# In re Sabine Oil & Gas Corp.

> United States Bankruptcy Court, S.D. New York · August 18, 2016 · 555 B.R. 180

URL: https://www.frixlaw.com/law-library/cases/8499700

## Case

- **Full name:** IN RE: SABINE OIL & GAS CORPORATION Debtors
- **Court:** United States Bankruptcy Court, S.D. New York
- **Decided:** August 18, 2016
- **Citations:** 555 B.R. 180; 2016 Bankr. LEXIS 3049; 2016 WL 4411433
- **Precedential status:** Published
- **Opinion:** Opinion of the court by Chapman
- **Judges:** Chapman
- **Cited by:** 14 later opinions in the Frix Law Library

## Citator (automated)

- No negative treatment found by the automated citator. That is not the same as a confirmation that the case is good law; read the citing cases.
- Full citator and citing cases: https://www.frixlaw.com/law-library/cases/8499700

## How later opinions describe it (automated extraction)

- noting that “[c]ompromises are a normal part of the process of reorganization.”
- noting that the settlement forms the basis of the plan

## Opinion text

MEMORANDUM DECISION CONFIRMING DEBTORS’ SECOND AMENDED JOINT CHAPTER 11 PLAN OF REORGANIZATION OF SABINE OIL & GAS CORPORATION AND ITS DEBTOR AFFILIATES
SHELLEY C. CHAPMAN, UNITED STATES BANKRUPTCY JUDGE
TABLE OF CONTENTS
BACKGROUND... 188
I. Case and Company Background... 188
II. Events Leading to the Plan and Settlement. . .189
III. The Plan... 192
A. Summary of the Plan and the Settlement Embodied in the Plan... 193
B. Voting Results... 195
C. Objections to the Plan.,. 195
IV. Estimates of Adequate Protection Claims and Potential Bucket II Claims Recoveries... 197
A. Estimates of the Adequate Protection Claims... 198
1. The Debtors’ Estimate of the Adequate Protection Claims.. .202
2. The Committee’s Challenges to the Debtors’ Estimate of the Adequate Protection Claims.. .206
a. Deduction of All Indirect Costs (Whether or Not Included in COPAS *186 Charges) from the Value of the Reserves. . .206
b. Reserve Adjustment Factors (RAFs).. .208
c. Strip Pricing.. .209
d. Encumbrance Analysis.. .210
e. Postpetition Adequate Protection Payments and Application of Swap Payments.. .211
f. Postpetition Mineral Lien Payments. . .211
B. Estimates of Potential Bucket II Claims Recoveries.. .212
1. Bucket II Unencumbered Assets. . .213
2. Disputed Cash.. .213
3. Bucket II Unallocated G&A.. .214
4. Unitized Leases and After-Acquired Unitized Leases.'. .215
5. Potentially Defective Recording Leases. . .216
6. County Leases.. .216
7. Personal Property Liens.. .216
8. RBL Lenders’ Preference Claims and Second Lien Lenders’ Preference Claims... 217
9. Swap Payments.. .217
V.The Confirmation Hearing., .218
A. Confirmation Testimony.. .219
1. Mr. David J. Sambrooks.. .219
2. Mr. David Cecil.. .222
3. Mr. James Seery,. .226
4. Mr. Michael Magilton... 228
5. Mr. Jonathan (Joff) A. Mitchell.. .231
6. Mr. Christopher J, Kearns... 240
7. Mr. Steven M. Zelin.. .242
B. Evidentiary Matters Relating to Certain Confirmation Testimony.. .245
1.The Committee’s Motion to Exclude the Declarations and Testimony of Mr. Brandon Aebersold .. .245
2.The Debtors’ Motion to Exclude the Testimony of Mr. Adrian Reed...250
DISCUSSION.. .256
VI. Applicable Law.. .256
VII. The Process Undertaken by the Debtors and the Independent Directors Committee ...258
VIII. The Settlement Embodied in the Plan is Fair, Reasonable, and Well Above the Lowest Point in the Range of Reasonableness. ..261 '
A. The Settlement of the Adequate Protection Claims.. .261
1. An “Enterprise” Valuation In Which All Indirect Costs Are Deducted from the Value of the Reserves is Not Appropriate for Purposes of Estimating Collateral Diminution and the Adequate Protection Claims.. .262
2. Using the Mid-RAFs and High-RAFs to Risk-Adjust the Value of the Reserves is Appropriate... 268
3. The Court Must Consider the Most Recent Strip Pricing Data But May Also Consider Additional Strip Pricing Data. . .271
4. The Committee’s Other Critiques of the Debtors’ Estimate of the Adequate Protection Claims Do Not Withstand Scrutiny and Must be Rejected.. .274
a. Encumbrance Analysis.. .274
b. Postpetition Adequate Protection Payments and Application of Swap Payments.. .275
c. Postpetition Mineral Lien Payments. . .276
5. Additional Considerations Supporting the Reasonableness of the Debtors’ Estimate of the. Adequate Protection Claims.. .277
a. The Additional Haynesville Locations. . .277
*187 b.Mr. Mitchell’s Conservative, Committee-Favorable “Weighted Bucket II Approach”.. .278
B. The Settlement of the Bucket II Claims.. .279
1. The Two “Critical Wins”.. .279
2. Other Bucket II Claims... 284
a. Disputed Cash.. .284
b. Unitized Leases and After-Acquired Unitized Leases... 285
c. Potentially Defective Recording Leases.. .286
C. Other Settlements Embodied in the Plan...287
1. The RBL Release Satisfies Metrome-dia and is Justified in These Cases., .287
a. The Court Has Subject Matter Jurisdiction to Approve the RBL Release. . .289
b. The RBL Release Satisfies Me-tromedia and its Progeny.. .290
D. The Iridium Factors Weigh Decisively in Favor of Approval of the Settlement. . .294
1. The Uncontested Iridium Factors. . .295
a. Factor #5: The Competency and Experience of Counsel Supporting, and the Experience and Knowledge of the Judge Reviewing, the Settlement. . .295
b. Factor #7: The Extent to Which the Settlement is the Product of Arm’s Length Bargaining., .295
2. The Contested Iridium Factors. . .296
a. Factor #1: The Balance Between the Litigation’s Possibility of Success and the Settlement’s Future Benefits... 296
b. Factor #2: The Likelihood of Complex and Protracted Litigation, with its Attendant Expense, Inconvenience, and Delay., .306
c. Factor #3: The Paramount Interests of Creditors... 307
d. Factor #4: Whether Other Parties in Interest Support the Settlement ...308
e. Factor #6: The Nature and Breadth of Releases to be Obtained by Officers and Directors... 308
IX. The Plan Complies with Sections 1129(a) and (b) of the Bankruptcy Code and Other Confirmation Standards.. .310
A. Section 1129(a)(1).. .310
B. Section 1129(a)(2)...311
C. Section 1129(a)(3).. .312
D. Section 1129(a)(4)... 313
E. Section 1129(a)(5)... 313
F. Section 1129(a)(6).. .314
G. Section 1129(a)(7)... 314
H. Sections 1129(a)(8)-(13).. .316
I. Section 1129(b)... 316
J. The Plan Does Not Effect a De Facto Substantive Consolidation... 317
CONCLUSION.. .318
“It’s not even close.” So said Sabine’s Chief Restructuring Officer when asked his opinion during the confirmation hearing as to the reasonableness of the settlement embodied in the Debtors’ plan of reorganization.
Just six months ago, the Debtors in these chapter 11 cases engaged in a lengthy evidentiary hearing in this Court to determine whether or not the Official Committee of Unsecured Creditors should be granted so-called STN standing to pursue a sweeping set of claims against the Debtors’ lenders as well as the Debtors’ current and former officers and directors. Nine days of live testimony, hundreds of exhibits, and five days of closing argument *188 later, the Court denied the Committee’s request for STN standing. The proceedings took an enormous toll on the Debtors: tens of millions of dollars in litigation costs were incurred and key members of senior management had no choice but to attend every day of the hearing rather than focus on maintaining the stability of the business and the morale of their employees.
Undaunted, the Debtors filed a plan of reorganization, dated April 29, 2016, and commenced a confirmation hearing on Monday, June 13, 2016 — just thirty-six hours after arguing before the District Court on the Committee’s appeal of this Court’s STN decision. In the two months between the STN decision and the commencement of the confirmation hearing, the parties once again engaged in weeks of depositions, discovery, and pre-trial skirmishes. Five days into the hearing, the District Court issued its decision in favor of the Debtors on the STN appeal. Ten days of live testimony, hundreds of exhibits, and ten hours of closing argument later, it is eminently clear that the plan should be confirmed. The proceedings again took an enormous financial toll on the Debtors and visited further human capital costs on members of senior management and the Debtors’ employees.
What makes this case unique is not that it was litigious and expensive and exhausting for all involved. Rather, it is the enormous extent to which it was unnecessarily litigious and expensive. Notwithstanding the complexities of certain of the issues implicated by the Rule 9019 settlement that forms the basis of the plan — most notably, valuing oil and gas reserves in a volatile market — the settlement addresses and resolves the wide variety of challenges raised by the Committee, which seemed oblivious to the context and circumstances in which the case unfolded. During the year in which Sabine has operated under chapter 11 protection, dozens and dozens of oil and gas companies have been financially ravaged by plummeting commodity prices and have sought refuge in chapter 11. Thousands of jobs have been lost in Texas alone as rigs have been shut down and exploration activities curtailed. It is time for this oil and gas company to emerge from chapter 11 and, with a rightsized capital structure, focus anew on maximizing the value of its assets and allowing its employees to feel a measure of security.
