses related to employee reductions in 2016 and a $1.5 million reduction in other corporate activities due to cost control measures implemented, partially offset by a $0.8 million increase in non-cash stock compensation.

Our general and administrative expenses were lower in the six months ended June 30, 2017 due to a $5.5 million decrease in non-recurring transaction costs primarily due to our restructuring, a $4.0 million decrease in salaries and benefits expenses related to employee reductions in 2016, a $3.2 million decrease in syndication expenses related to lower investment partnership program

fundraising activities and employee reductions in 2017, and a $2.5 million reduction in other corporate activities due to cost control measures implemented, partially offset by a $1.3 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 $9.8 million decrease in depletion expense and a $2.7 million decrease as a result of the application of fresh-start accounting to our proved gas and oil properties on September 1, 2016.

Our depreciation, depletion and amortization expenses were lower in the six months ended June 30, 2017 due to a $20.9 million decrease in depletion expense and a $5.3 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 June 30, 2017 primarily consisted of $8.6 million related to our Second Lien Credit Facility, $4.6 million related to our First Lien Credit Facility, and $0.6 million related to amortization of deferred financing costs, partially offset by $0.2 million in capitalized interest. Interest expense during the Predecessor three months ended June 30, 2016 consisted of $14.1 million related to our Predecessor’s senior notes, $7.5 million related to amortization of deferred financing costs and debt discounts, $6.3 million related to our Predecessor’s second lien term loan, and $5.0 million related to our Predecessor’s first lien credit facility, partially offset by $2.4 million in capitalized interest.

Interest expense during the Successor six months ended June 30, 2017 primarily consisted of $16.5 million related to our Second Lien Credit Facility, $9.1 million related to our First Lien Credit Facility, and $1.1 million related to amortization of deferred financing costs, partially offset by $0.2 million in capitalized interest. Interest expense during the Predecessor six months ended June 30, 2016 consisted of $28.5 million related to our Predecessor’s senior notes, $12.6 million related to our Predecessor’s second lien term loan, $11.3 related to amortization of deferred financing costs and debt discounts, and $9.4 million related to our Predecessor’s first lien credit facility, partially offset by $4.8 million in capitalized interest.

Gain on Early Extinguishment of Debt. The gain on early extinguishment of debt for the Predecessor six months ended June 30, 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.

Income Tax Provision (Benefit). For the Successor period six months ended June 30, 2017, we recorded a full valuation allowance against our net deferred tax asset balance, which reduced our effective tax rate to 1.14%. 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 six months ended June 30, 2017 was 1.14%, 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

See the “Liquidity and Ability to Continue as a Going Concern” section for discussion regarding these matters.

Cash Flows


	Successor			Predecessor
	Six Months Ended June 30,
	2017			2016
(in thousands)
Net cash provided by (used in) operating activities	$	24,255		$	(17,309	)
Net cash provided by (used in) investing activities		33,994			(18,820	)
Net cash provided by (used in) financing activities		(66,448	)		59,034

Cash Flows From Operating Activities:

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

•

an increase of $45.1 million net cash provided by continuing operating activities and an increase of $4.9 million net cash provided by discontinued 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 $39.8 million of cash paid for interest due to a decrease of $28.5 million and $11.3 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; and

•

a decrease of $5.2 million of funds transferred to certain Drilling Partnerships; partially offset by

•

a decrease of $90.1 million of cash settlement receipts on commodity derivative contracts.

Cash Flows From Investing Activities:

The increase in cash flows provided by investing activities was due to a $66.6 million increase from the completion of the majority of the sale of our Appalachian Assets, partially offset by a $13.8 million increase 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 $77.5 million in net borrowings under our Predecessor’s revolving credit facility;

•

a decrease of $12.6 million in distributions paid to our Predecessor’s unitholders; and

•

a decrease $5.5 million related to our Predecessor’s senior note repurchases; partially offset by

•

a $65.6 million increase in repayments under our First Lien Credit Facility.