The settlement contained in the plan is fair, reasonable, and well above the lowest point in the range of reasonableness and the plan otherwise satisfies each and every requirement for confirmation. It’s not even close.
BACKGROUND 1
I. Case and Company Background
Sabine Oil & Gas Corporation (“Sabine”) and its debtor affiliates, as debtor and debtors in possession in the above-captioned cases (collectively, the “Debtors” or the “Company”) are an independent energy company engaged in the acquisition, production, exploration, and development of onshore oil and natural gas properties in the United States. The Debtors constitute the surviving business from the business *189 combination (the “Combination”) of Forest Oil Corporation(“Legacy Forest”) and Sabine Oil & Gas LLC (“Legacy Sabine Parent”) that was first announced in May 2014 and consummated in December 2014.
On July 15, 2015 (the “Petition Date”), each of the Debtors filed a voluntary petition for relief under chapter 11 of the Bankruptcy Code (“the Code”). On July 28, 2015, the United States Trustee for Region 2 (the “U.S. Trustee”) appointed an official committee of unsecured creditors pursuant to section 1102 of the Bankruptcy Code (the “Committee”). 2
II. Events Leading to the Plan and Settlement
Two months prior to the Petition Date, Sabine’s board of directors approved the formation of a special committee (the “Independent Directors Committee”) to conduct and oversee an investigation of potential claims and causes of action related to the Combination that the Debtors may possess against creditors and others. The Independent Directors Committee was comprised of two independent directors, neither of whom had been involved in the Combination or had involvement with Legacy Sabine Parent or Legacy Forest at the time of the Combination. On June 10, 2015, Sabine’s board of directors approved an expansion of the Independent Directors Committee’s authority to decide which claims related to the Combination, if any, Sabine should assert. The Independent Directors Committee was assisted in its assessment of potential claims by legal advisors and restructuring specialists who initially included litigation attorneys from Kirkland & Ellis LLP (“Kirkland”) and financial advisors from Zolfo Cooper Management, LLC (“Zolfo Cooper”). The Independent Directors Committee later retained Professor Jack F. Williams to provide additional expertise and perspective on the Debtors’ potential constructive fraudulent transfer claims.
The Independent Directors Committee’s advisors analyzed over 100,000 documents over the course of more than six months in an effort to identify meritorious estate causes of action. In connection with the investigation, Professor Williams produced an extensive report, dated October 26, 2015, analyzing potential constructive fraudulent transfer claims (the “Williams Report”) 3 and, on December 1, 2015, the Independent Directors Committee adopted a detailed report prepared by Kirkland (the “December 1 Report”) analyzing potential claims for (i) intentional fraudulent transfers related to the Combination; (ii) breaches of fiduciary duty against (a) the pre-Combination Legacy Forest directors and officers (the “Legacy Forest Directors and Officers”); (b) the Legacy Sabine Parent board of directors; (c). Mr. David J. Sambrooks, as fiduciary for the subsidiaries of Legacy Sabine Parent (the “Legacy Sabine Subsidiaries”); 4 and (d) the members of the board of directors of Sabine who replaced the Legacy Forest board of directors at or around 1:20 p.m. EST on December 16, 2014 and met for the first time at 3:30 p.m. EST on December 16, 2014 (the “3:30 Board”); (iii) aiding and abetting breaches of fiduciary duty against *190 the RBL Lenders, 5 the Second Lien Lenders, 6 the Legacy Forest Directors and Officers, and the First Reserve Defendants (as defined below); (iv) equitable subordination of the claims of the RBL Lenders and the Second Lien Lenders (collectively, the “Prepetition Secured Lenders”); and (v) recharacterization as equity of the $50 million borrowed from the Second Lien Lenders by Sabine in connection with the Combination (collectively, the “Bad Acts Claims”).
The Williams Report and the December 1 Report provided the foundation for the Independent Directors Committee’s conclusion that, other than the claims for constructive fraudulent transfer asserted against the Second Lien Agent in the Adversary Proceeding filed by the Debtors, 7 there were no other colorable constructive fraudulent transfer claims, nor were there any other colorable claims arising from the Combination or related transactions that would benefit the estates.
On October 27, 2015, Sabine’s board of directors convened a meeting to discuss whether to pursue the so-called “Bucket II Claims,” a set of potential claims unrelated to the Combination, including, among others, claims challenging certain liens of the Prepetition Secured Lenders as beyond the scope of the applicable grant or as avoidable preferences. 8 After discussing at the meeting Kirkland’s analysis and recommendation regarding the Bucket II Claims, the Board of Directors determined not to pursue certain of the Bucket II Claims because doing so would not be in the best interest of the Debtors or then-stakeholders.
On November 2, November 11, and November 14, 2015, the Independent Directors Committee received demand letters from the Committee and the Forest Notes Trustees 9 with respect to (a) the Bad Acts Claims and (b) claims seeking, on behalf of (i) the Legacy Forest estate and (ii) the estates of the subsidiaries of the Legacy Sabine Subsidiaries, to avoid obligations incurred, liens transferred, and payments made in connection with or related to the Combination (the “Construc *191 tive Fraudulent Transfer Claims”). The Independent Directors Committee considered the claims raised in the demand letters, and it continued to conclude that no additional claims were colorable and beneficial to the estates.
On November 17, 2015, the Committee filed a motion for leave, standing, and authority to commence and prosecute certain claims and causes of action on behalf of the Debtors’ estates (the “First Committee STN Motion”), 10 which was followed on December 15, 2015 by a second motion seeking standing to pursue additional claims and causes of action (the “Second Committee STN Motion,” 11 and together with the First Committee STN Motion, the “STN Motions”). By the STN Motions, the Committee sought standing to pursue the Constructive Fraudulent Transfer Claims, the Bad Acts Claims, and the Bucket II Claims.
After a fifteen-day trial on the STN Motions which included ten days of live witness testimony and the submission of over 400 exhibits (the “STN Hearing”), the Court denied the STN Motions. 12 The Court found that the Bad Acts Claims and the Constructive Fraudulent Transfer Claims asserted were not colorable, with the exception of the Constructive Fraudulent Transfer Claims sought to be asserted on behalf of the Legacy Sabine Subsidiaries. Although the Court found this subset of Constructive Fraudulent Transfer Claims to be colorable, the Court concluded that it was not in the best interests of the Debtors’ estates to pursue such claims because the potential recovery was relatively low as compared to the high costs and risks to the Debtors’ estates associated with that litigation. 13 The Court also declined to rule on the colorability of the Bucket II Claims because the Debtors were pursuing a settlement of the Bucket II Claims in the context of the proposed plan of reorganization filed by the Debtors on January 26, 2016. 14
*192 III. The Plan
In January of 2016, before the commencement of the STN Hearing, the Court entered the Order Selecting Mediator and Governing Mediation Procedures [Dkt. No. 669] (the “First Mediation Order”) appointing the Honorable Allan L. Gropper (Ret.) as mediator (the “First Mediator”) in these chapter 11 cases. Through the First Mediation Order, the Court authorized the First Mediator to mediate any issues concerning, among other things, the terms of any plan of reorganization relating to the claims and causes of action raised in the Adversary Proceeding, the proposed complaints annexed to the STN Motions, the Williams Report, and the December 1 Report, as well as any issues related to the confirmation of a plan of reorganization (the “First Mediation”). In accordance with the terms of the First Mediation Order, the First Mediation Parties 15 submitted mediation statements and participated in several mediation sessions. The First Mediation culminated in an agreement among the Debtors and the RBL Lenders, the RBL Agent, the Second Lien Lenders, and the Second Lien Agent (collectively, the “Supporting Parties”) (who were also First Mediation Parties) on the terms of the restructuring transaction contemplated in the Plan (as defined below).
Accordingly, on March 31, 2016, the Debtors filed an amended version of the Standalone Plan [Dkt. No. 926] (the “March 2016 Plan”) and an amended version of the disclosure statement [Dkt. No. 927] reflecting the agreement among the Supporting Parties and the Debtors. On April 27, 2016, the Debtors filed the Second Amended Joint Chapter 11 Plan of Sabine Oil & Gas Corporation and its Debtor Affiliates [Dkt. No. 1041] (the “April 2016 Plan”) and related disclosure statement [Dkt. No. 1042] (the “Disclosure Statement”) (i) reflecting further discussions among the Supporting Parties and the Debtors and (ii) incorporating the STN Ruling.
On April 29, 2016, the Court entered the Order Approving (A) The Adequacy Of The Disclosure Statement, (B) Solicitation And Notice Procedures With Respect To Confirmation Of The Second Amended Joint Chapter 11 Plan Of Reorganization Of Sabine Oil & Gas Corporation And Its Debtor Affiliates, (C) The Form Of Ballots And Notices In Connection Therewith, And (D) The Scheduling Of Certain Dates With Respect Thereto [Dkt. No. 1050, as amended by Dkt. No. 1062] (the “Disclosure Statement Order”) approving the Disclosure Statement. On May 2, 2016, the Debtors filed final solicitation versions of the April 2016 Plan (the “Plan”) and the Disclosure Statement [Docket No. 1061], Shortly thereafter, the Debtors began solicitation of votes on the Plan.