Capital Requirements

At June 30, 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 June 30, 2017, we are committed to expend approximately $2.8 million on drilling and completion and other capital expenditures, excluding acquisitions. We expect to fund these capital expenditures primarily with cash flow from operations, capital raised through our Drilling Partnerships and borrowings under our revolving credit facility

OFF BALANCE SHEET ARRANGEMENTS

As of June 30, 2017, our off-balance sheet arrangements were limited to our letters of credit outstanding of $2.8 million and commitments to spend $2.8 million related to our drilling and completion and capital expenditures, excluding acquisitions.

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 $2.3 million as of June 30, 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 June 30, 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 June 30, 2017, $370.2 million was outstanding under our First Lien Credit Facility and $274.9 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 June 30, 2018 by approximately $6.5 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 June 30, 2018 of approximately $0.1 million.

At June 30, 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⁾		25,839,800	$	3.140
		2018			43,947,300	$	2.959
Crude Oil – Fixed Price Swaps		2017	⁽²⁾		392,900	$	47.441
		2018			588,200	$	50.284

⁽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 six months of 2017 beginning July 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 June 30, 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
2.1		Purchase and Sale Agreement by and among certain subsidiaries of Titan Energy, LLC and Diversified Energy LLC, dated May 4, 2017 (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed July 7, 2017)

2.2		First Amendment to Purchase and Sale Agreement by and among certain subsidiaries of Titan Energy, LLC and Diversified Energy LLC, dated June 30, 2017 (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K filed July 7, 2017)

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		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)

10.2		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)

10.3		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)

10.4*		Retention Agreement between Titan Energy, LLC and Jeffrey M. Slotterback, effective May 15, 2017

10.5*		Retention Agreement between Titan Energy, LLC and Mark D. Schumacher, effective May 23, 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: August 21, 2017	By:	/s/ Daniel C. Herz
		Daniel C. Herz
		Chief Executive Officer and Director

Date: August 21, 2017	By:	/s/ Jeffrey M. Slotterback
		Jeffrey M. Slotterback
		Chief Financial Officer

Date: August 21, 2017	By:	/s/ Matthew J. Finkbeiner
		Matthew J. Finkbeiner
		Chief Accounting Officer

EXHIBIT 10.4

LOGO

May 11, 2017

Jeffrey M. Slotterback

Re: Retention Bonus

Dear Jeff:

The Company agrees to make the following payment to you, in addition to your normal salary and benefits, subject to the terms and conditions in this Agreement and your execution and delivery of this Agreement to the Company by May 15, 2017 (the “Delivery Date”):

Retention Bonus. Subject to the conditions set forth below, you will be eligible to receive a cash bonus in an amount equal to $220,000 (the “Retention Bonus”) payable in two installments: the first installment of $73,333 on November 2, 2017 and the second installment of $146,667 on May 2, 2018 (each a “Payment Date”); provided you are actively employed by the Company on each Payment Date. The Retention Bonus will be paid subject to applicable withholdings and deductions.

Payment Conditions. If you resign your employment with the Company or your employment is terminated for “Cause” (as defined in the Titan Energy, LLC Management Incentive Plan, as in effect on the date hereof), prior to May 2, 2018, you will not be eligible for any unpaid portion of the Retention Bonus. In the event that your employment is terminated by the Company without “Cause” prior to May 2, 2018, the Company will pay you any unpaid portion of the retention Bonus within sixty (60) days of your termination date; provided, you execute, return and do not revoke a separation agreement and general release of claims in a form acceptable to the Company.

Miscellaneous. The Retention Bonus shall not be taken into account for purposes of any other compensation or benefit program of the Company and is in addition to and not in lieu of any salary, bonus, benefits or severance to which you may otherwise be entitled. You may not assign your rights under this Agreement. The Company may assign its obligations hereunder to any successor (including any acquirer of substantially all of its assets). This Agreement sets forth the entire understanding between the Company and you regarding any retention bonus, and may be changed only by a written agreement signed by you and the Company. This Agreement is governed by and to be construed in accordance with the laws of the Commonwealth of Pennsylvania, without regard to conflicts of laws principles thereof. Notwithstanding any of the above, you remain an “at will” employee of the Company. This Agreement may be executed in two or more counterparts, and by the different parties in separate counterparts, each of which when executed shall be deemed to be an original but all of which taken together shall constitute one and the same agreement.

To accept this Agreement, please sign where indicated below, and return in a confidential envelope to Robin Harris, Vice President of Human Resources, Titan Energy, LLC, 1845 Walnut Street, Philadelphia, PA 19103.