In early May 2016, the Court ordered the parties to take part in a second round of mediation (the “Second Mediation”) 16 and appointed the Honorable Robert D. Drain (the “Second Mediator”) *193 as the mediator for the Second Mediation. The parties participating in the Second Mediation 17 were unable to reach a global settlement; on June 7, 2016, the Second Mediator filed his post-mediation memorandum stating his conclusion that “there is no prospect of a mediated settlement at this time.” 18
A. Summary of the Plan and the Settlement Embodied in the Plan 19
The centerpiece of the Plan is a settlement (the “Settlement”) of certain claims and causes of action that were asserted or could have been asserted by or against the Debtors including, but not limited to the Bucket II Claims and the Adequate Protection Claims (as defined below). 20 The Debtors submit that they have conducted “a lengthy and thorough analysis of the potential value of their unencumbered assets” and have concluded that, even in “the best possible scenario for the unsecured creditors” (ie., a scenario that (i) ignores risk of loss and assumes a total victory on each and every Bucket II Claim and (ii) ignores the substantial costs and delays associated with pursuit of the claims), 21 (a) the collateral .diminution suffered by the RBL Lenders entitles them to all of the value of the Debtors’ unencumbered assets on account of their adequate protection claims and (b) the adequate protection claims of the Prepetition Secured Lenders “swamp any recovery” on the Bucket II Claims. 22
Notwithstanding the entitlements of the Prepetition Secured Lenders, however, pursuant to the Settlement, unsecured creditors holding allowed claims will receive a recovery under the Plan. The Plan provides that (i) holders of Allowed RBL Secured Claims (as defined in the Plan) will receive ninety-three percent (93%) of the New Common Stock in the Reorganized Debtors 23 (the “RBL Equity Pool”); 24 (ii) holders of Allowed Second Lien Adequate Protection Claims will receive (a) five percent (5%) of the New Common Stock and (b) one hundred per *194 cent (100%) of the Tranche 1 Warrants 25 to be issued and outstanding as of the effective date (the “Second Lien Equity Pool); (iii) holders of Allowed Second Lien Deficiency Claims (Class 4b), Allowed 2017 Senior Notes Claims (Class 5a), Allowed 2019 Senior Notes Claims (Class 5b), Allowed 2020 Senior Notes Claims (Class 5c), and Allowed General Unsecured Claims (Class 6) will share pro rata in (x) the remaining two percent (2%) of the New Common Stock and (y) one hundred percent (100%) of the Tranche 2 Warrants 26 to be issued and outstanding as of the effective date of the Plan (the “Unsecured Equity Pool”). The parties disagree on the approximate value of the Unsecured Equity Pool to be distributed to Classes 4b, 5a, 5b, 5c, and 6 and, more specifically, on the value of both the Tranche 1 Warrants and the Tranche 2 Warrants.
Additionally, the Plan provides that the Reorganized Debtors on the effective date of the Plan (the “Effective Date”) will enter into (i) an exit revolver credit facility, which will consist of a new reserve-based revolving credit facility with $200 million of initial commitments that is being provided to the Debtors by each of the RBL Lenders on account of its pro rata share of the Allowed RBL Secured Claims (the “Exit Facility”) and (ii) a new second lien credit facility with a principal amount of $150 million.
The Plan also provides for the following releases: (i) releases by the Debtors of the secured lenders, the Committee, and certain other released parties set forth in Article YIII.F of the Plan (the “Debtor Release”); (ii) a third-party release by holders of claims or interests (who did not elect on their ballot to opt out of such release) of the Debtors, the Reorganized Debtors, the Committee, and other released parties as set forth in Article VIII.G of the Plan; and (iii) a mandatory release by holders of claims or interests (for which parties may not opt out) of the “RBL Released Parties,” who are defined in the Plan to include each of the RBL Agent, the RBL Lenders, and their respective affiliates, equity holders, and professionals as set forth in Article VIII.B of the Plan (the “RBL Release”). 27
*195 B. Voting Results
The deadline for all holders of Claims or Interests (each as defined in the Plan) entitled to vote on the Plan to submit their Ballots was June 3, 2016 at 5:00 p.m. (Eastern Time). Consistent with Local Bankruptcy Rule 3018-l(a), on June 6, 2016, the Debtors filed the voting certifications and reports of the Court-appointed Notice and Claims Agent, Prime Clerk LLC (the “Voting Certification”). 28 All classes of claims entitled to vote on the Plan voted to accept the Plan, with the exception of the three classes of notehold-ers, who voted to reject: Class 5a (2017 Senior Notes Claims); Class 5b (2019 Senior Notes Claims); and Class 5c (2020 Senior Notes Claims). 29 In total, over 470 creditors voted to accept the Plan, while only 216 creditors voted to reject the Plan.
C. Objections to the Plan
In addition to the objections related to the assumption of executory contracts or unexpired leases, 30 the Debtors received nine 31 other objections to Confirmation (including the objections of the Committee (the “Committee Objection”) 32 and the Forest Notes Trustees (the “Forest Objec *196 tion”)). 33
In support of its objection, the Committee submitted (i) three Declarations and Expert Reports of Christopher J. Kearns; 34 (ii) three Declarations and Expert Reports of Steven M. Zelin; 35 (iii) a Declaration and Expert Report of Adrian A. Reed; 36 and (iv) a Declaration of Anders T.C. Gibson. 37
In support of confirmation of the Plan and in response to the objections, the Debtors filed (i) the Debtors’ (I) Memorandum of Law in Support of Confirmation of Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization of Sabine Oil & Gas Corporation and Its Debtor Affiliates and (II) Omnibus Reply to Objections Thereto; 38 (ii) two Declarations of David Sambrooks; 39 (iii) two Declarations of Brandon Aebersold; 40 (iv) the Declaration of Michael Magilton; 41 (v) three Declarations and Expert Reports of Jonathan (Jofi) A. Mitchell; 42 (vi) four Declarations *197 and Expert Reports of David Cecil; 43 and (vii) the Voting Certification. 44
IV. Estimates of Adequate Protection Claims and Potential Bucket II Claims Recoveries
The principal dispute in these cases centers on the two most significant aspects of-the Settlement: the estimated amount of the Adequate Protection Claims and the estimated recoveries potentially available to unsecured creditors if the Bucket II Claims were litigated. The Committee argues that (i) the Debtors have failed to value the Bucket II Claims properly and, as a result, the Debtors are essentially abandoning the pursuit of claims that would significantly enhance unencumbered value and (ii) the Settlement rests on a significantly overstated estimate of the amount of the Adequate Protection Claims. 45 The Debtors contend that the settlement of the Bucket II Claims is unquestionably reasonable because, even adopting in large measure the Committee’s view of the value of the Bucket II Claims, the Adequate Protection Claims (as calculated by the Debtors) are so large that they will “swamp any recovery for such claims.” 46 The Debtors maintain that even in the best possible scenario for unsecured creditors (ie., a scenario that (i) ignores litigation risk and assumes 100 *198 percent cliance of success on the merits on each and every Bucket II Claim and (ii) ignores litigation costs and business costs), the collateral diminution suffered by the RBL Lenders entitles them to all of the value of the Debtors’ unencumbered assets on account of the RBL Lenders’ Adequate Protection Claim (as defined below). 47 A discussion of the parties’ positions with respect to the Adequate Protection Claims and the Bucket II Claims follows.
A. Estimates of the Adequate Protection Claims
Pursuant to the Code, a secured creditor is entitled to adequate protection of its interest in a debtor’s property to the extent that such interest declines in value during the course of a bankruptcy case. 48 Consistent with the Code’s requirements, in the early stages of these cases, the Debtors negotiated with the Prepetition Secured Lenders and the Committee to, among other things, reach agreement as to the Debtors’ use of the Prepetition Secured Lenders’ prepetition collateral during the course of the bankruptcy case and the form of adequate protection the lenders would receive from the Debtors. 49 One of the forms of adequate protection provided to the Prepetition Secured Lenders pursuant to the Final Cash Collateral Order is the right to assert a claim against the Debtors’ property pursuant to section 507(b) of the Code in an amount that is primarily determined by calculating the “Collateral Diminution,” defined in the Final Cásh Collateral Order as the “amount equal to the decrease in the value of the Prepetition Secured Lenders’ interest in the Prepetition Collateral 50 (including Cash Collateral) from and after the Petition Date, resulting from the use, sale or lease of the Prepetition Collateral (including Cash Collateral), or the imposition of the automatic stay.” 51
*199 The Settlement among the Debtors and their Prepetition Secured Lenders embodied in the Plan settles, among others things, the amount of the Adequate Protection Claims. The Debtors submit that the Collateral Diminution would be an amount that, absent a settlement, entitles the RBL Lenders “to all of the value of the Debtors’ unencumbered assets on account of their Adequate Protection Claims.” 52 The Debtors therefore argue that the settlement of the Adequate Protection Claims creates value for the Debtors’ other creditors. The Committee asserts, however, that the Debtors have vastly overestimated the amount of the Adequate Protection Claim of the RBL Lenders (the “RBL Lenders’ Adequate Protection Claim”), and that the Adequate Protection Claims, absent a settlement, would not exceed the value of the Debtors’ unencumbered assets. The Committee therefore objects to the reasonableness of the Settlement and the Plan on the grounds that the Settlement deprives the Debtors’ unsecured creditors of value that they could otherwise receive through litigation.
The Supreme Court of the United States has explained that a secured creditor’s interest in a debtor’s property is measured as the value of the collateral securing the debtor’s obligations to such creditor under section 506(a). 53 Section 506(a)(1) of the Code provides that in valuing a secured creditors’ interest in collateral, “[s]uch value shall be determined in light of the purpose of the valuation and of the proposed disposition or use of such property;” in the seminal case of Assocs. Commercial Corp. v. Rash, the Supreme Court explained that the latter prong of the section 506(a)(1) determination is “of paramount importance to the valuation question.” 54 A number of courts have interpreted the language of section 506(a)(1) to mean that collateral must be valued “in the hands of the Debtors.” 55 The legislative history of section 506(a) confirms that the valuation methodology varies on a case-by-case basis, and that courts should take into consideration the facts and competing interests of each case. 56
*200 The parties agree that Collateral Diminution should be calculated using (i) the going-concern value of the Debtors’ encumbered oil and gas assets (the “Reserve Collateral Value”) and (ii) the value of other assets on which the Prepetition Secured Lenders hold valid and perfected liens 57 (“Other Collateral Asset Value,” and together with the Reserve Collateral Value, the “Total Collateral Value”) at the Petition Date and at the anticipated Effective Date of June 30, 2016 (the “Forecast-ed Effective Date”). 58 To calculate the Reserve Collateral Value, the Debtors and the Committee each first calculated the value of all of the Debtors’ oil and' gas assets, encumbered and unencumbered (the “Reserves”), by performing the following steps: 59 (i) calculating an estimate of the going-concern value of the Debtors’ oil and gas reserves using a net asset value (“NAV”) approach to determine the present value (“PV-10”) of the future cash flows of the Reserves, net of certain expenses; 60 (ii) risk-adjusting the estimated present value of each reserve based on its categorization into one of five predictability categories (as indicated in the Debtors’ reserves report) 61 by applying a “Reserve Adjustment Factor” (“RAF”); 62 (iii) applying the results of an encumbrance analysis to calculate the estimated risk-adjusted Reserve Collateral Value; 63 and (iv) calculating the Collateral Diminution by quantifying the difference between the Reserve Collateral Value on the Petition Date and the Reserve Collateral Value on the Fore-casted Effective Date.
While they generally agree on the steps required to calculate the Collateral Diminution, the parties do not agree on the methodology for calculating the Adequate Protection Claims once the Petition Date Reserve Collateral Value and the Fore-casted Effective Date Reserve Collateral Value have been estimated. Their disagreement is largely driven by the fact that the Debtors and the Supporting Par *201 ties take the position, based on their expert’s estimate of the Petition Date Reserve Collateral Value, that the RBL Lenders were oversecured as of the Petition Date and the Second Lien Lenders were undersecured. In contrast, the Committee takes the position, based on its expert’s estimate of the Petition Date Reserve Collateral Value, that the RBL Lenders were undersecured as of the Petition Date and the Second Lien Lenders were thus entirely unsecured as of the Petition Date. Therefore, while each side’s expert calculates the Adequate Protection Claims (i) based on the Reserve Collateral Value on the Petition Date and as of the Forecasted Effective Date, and (ii) by giving effect to certain postpetition payments made to the Prepetition Secured Lenders, 64 they do not use the same methodology for doing so.
Relying on their estimates of the value of the Reserves, the Debtors and the Supporting Parties submit that the Total Collateral Value as of the Petition Date exceeded the principal amount of the RBL Lenders’ claim of $926.8 million and that the RBL Lenders were oversecured on the Petition Date. Accordingly, both the RBL Lenders and the Second Lien Lenders have sizable Adequate Protection Claims against the Debtors’ estates. 65 The Debtors estimate that, depending on whether value as of the Forecasted Effective Date is calculated using commodity prices as of March 22, 2016, May 20, 2016, June 10, 2016, or July 7, 2016, (i) the Collateral Diminution is between $417.5 million and $813.5 million and (ii) the RBL Lenders’ Adequate Protection Claim is between $227.9 million and $123.9 million. 66 The Debtors estimate that, regardless of which commodity prices are used, the Adequate Protection Claim of the Second Lien Lenders (the “Second Lien Lenders’ Adequate Protection Claim”) is $112.3 million. 67 The Debtors argue that, absent the Settlement, the RBL Lenders’ Adequate Protection Claim would “swamp” the Debtors’ unencumbered assets, and that therefore the Settlement, which provides value to the Second Lien Lenders and to the Debtors’ unsecured creditors, is reasonable and sat *202 isfies the standards under Bankruptcy Rule 9019. 68
The Committee disagrees. It disputes the Debtors’ valuation of the Reserves at both the Petition Date and the Forecasted Effective Date, as well as the Debtors’ methodology for calculating the Adequate Protection Claims. It argues that (i) the RBL Lenders were undersecured at the Petition Date; (ii) the Second Lien Lenders were unsecured at the Petition Date; and (iii) the Collateral Diminution does not exceed $86 million. As explained below, the Committee challenges on a number of grounds the Debtors’ calculations of the value of the Reserves on both the Petition Date and the Forecasted Effective Date and the Debtors’ methodology for quantifying the Adequate Protection Claims.
1. The Debtors’ Estimate of the Adequate Protection Claims
As explained above, the Debtors assert that the Plan reasonably settles the Adequate Protection Claims as part of an overall settlement between the Debtors and the Prepetition Secured Lenders. More specifically, the Debtors have estimated the Adequate Protection Claims for the purpose of evaluating the Settlement embodied in the Plan. 69 At the Confirmation Hearing, the Debtors elicited testimony from four witnesses relating to the Debtors’ approach to quantifying the Adequate Protection Claims: Mr. Cecil, the Debtors’ oil and gas asset valuation expert, who calculated the value of the Reserves; Mr. Sambrooks, who provided testimony about the Company’s reserves database (the “ARIES Database”), the predictability of the Debtors’ wells in certain geographical regions, and the appropriateness of Mr. Cecil’s application of a customized range of RAFs; Mr. Magilton, who supervised the Debtors’ encumbrance review and analysis; and Mr. Mitchell, who calculated the Collateral Diminution and estimated the Adequate Protection Claims for purposes of assessing the reasonableness of the Settlement.
The Debtors’ valuation expert, Mr. Cecil of Lazard, testified that his approach was to calculate a “going concern value for assets .., as prescribed by the development plan that’s put in place for those assets.” 70 Accordingly, Mr. Cecil calculated the value of the Reserves using an NAV approach, which the Debtors assert is industry-standard and customary for valuing oil and gas assets. 71 Mr. Cecil used the financial information included in the ARIES Database as of the Petition Date and as of the Forecasted Effective Date, respectively, to conduct his NAV analysis. Specifically, he began with the Debtors’ projected future production volumes of the Reserves and the applicable strip price 72 *203 to calculate future cash flows for each Reserve. 73
The projected net cash flows of the Debtors’ Reserves are summarized in the ARIES Database. The gross cash flows are calculated using the Debtors’ projection of volume production by each well and the Debtors’ commodity price forecasts. Mr. Cecil testified that the Debtors categorize their projected expenses as one of two types: (i) operating expenses and capital expenditures incurred by an individual well (“Direct Costs”), or (ii) expenses that are not incurred by an individual well (“Indirect Costs”). The net cash flow for each well in the ARIES Database is net of (a) Direct Costs for that well and (b) an allocation to that well of a portion of the Indirect' Costs pursuant to standards disseminated by the Council of Petroleum Accountants Societies, Inc. (“COPAS”, and such expenses, “COPAS Charges”). 74 As discussed infra, the parties disagree as to whether the COPAS guidelines are appropriate to use in this way.