Sincerely,

/s/ TITAN ENERGY, LLC

TITAN ENERGY, LLC

ACCEPTED AND AGREED AS OF THE

DATE FIRST SET FORTH ABOVE:

/s/ Jeffrey M. Slotterback

Jeffrey M. Slotterback

EXHIBIT 10.5

LOGO

May 16, 2017

Mark D. Schumacher

Re: Retention Bonus

Dear Mark:

To incentivize you to remain with and committed to the success of Titan Energy, LLC (the “Company”) and its subsidiaries, the Company is offering you a retention bonus upon the terms and conditions set forth in this letter agreement (“Agreement”). As confirmed by the Class B directors, no amount paid pursuant to this Agreement shall impact the amount of your 2017 bonus.

The Company agrees to make the following payment to you, in addition to your normal salary, 2017 bonus and benefits (as confirmed by the Class B directors), subject to the terms and conditions in this Agreement and your execution and delivery of this Agreement to the Company by May 23, 2017 (the “Delivery Date”):

Retention Bonus. Subject to the conditions set forth below, you will be eligible to receive a cash bonus in an amount equal to $320,000 (the “Retention Bonus”) payable in three (3) installments: the first installment of $80,000 as soon practicable following the execution of this Agreement, the second installment of $80,000 on November 2, 2017, and the third installment of $160,000 on May 2, 2018 (each a “Payment Date”); provided you are actively employed by the Company on each Payment Date. The Retention Bonus will be paid subject to applicable withholdings and deductions.

Payment Conditions. If you resign your employment the Company or your employment is terminated for “Cause” (as defined in the Titan Energy, LLC Management Incentive Plan, as in effect on the date hereof), prior to May 2, 2018, you will not be eligible for any unpaid portion of the Retention Bonus. In the event that your employment is terminated by the Company without “Cause” prior to May 2, 2018, the Company will pay you any unpaid portion of the retention Bonus within sixty (60) days of your termination date; provided, you execute, return and do not revoke a separation agreement and general release of claims in a form acceptable to the Company.

Miscellaneous. The Retention Bonus shall not be taken into account for purposes of any other compensation or benefit program of the Company and is in addition to and not in lieu of any salary, bonus, benefits or severance to which you may otherwise be entitled. You may not assign your rights under this Agreement. The Company may assign its obligations hereunder to any successor (including any acquirer of substantially all its assets). This Agreement sets forth the entire understanding between the Company and you regarding any retention bonus, and may be changed only by a written agreement signed by you and the Company. This Agreement is governed by and to be construed in accordance with the laws of the Commonwealth of Pennsylvania, without regard to conflicts of laws principles thereof. This Agreement may be executed in two or more counterparts, and by the different parties in separate counterparts, each of which when executed shall be deemed to be an original but all of which taken together shall constitute one and the same agreement. Nothing in this Agreement shall be deemed

to constitute a waiver of any of your rights, claims or causes of action under your September 1, 2016 Employment Agreement.

Sincerely,

/s/ TITAN ENERGY, LLC

TITAN ENERGY, LLC

ACCEPTED AND AGREED AS OF THE

DATE FIRST SET FORTH ABOVE:

/s/ Mark D. Schumacher

Mark D. Schumacher

EXHIBIT 31.1

CERTIFICATION

I, Daniel C. Herz, certify that:

1.	I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2017 of Titan Energy, LLC;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ DANIEL C. HERZ

Daniel C. Herz

Chief Executive Officer of Titan Energy, LLC

August 21, 2017

EXHIBIT 31.2

CERTIFICATION

I, Jeffrey M. Slotterback, certify that:

1.	I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2017 of Titan Energy, LLC;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer of Titan Energy, LLC

August 21, 2017

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Titan Energy, LLC (the “Company”) on Form 10-Q for the quarter ended June 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Daniel C. Herz, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ DANIEL C. HERZ

Daniel C. Herz

Chief Executive Officer of Titan Energy, LLC

August 21, 2017

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Titan Energy, LLC (the “Company”) on Form 10-Q for the quarter ended June 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey M. Slotterback, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer of Titan Energy, LLC

August 21, 2017