At the Confirmation Hearing, Mr. Cecil explained that the Direct Costs are operating expenses that are recorded as well-level lease operating expenses (“LOE”): 75 capital expenditures, workover expenses, taxes, and lease operating expenses. The COPAS Charges, on the other hand, represent overhead costs indirectly associated with “field-level” activities that are necessary to maintain and preserve the value of the Debtors’ oil and gas assets which were accounted for, according to the Debtors, consistent with COPAS standards. 76 For example, COPAS recommends including in COPAS Charges a portion of expenses associated with administration, human resources, legal services, management, accounting and auditing, and warehousing. The Debtors take the position that the COPAS Charges are the only Indirect Costs that should be included in the NAV *204 valuation of the Reserves. 77
At the Confirmation Hearing, the Debtors elicited testimony from both Mr. Sam-brooks and Mr. Cecil that the allocation of costs associated with COPAS categories is a matter of negotiation between the Debtors and their joint working partners. As explained by Mr. Sambrooks, one of the terms of a joint operating agreement is the amount of the operator’s costs incurred in COPAS categories that will be charged to the non-operating partner. For those wells for which the Debtors do not have a joint interest partner, the amount of COPAS Charges deemed attributable to such wells is estimated by reviewing the allocation of COPAS Charges for comparable wells. 78 The Debtors maintain that burdening the projected value of the Reserves with Direct Costs and COPAS Charges accurately captures the projected net cash flows for each of the Debtors’ wells consistent with the industry standards for evaluating the going-concern value of oil and gas assets. 79
Using the Debtors’ projected net cash flows, Mr. Cecil then applied the industry-standard PV-10 to calculate the present value of the future cash flows. Next, Mr. Cecil risk-adjusted the PV-10 cash flows using the RAFs provided by SPEE to account for “the varying degrees of risk associated with projected volumes within each reserve category.” 80 Mr. Cecil applied a customized range of RAFs — the mid-RAFs and high-RAFs — “to capture the specific risk profile of the assets being evaluated.” 81 Both Mr. Cecil and Mr. Sam-brooks testified that using only the mid-RAFs and high-RAFs is appropriate here because the majority of the Reserves that comprise the Prepetition Collateral are located in plays 82 that are highly predictable and can be characterized as having low geologic risk, thus justifying a lower risk-adjustment. 83 Moreover, according to Mr. Cecil, it is common industry practice to apply a customized range of RAFs based on the predictability of well production when performing an NAV analysis. 84
After calculating the risk-adjusted value of the Debtors’ oil and gas assets, the Debtors then determined the Reserve Collateral Value as of the Petition Date and as of the Forecasted Effective Date by applying the results of the encumbrance review conducted by Mr. Magilton and his land team. This analysis identified which of the Reserves were part of the Prepetition Collateral securing the Debtors’ obligations to *205 the Prepetition Secured Lenders. Mr. Ma-gilton testified that the Debtors’ land team, working with the Debtors’ advisors, conducted a comprehensive review of leases, mortgages, acquisition schedules, and other documents to determine whether each well was encumbered or unencumbered as of the Petition Date and as of the Forecasted Effective Date. 85 Mr. Mitchell then used this well-by-well encumbrance review to calculate the Reserve Collateral Value as of the Petition Date and as. of the Forecasted Effective Date. 86 Mr. Mitchell employed what he has described as a “bottom-up” approach, in which he included, as part of the calculation of the Reserve Collateral Value, the value of only those Reserves that were reflected as “encumbered” in Mr. Magilton’s analysis. 87
In his expert reports and at the Confirmation Hearing, Mr. Mitchell explained that, to the extent there are disputes as to whether certain Reserves are encumbered or unencumbered, for purposes of estimating the Adequate Protection Claims, he assumed that (i) Reserves that are subject to the Second Lien Lenders’ Preference Claims (as defined below) or the County Leases issue (as defined below) are unencumbered, while (ii) the Reserves that are subject to other encumbrance disputes were encumbered. 88 Importantly, this is a more conservative (£&, Committee-favorable) approach to the encumbrance classification of the wells than an approach which classifies the encumbrance of the Reserves based on the Debtors’ view of the estimated chance of success on each encumbrance issue. This is especially so with respect to the County Leases issue, which has the greatest risked and unrisked notional value of all of the Bucket II Claims and to which the Debtors attribute a fifty percent chance Of success. 89
Mr. Mitchell then calculated the RBL Lenders’ Adequate Protection Claim by subtracting from the $926.8 million in outstanding principal owed to the RBL Lenders (i) $24.3 million of postpetition payments made by the Debtors to the RBL Lenders pursuant to the Final Cash Collateral Order, 90 comprising proceeds of the Debtors’ terminated swap agreements (the “Swap Payments”); (ii) $40.8 million of postpetition payments made by the Debtors to the RBL Lenders as adequate protection payments after the RBL Lenders became undersecured and no longer entitled to adequate protection, which the Debtors estimate occurred in October 2015; and (iii) the Total Collateral Value as of the Forecasted Effective Date, which ranges from $633.8 million to $737.8 million depending on which strip pricing assumptions are used.. This calculation resulted in an estimate of the RBL Lenders’ Adequate Protection Claim of $227.9 mil *206 lion' (using strip pricing data as of March 22, 2016) and $123,9 million (using strip pricing data as of July 7, 2016).
Mr. Mitchell then estimated the Second Lien Lenders’ Adequate Protection Claim by calculating the difference between the Total Collateral Value as of the Petition Date and the amount of the RBL Lenders’ claim (to wit, $1,051,3 million less $926.8 million); thus, the value of the Second Lien Lenders’ interest in the Prepetition Collateral as of the Petition Date was $124.5 million. As of the Forecasted Effective Date, no matter which strip pricing data is used, this value has been entirely eliminated, resulting in a $124.5 million decrease in the Second Lien Lenders’ interest in the Prepetition Collateral over that period. Consistent with his approach to calculating the RBL Lenders’ Adequate Protection Claim, Mr. Mitchell then reduced that amount by $12.2 million of postpetition adequate protection payments made by the Debtors to the Second Lien Lenders during the period that the Debtors estimate the Second Lien Lenders were underse-cured and therefore not entitled to receive adequate protection payments. As a result, Mr. Mitchell estimated the Second Lien Lenders’ Adequate Protection Claim to be $112.3 million.
2. The Committee’s Challenges to the Debtors’ Estimate of the Adequate Protection Claims
The Committee challenges the Debtors’ estimates of the value of the Reserves as of the Petition Date and as of the Fore-casted Effective Date primarily with respect to three issues: (i) whether, when calculating the value of the Reserves for purposes of calculating the Adequate Protection Claims, all general and administrative expenses (“G&A”) as well as “Land Expense” should be deducted from the cash flows of the Reserves; (ii) whether the use of the mid-point between the mid-RAFs and high-RAFs, rather than the midpoint of the low-RAFs, mid-RAFs, and high-RAFs is appropriate for risk-adjusting the value of the Reserves; and (iii) whether the consideration of commodity prices other than prices as of June 10, 2016 is appropriate for purposes of calculating the value of the Reserves as of the Forecasted Effective Date. 91 In addition to the foregoing, the Committee also challenges the Debtors’ estimate of the Adequate Protection Claims with respect to (a) the application of the Debtors’ Encum: brance Review (as defined below); (b) adjustments to the Adequate Protection Claims based on certain postpetition payments the Debtors made to the RBL Lenders and the Second Lien Lenders; and (c) the Debtors’ failure to adjust the RBL Lenders’ Adequate Protection Claim for postpetition payments made with respect to certain alleged mineral liens. 92
a. Deduction of All Indirect Costs (Whether or Not Included In CO-PAS Charges) from the Value of the Reserves
As described above, the Debtors’ valuation of the Reserves applies an NAV meth *207 odology to the future cash flows of the Reserves and nets out Direct Costs and COPAS Charges. While the Committee also uses an NAV methodology, the Committee’s valuation expert, Mr. Zelin, used the NAV methodology to calculate an enterprise valuation (as opposed to an asset valuation) based on the value of the Reserves. 93 The Committee argues that, in light of the Debtors’ pursuit of a restructuring through a plan of reorganization, an enterprise value, rather than the Debtors’ Reserves value, reflects the true going concern value of the Reserves in the hands of the Debtors. The Committee maintains that the Debtors’ Reserves valuation is in essence a sale valuation, not a going concern valuation, and does not reflect the “intended use” of the collateral in the hands of the Debtors as of the Petition Date because it ignores the overhead necessary to operate the business and realize the value of the Reserves pursuant to the Debtors’ business plan. 94
The Committee submits that Mr. Zelin’s valuation of the Reserves in this context properly burdens the value of the Reserves with Direct Costs and with all Indirect Costs 95 rather than only with Direct Costs and COPAS Charges as Mr. Cecil did. Mr. Zelin calculated total Indirect Costs by capitalizing the Debtors’ projected 2016 aggregate G&A run-rate using a multiple of 4.5x. 96 Using that approach, Mr. Zelin estimated that including all Indirect Costs (ie., costs of operating the Debtors’ business, all G&A, and Land Expense that are not directly attributable to specific Reserves) results in a $189 million downward adjustment to the Debtors’ valuation of the Reserves as of the Petition Date. 97
The Committee argues that these additional costs must be included in' the valuation of the Reserves as a going concern because they would necessarily be incurred as a cost of generating the Debtors’ projected cash flows. The Committee challenges the appropriateness of limiting the deduction of Indirect Costs to COPAS Charges in light of what it views as certain “anomalies” resulting from the Debtors’ calculations: (i) Mr. Cecil’s calculations resulted in a higher valuation for the Re *208 serves than for the entirety of the enterprise; (ii) Mr. Cecil’s calculation of COPAS Charges as of the Forecasted Effective Date reflects an increase in COPAS Charges of $24 million from the Petition Date to the Forecasted Effective Date despite the Debtors’ reduction in annual run-rate G&A of $40 million during that time; and (iii) Mr. Cecil’s calculation of COPAS Charges as of the Forecasted Effective Date results in an implied G&A multiple of 9.5x when compared to the Debtors’ projected 2016 G&A run-rate, more than twice the multiple that Mr. Cecil used for his own calculation of capitalized G&A. Stated more succinctly, the Committee argues that the Debtors’ valuation methodology inappropriately includes 100 percent of the value of the Reserves but only a portion of the costs associated with generating that value and is therefore inconsistent with the Debtors’ own business plan and with applicable standards for valuing collateral in the context of sizing the Adequate Protection Claims.
b. Reserve Adjustment Factors (RAFs)
While the parties agree that an RAF adjustment is appropriate to reflect the probabilities that the Reserves, as classified as IP (Proved), 2P (Probable), or 3P (Possible), 98 will produce, or continue to produce, hydrocarbons as predicted, the second basis on which the Committee challenges the Debtors’ valuation of the Reserves is the Debtors’ use of only the mid-RAFs and high-RAFs to risk-adjust the value of the Reserves.
The Committee argues that while Mr. Cecil’s NAV analysis incorporates risk adjustment factors that are technically “within the range” provided by SPEE, the Debtors’ exclusion of the low-RAFs is not appropriate here. The Committee rejects what it describes as Mr. Cecil’s only rationale for excluding the low-RAFs: that the Haynesville and Cotton Valley wells are more “predictable.” More specifically, the Committee asserts that (i) Mr. Cecil does not have sufficient expertise on the use of RAFs to make an independent determination of an appropriate customized RAF range; (ii) Mr. Cecil did not rely on any authority to justify basing such a determination only on the predictability of the Reserves; and (iii) Mr. Cecil did not independently verify the accuracy of the Debtors’ projections to determine if the use of only the mid-RAFs and high-RAFs was appropriate.
In support of the Committee’s position that a proper valuation of the Reserves must include the low-RAFs, Mr. Zelin testified that he relied on the report of the Committee’s expert, Mr. Adrian Reed, 99 and on a report by industry consultant Wood Mackenzie, dated April 2016, entitled “Haynesville Core Shale Gas Unconventional Play” (the “Wood Mackenzie Report”). 100 At the Confirmation Hearing, the Committee sought to introduce the expert testimony of Mr. Reed with respect to his assessment of, among other things, the quality and predictability of the Reserves for the purposes of determining the appropriate RAF range to use in valuing the Reserves. After Mr. Reed was questioned by counsel to the Debtors, however, the Committee largely acknowledged significant deficiencies in the reliability of Mr. *209 Reed’s testimony and opinions. Moreover, as discussed infra, to the extent the Court has concluded that certain of Mr. Reed’s opinions are admissible, such opinions shall not be afforded any evidentiary weight. 101 Relying on Mr. Reed’s opinions and the Wood Mackenzie Report, the Committee (per Mr. Zelin) submits that the valuation of the Debtors’ Reserves must include the low-RAFs and that doing so reduces the Adequate Protection Claims by approximately $83 million. . .
c. Strip Pricing
A key'variable in estimating the value'of the Reserves is the prevailing commodity price applicable to the Reserves. Both the Debtors’ experts and the Committee’s experts relied on the “strip pricing” of oil and natural gas to conduct their analy-ses. 102 The strip price represents prices “at which actual commodity volumes are being contracted for future delivery.” 103 In other words, while not a projection, strip prices are considered an appropriate source of information as to future movement in the commodity price because they are based on the pricing of commodity future contracts.
More than three months have now passed since the Debtors filed the Disclosure Statement, and more than three months have passed since the first expert reports were filed in anticipation of the Confirmation Hearing. Not surprisingly, commodity prices have changed on a daily basis over that time period. In his initial expert report dated May 13, 2016, Mr. Cecil, the Debtors’ valuation expert, estimated the value of the -Reserves as of the Forecasted Effective Date using the strip pricing of oil and natural gas as of March 22, 2016 to be approximately $580 million to $760' million (with a midpoint of $670 million). 104 The Committee’s expert, Mr. Zelin, then submitted his analysis, dated May 25, 2016, using the strip pricing of oil and natural gas as of May 20, 2016, estimating the value of the Reserves as of the Forecasted Effective Date to be approximately $365 million to $880 million (with a midpoint of $687 million). 105 Pursuant to a so-called “Strip Pricing Protocol” agreement between the Committee and the Debtors, 106 both Mr, Cecil and Mr. Zelin then provided updated estimates of the value of the Reserves as of the Forecasted Effective Date using the strip pricing of oil and natural gas as of June 10, 2016: Mr. Cecil estimated the value of the Reserves to be approximately $700 to $900 million (with a midpoint of $800 million) and Mr. Zelin estimated.the value of the Reserves to be $726 million. 107 Finally, both Mr. Cecil and Mr. Zelin’provided updated reports on July 11, 2016 indicating that (i) strip pricing had not materially changed between June 10, 2016 and July 7, 2016 and (ii) accordingly, the estimates generated using the June 10, 2016 strip pricing did not require updating. 108 The Court therefore has been provided with different esti *210 mates of the value of the Reserves at the Forecasted Effective Date based on strip pricing data as of multiple dates between March 2016 and July 2016. 109
While the Debtors urge the Court to focus primarily on the calculations based on the March 22, 2016 strip price but also to give consideration to the calculations based on the more recent strip price, the Committee argues that the Court must rely exclusively on the “most up to date” strip pricing available. 110 Although the Confirmation Hearing did not conclude until July 13, 2016, the Committee takes the position that, in the absence of a material change in pricing, the appropriate strip price to use in considering confirmation of the Plan is the June 10, 2016 strip price because it was the “most up-to-date information available ... as of the start of the confirmation hearing.” 111 As reflected in the various calculations of the value of the Reserves based on various strip pricing assumptions identified above, use of the June 10, 2016 strip price (instead of the March 22, 2016 strip price) results in an increase in the value of the Reserves as of the Forecasted Effective Date and a downward adjustment to the Collateral Diminution of $102 million. 112
d. Encumbrance Analysis
In order to calculate the portion of the value of the Reserves that constitutes value of the Collateral, the Committee engaged the law firm of Porter Hedges LLP (“Porter Hedges”) to conduct an encumbrance review of the Debtors’ records and related mortgage documentation. 113 Based on Porter Hedges’ encumbrance review, Mr. Kearns states that he determined, in the aggregate, that 81.7 percent of the Reserves were encumbered as of the Petition Date. 114 Mr. Kearns did not reach any conclusion with respect to the aggregate percentage of wells that were encumbered as of the Forecasted Effective Date. Mr. Zelin, purporting to rely on the work of Porter Hedges and Mr. Kearns, 115 applied an 84 percent aggregate encumbrance percentage as of the Petition Date and a 79 percent aggregate encumbrance percentage as of the Forecasted Effective Date. 116
In arriving at these encumbrance percentages, the Committee adopted Mr. Mitchell’s assumption that Reserves subject to the Second Lien Lenders’ Preference Claims and the County Leases issue are unencumbered but also assumed that the Reserves subject to the Potentially Defective Recording Leases, the Unitized Leases, and the RBL Lenders’ Preference *211 Claims (each as defined below) are unencumbered. 117 According to the Committee, the use of its encumbrance analysis instead of that of the Debtors results in a downward adjustment of approximately $16 million to the amount of the Collateral Diminution.
e. Postpetition Adequate Protection Payments and Application of Swap Payments
As described above, the Debtors deducted from the RBL Lenders’ Adequate Protection Claim $40.8 million of postpetition payments made by the Debtors to the RBL Lenders as adequate protection payments after the RBL Lenders-became un-dersecured in October 2015, as estimated by the Debtors. Because the Committee takes the position that the RBL Lenders were undersecured as of the Petition Date, it argues that an additional $15 million of postpetition payments made prior to October 2015 should also be deducted from the RBL Lenders’ Adequate Protection Claim.
In addition, the Committee argues that the $24.8 million of Swap Payments that Mr. Mitchell deducted from the outstanding principal amount of the RBL Lenders’ claim should instead be deducted from the RBL Lenders’ Adequate Protection Claim. Doing so would have no net effect on Mr. Mitchell’s calculations; however, because thé Committee posits that the RBL Lenders were undersecured as of the Petition Date, deducting the amount of the Swap .Payments from the RBL Lenders’ claim for amounts owed pursuant to the RBL Credit Agreement, under the assumption that the Committee is correct, would reduce by $24.3 million the RBL Lenders’ deficiency claim, not their Adequate Protection Claim, The Committee argues that the Debtors’ interpretation of the Final Cash Collateral Order ignores the proviso to the requirement that .the Swap Payments reduce the RBL Lenders’ claim, which states that the Swap Payments should be “unwound if the Court ... finds that such payments unduly disadvantaged the Debtors or unsecured creditors.” 118 Because the RBL Lenders were underse-cured at the Petition Date, the Committee contends, merely reducing the RBL Lenders’ unsecured deficiency claim by the amount of the Swap Payments would unduly disadvantage' unsecured creditors in comparison to reducing the RBL Lenders’ claim. Therefore, the Committee contends that the $24,3 million of Swap Payments should reduce the RBL Lenders’ Adequate Projection Claim, not the amount of the RBL Lenders’ claim for outstanding principal due and owing pursuant to the RBL Credit Agreement. .
f. Postpetition Mineral Lien Payments
The Committee further challenges the Debtors’ Collateral Diminution calculation on the basis that $17 million in certain postpetition payments made by the Debtors to lienholders whose liens arguably have priority over the liens of the RBL Lenders in effect increased the value of the Prepetition Collateral. The Committee argues the $17 million paid pursuant to a Court order 119 has not been reimbursed, and, therefore, the RBL Lenders’ Adequate Protection Claim must be reduced dollar-for-dollar by that amount. Mr. Zelin *212 testified that he deducted $17 million from the RBL Lenders’ Adequate Protection Claim based on advice of counsel for the Committee, and that he did not conduct his own analysis of the issue. 120 The Committee cites no authority for its position. 121
B. Estimates of Potential Bucket II Claims Recoveries
In addition to settling the Adequate Pro- - tection Claims, the Settlement resolves all disputes included in the Bucket II Claims. The Debtors maintain that a settlement of the Bucket II Claims provides significant value to unsecured creditors that would otherwise not be available due to the size of the RBL Lenders’ Adequate Protection Claim. 122 According to the Debtors, a resolution of the Bucket II Claims avoids the significant cost and delay associated with litigating these issues with the RBL Agent, the RBL Lenders, the Second Lien Agent, and the Second Lien Lenders, each of whom would vigorously defend its positions with respect to the Bucket II Claims. 123 Based on Mr. Cecil’s $550 million total enterprise value, the Debtors estimate that (i) the maximum potential amount which could be recovered on account of the Bucket II Claims is $192.7 million without accounting for any risk and (ii) the risk-adjusted maximum amount which could be recovered on account of the Bucket II Claims is $89.1 million. Based on Mr. Zelin’s $726 million total enterprise value, the Debtors estimate that (a) the maximum potential amount which could be recovered on account of the Bucket II Claims is $230.4 million without accounting for any risk and (b) the risk-adjusted maximum amount which could be recovered on account of the Bucket II Claims is $108.8 million.
The Committee does not dispute these maximum potential amounts; indeed, Mr. Kearns testified that he did not disagree with the methodology used by Mr. Mitchell in calculating them. The Committee, however, contends that the Debtors understate the risk adjustments (i.e., the Committee’s chance of success on the merits) and in doing so, underestimate the amounts that could be recovered from litigating the Bucket II Claims. The Committee did not provide its own risk-adjusted amounts for the Bucket II Claims based on Mr. Cecil’s $550 million enterprise value; however, based on Mr. Zelin’s $726 million enterprise value, the Committee estimates that the risk-adjusted maximum amount which could be recovered on account of the Bucket II Claims should be $120.1 million. Mr. Kearns’ calculations of the risk-adjusted amounts of the Bucket II Claims utilized the same risk adjustments that the Debtors used for nine of the ten Bucket II Claims. The only Bucket II Claim for which Mr. Kearns assumed a chance of success different from the Debtors’ proposed chance of success (100 percent instead of the Debtors’ five percent) is the RBL Lenders’ Preference Claim (as defined below), based on the Committee’s position that the RBL Lenders were un-dersecured as of the Petition Date. The Committee did not present an independent view of the estimated chances of success for the other Bucket II Claims.
Neither the Debtors nor the Committee disputes that (i) the potentially recoverable amounts on account of the Bucket II Claims must be reduced by litigation *213 costs; 124 and (ii) the value of certain Bucket II Claims is directly tied to the value of the Reserves (ie., the potentially recoverable amounts on account of certain Bucket II Claims increase when the value of the Reserves increases). The Bucket II Claims that are directly tied to the value of the Reserves are: Bucket II Unencumbered Assets, Unitized Leases and After-Acquired Unitized Leases, Potentially Defective Recording Leases, County Leases, RBL Lenders’ Preference Claims, and Second Lien Lenders’ Preference Claims (each as defined below). A discussion of each of the Bucket II Claims, including the parties’ positions with respect thereto, is outlined below. For each Bucket II Claim summary, the maximum amount potentially recoverable on account of each Bucket II Claim and the risk-adjusted amount potentially recoverable on account of each Bucket II Claim are based on Mr. Zelin’s $726 million enterprise value using June 10, 2016 strip pricing.
1. Bucket II Unencumbered Assets
This Bucket II Claim (“Bucket II Unencumbered Assets”) relates to allegedly unencumbered wells located in counties in which no mortgage was filed by the Pre-petition Secured Lenders. According to Mr. Mitchell, these unencumbered wells are primarily located in the Debtors’ Woodardville field in Red River, Louisiana. 125 The Debtors and the Committee agree that the total maximum amount potentially recoverable on account of this Bucket II Claim is $24.3 million. Neither the Debtors nor the Committee provided an estimated chance of success on this issue.
2. Disputed Cash
On February 25, 2015, the Company drew down substantially all of the remaining availability under the RBL Credit Agreement in an attempt to secure additional liquidity, fund ordinary course business operations, and preserve optionality in the event of a restructuring (the “Revolver Draw”). The Debtors placed the funds from the Revolver Draw into the Debtors’ main operating account (the “Operating Account”). Between the time of the Revolver Draw and the Petition Date, (i) the funds from the Revolver Draw; (ii) the Debtors’ unencumbered cash from operations; and (in) the Debtors’ encumbered cash proceeds of Prepetition Collateral were commingled in the Operating Account. As of the Petition Date, the Operating Account had a balance of approximately $252 million, which amount the Debtors contend comprised the “Disputed Cash.” The RBL Agent disagrees with the position of the Debtors and the Committee with respect to whether the Disputed Cash was encumbered or unencumbered, arguing that its liens on the Debtors’ personal property include the Disputed Cash and that the Disputed Cash is subject to a constructive trust. The Debtors and the *214 Committee, however, assert that all of the Disputed Cash was unencumbered as of the Petition Date.
The Committee also contends that the Disputed Cash balance will be approximately $21.3 million as of the Forecasted Effective Date. 126 The Kearns Initial Report explains that the Company’s cash is segregated in a separate account for the benefit of the RBL Lenders on a monthly basis and is calculated as monthly net operating results, less capital expenditures attributable to encumbered wells for the postpetition period, as determined by the Debtors. 127 According to Mr. Kearns, the Committee’s lien analysis concluded that 81.7 percent of proved reserves were encumbered as of the Petition Date. 128 As a result of the Committee’s lien analysis, Mr. Kearns calculated that the Disputed Cash balance would be approximately $21.3 million as of the Forecasted Effective Date. However, for purposes of his analysis of the Bucket II Claims, Mr. Kearns stated that he did not utilize this $21.3 million figure and instead adopted the $8.4 million figure forecasted by the Debtors. 129
Although the RBL Lenders continue to disagree with both the Debtors’ analysis and the Committee’s analysis, they have agreed to settle this claim as part of the Plan. The Debtors state that the total maximum amount potentially recoverable on account of this Bucket II Claim is $8.4 million (which is disputed by Mr. Kearns but nonetheless adopted by him for the purpose of his Bucket II Claims analysis). After applying a ninety percent chance of success, the Debtors estimate that a maximum of $7.6 million is recoverable on account of this Bucket II Claim.
3. Bucket II Unallocated G&A
This Bucket II Claim (“Bucket II Unallocated G&A”) represents a claim for general and administrative expenses incurred by the Debtors after the Petition Date that were paid by the Debtors using Disputed Cash. Paragraph 11 of the Final Cash Collateral Order provides that the Debtors and the Committee reserved their respective rights to assert that a portion of the Unallocated G&A (as defined in the Final Cash Collateral Order) 130 should be, or should have been, payable from the Segregated Cash Collateral 131 and the Prepetition Secured Lenders reserved their rights to oppose such relief. 132 The Committee argues that general and administrative costs incurred by the estates during the case that are not otherwise allocated at the well-by-well level should be charged to the Segregated Cash Collateral. The Committee contends that this approach is appropriate because the general costs of the business (including corporate overhead and senior executive compensation programs that the RBL Lenders supported) *215 should not be borne solely by unsecured creditors who are receiving a minimal recovery under the Plan. Therefore, the Committee asserts that the costs of the case should be borne proportionately to the benefit received — in this case, by the ratio of encumbered to unencumbered asset value. The RBL Lenders disagree.
At the STN Hearing, the Committee asserted that 82 percent of the Debtors’ Unallocated G&A (as defined in the Final Cash Collateral Order) should be allocated to the encumbered wells. The Debtors posit that, if the Committee is correct, there would be $27.4 million of Disputed Cash on the Forecasted Effective Date in addition to the approximately $8.4 million of Disputed Cash reflected in the Debtors’ forecast. The Debtors have adopted the Committee’s $27.4 million figure in their analysis of this Bucket II Claim issue, despite the fact that the Debtors do not agree that 82 percent of the Unallocated G&A (as defined in the Final Cash Collateral Order) can or should be allocated to the encumbered wells. After applying a fifty percent chance of success, the Debtors estimate that a maximum of $13.7 million is recoverable on account of this Bucket II Claim.
4. Unitized Leases and After-Acquired Unitized Leases
Certain of the Debtors’ predecessors-in-interest granted security interests in favor of the RBL Agent in properties that now belong to the Debtors pursuant to several mortgage documents (collectively, the “RBL Mortgages”) and granted mortgages on substantially the same properties to the Second Lien Agent (collectively, the “Second Lien Mortgages”). Each of the RBL Mortgages and the Second Lien Mortgages at issue contains a clause that specifically grants a security interest in “[a]ll rights, titles, interests and estates now owned or hereafter acquired by [the Debtors] in and to (i) the properties now or hereafter pooled or unitized with the Hydrocarbon Property” (each such clause, a “Unitization Clause”). 133 The Unitization Clause relates to certain “unitized” oil and gas leases (collectively, the “Unitized Leases”). The Unitization Clause also purports to grant a security interest in all after-acquired leases pooled or unitized with such Hydrocarbon Properties (collectively, the “After-Acquired Unitized Leases” and, together with the Unitized Leases, the “Unlisted Leases”).
The RBL Agent and the Second Lien Agent assert that they have valid, perfected mortgages on all of the Unlisted Leases under Texas law. The Committee, on the other hand, argues that, as a matter of Texas law, the liens held by the RBL Agent and the Second Lien Agent do not extend to any of the Unlisted Leases; the Committee did not present any evidence at the Confirmation Hearing relating to this Bucket II Claim.
The Debtors have estimated that there is an approximately fifteen percent chance that the Debtors would be successful in demonstrating that the prepetition liens held by the RBL Agent and the Second Lien Agent do not extend to the Unitized Leases, and a fifty percent chance of demonstrating that the prepetition liens held the RBL Agent and the Second Lien Agent by do not extend to the After-Acquired Unitized Leases, for a blended success rate of 32.5 percent. Per the Debtors, the total maximum amount potentially recoverable on account of this Bucket II Claim, without accounting for litigation risk, is $19 million. After applying a 32.5 percent chance of success, the Debtors *216 estimate that a maximum amount of $6.2 million would be recoverable on account of this Bucket II Claim.
5.Potentially Defective Recording Leases
Certain of the Debtors’ predecessors-in-interest filed mortgages on their oil and gas leases and wells in favor of the Prepet-ition Secured Lenders. The Committee has identified 199 of such leases that were or may have been included in the lease schedules attached to the RBL Mortgages or the Second Lien Mortgages, but allegedly include defective descriptions of the property covered by such mortgages (collectively, the “Potentially Defective Recording Leases”).
The Debtors have concluded that any errors or omissions are minor and insufficient to render the mortgages ineffective inasmuch as the collateral is still clearly identifiable, and they assert that the total maximum amount potentially recoverable on account of this Bucket II Claim, without accounting for litigation risk, is $5.5 million. After applying a thirty percent chance of success, the Debtors estimate that a maximum of $1.6 million would be recoverable on account of this Bucket II Claim.
6.County Leases
This Bucket II Claim (the “County Leases issue”) arose as a result of the Prepetition Secured Lenders’ assertion that they hold a valid mortgage on all 3,338 of the leases located in the counties in which the RBL Mortgages and the Second Lien Mortgages were filed (the “County Leases”). The Prepetition Secured Lenders assert that the broadly-drafted granting clauses in each of the RBL Mortgages and the Second Lien Mortgages provide the Prepetition Secured Lenders with perfected blanket liens on all of the Debtors’ real property interests located in the counties in Texas in which an RBL Mortgage or a Second Lien Mortgage has been recorded and that the RBL Mortgages and the Second Lien Mortgages satisfy the Statute of Frauds under Texas law.
The Debtors acknowledge that the granting clause in the RBL Mortgages and the Second Lien Mortgages is broadly drafted. In light of the recent decision of the United States Bankruptcy Court for the District of Delaware in In re Quicksilver Res., Inc., 134 which applied Texas law in upholding a blanket lien on real property interests, the Debtors have revised their earlier conclusion and now believe that a court would likely find that the County Lease Granting Clause (as defined below) effectively covers and grants a hen in all of the Debtors’ oil and gas leases in each county in which an RBL Mortgage and a Second Lien Mortgage were filed — not just those counties set forth on Exhibit A to the RBL Mortgages and the Second Lien Mortgages. The Committee challenges the Debtors’ reliance on Quicksilver and contends that the critical facts and underlying mortgages here are substantially different from those in Quicksilver.
The total maximum amount potentially recoverable on account of this Bucket II Claim, without accounting for litigation risk, is $93.1 million. After applying a fifty percent chance of success, the Debtors estimate that a maximum of $46.5 million is recoverable on account of this Bucket II Claim.
7.Personal Property Liens
The RBL Lenders assert that they have blanket liens on all of the Debtors’ personal property, including general intangibles', *217 accounts, inventory, and as-extracted collateral, whether or not related to hydrocarbons. According to the Debtors, the language of the RBL Mortgages and the Second Lien Mortgages includes only personal property related to the mortgaged hydrocarbons in the Prepetition Secured Lenders’ collateral package and, accordingly, the Prepetition Secured Lenders would likely not prevail in asserting liens over personal property unrelated to the mortgaged hydrocarbons. The personal property at issue consists of (i) unused pipe for transporting oil and gas; (ii) undeveloped leased and owned acreage; (iii) office equipment; (iv) various field locations; and (v) thirty-seven trucks used by field personnel. At the outset of the negotiations with the RBL Lenders, the Debtors estimated that the total value of such personal property could be as much as $15 million. However, after further analysis, the Debtors adjusted this figure to $6.8 million. The Committee has not disputed the Debtors’ $6.8 million figure. 135 Neither the Debtors nor the Committee has provided an estimated chance of success on this issue.
8. RBL Lenders’ Preference Claims and Second Lien Lenders’ Preference Claims
The Debtors have considered whether the liens granted to the RBL Lenders (the “RBL 90-Day Mortgages”) and the Second Lien Lenders (the “Second Lien 90-Day Mortgages” and together with the RBL 90-Day Mortgages, the “90-Day Mortgages”) pursuant to their respective forbearance agreements could be avoided as preferential transfers under section 547(b) of the Code. These two buckets of claims are (i) the “RBL Lenders’ Preference Claims,” which refers to litigation involving potential preferential transfer claims on account of the RBL 90-Day Mortgages and (ii) the “Second Lien Lenders’ Preference Claims,” which refers to litigation involving potential preferential transfers on account of the Second Lien 90-Day Mortgages.
The Debtors’ estimated maximum amount potentially recoverable on account of the RBL Lenders’ Preference Claims, without accounting for litigation risk, is $12 million. The Debtors estimate that they would have less than a five percent chance of success on this issue and conclude that $0.6 million is the risk-adjusted maximum potential amount recoverable on account of this Bucket II Claim. The RBL Lenders’ Preference Claims are the only Bucket II Claim for which the Committee provided a risk-adjusted amount different from that proposed by the Debtors. Because the Committee asserts that the RBL Lenders were undersecured as of the Petition Date, the Committee forecasts a 100 percent chance of success on this claim, resulting in a risk-adjusted total maximum amount of $12 million.
While the Debtors and the Committee do not provide an estimated chance of success with respect to avoiding the liens granted to the Second Lien Lenders on account of the Second Lien 90-Day Mortgages, the Debtors have forecasted that the total maximum amount recoverable with respect to the Second Lien Lenders’ Preference Claims is $1.5 million.
9. Swap Payments
Prior to the Petition Date, the Company or one of its predecessors-in-interest entered into ISDA Master Agreements (collectively, and as amended, modified, or supplemented from time to time in accordance with the terms thereof, the “Swap Agreements”) with seven financial institu *218 tions (collectively, the “Swap Counterparties”) to hedge the pricing risk associated with floating commodity prices. Prior to or shortly after the Petition Date, each of the Swap Counterparties terminated their Swap Agreements with Sabine. Two of the Swap Counterparties — Huntington National Bank (“Huntington”) and Merrill Lynch Commodities (“ML Commodities”) — terminated their Swap Agreements on July 16, 2015 and July 15, 2015, respectively. Both Huntington and ML Commodities remitted to the Debtors the Swap Payments, cash proceeds that resulted from the termination of their respective Swap Agreements. Upon receiving the Swap Payments, the Debtors remitted the Swap Payments to the RBL Agent, who then applied such proceeds to reduce the principal amount outstanding under the RBL Credit Agreement.
Pursuant to the Final Cash Collateral Order, the postpetition payment of swap amounts to the RBL Lenders, and concomitant reduction in the principal amount owed to the RBL Lenders under the RBL Credit Agreement, can only be unwound if such payments “unduly disadvantaged” the unsecured creditors. 136 The Debtors assert that the Swap Payments did not unduly disadvantage unsecured creditors because (i) such payments were contemplated, and approved, as adequate protection payments to the RBL Lenders and were made pursuant to the Final Cash Collateral Order; (ii) the RBL Lenders were overse-cured on the Petition Date and the Swap Payments reduced the principal amount of the RBL Lenders’ claims and therefore, the Swap Payments are net neutral to, rather than disadvantageous to, unsecured creditors; and (iii) due to the substantial adequate protection liens and claims of the Prepetition Secured Lenders, even if the Swap Payments were to be unwound or clawed back, the RBL Lenders’ adequate protection liens and claims would increase in an amount equal to the unwound amount and, thereafter, the RBL Lenders would recover such amounts with respect to their adequate protection liens and claims.
The Debtors argue that the Committee, in its analysis, erroneously reduces the RBL Lenders’ Adequate Protection Claim by reducing such claim by the $24 million Swap Payments, pointing out that under the Final Cash Collateral Order, it is the RBL Lenders’ claim for principal amounts due and owing under the RBL Credit Agreement as of the Petition Date that should be reduced (from $927 million to $903 million). Notwithstanding the disagreement, the Debtors and the Committee agree that the total amount of the Swap Payments is $24.8 million. The Debtors estimate that they would have a less than a 2 percent chance of success on this issue and estimate that $0 is recoverable on account of this Bucket II Claim.
V. The Confirmation Hearing
The confirmation hearing on the Plan (the “Confirmation Hearing”) took place over twelve days, beginning on June 13, 2016, and concluding with approximately ten hours of closing arguments held on July 13, 2016. At the Confirmation Hearing, the following nine witnesses gave live testimony: (i) Mr. David J. Sambrooks; (ii) Mr. David Cecil; (iii) Mr. James Seery; (iv) Mr. Brandon Aebersold; (v) Mr. Michael Magilton; (vi) Mr. Jonathan (Joff) A. Mitchell; (vii) Mr. Adrian A. Reed; (viii) Mr. Christopher J. Kearns; and (ix) Mr. Steven M. Zelin. Admitted into the record were the declarations of *219 each of the witnesses as well as the Declaration of Anders T. C. Gibson in Support of the Committee Objection 137 and deposition designations of Mr. Gibson. Finally, several hundred exhibits and hundreds of pages of demonstratives were made part of the record of the Confirmation Hearing.
On July 27, 2016, the Court entered the Findings of Fact, Conclusions of Law, and Order Confirming the Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization [Dkt. No. 1368, as corrected by Dkt. No. 1359] (the “Confirmation Order”). 138 The Committee has filed an appeal of the Confirmation Order [Dkt. No. 1360] 139 and the following indenture trustees have also appealed the Confirmation Order: (i) The Bank of New York Mellon Trust Company, N.A., as Indenture Trustee for the 2017 Notes [Dkt. No. 1374]; (ii) Wilmington Savings Fund Society, FSB, as Indenture Trustee for the 2019 Notes [Dkt. No. 1375]; and (iii) Delaware Trust Company, as Indenture Trustee for the 2020 Notes [Dkt. No. 1376]. A motion to consolidate the aforementioned appeals has been filed. 140
A. Confirmation Testimony
1. Mr. David J. Sambrooks
Mr. Sambrooks is the President, Chief Executive Officer, and Chairman of the Board of Sabine. His thoughtful and deliberate testimony over the course of two days included (i) a summary of the negotiation process leading up to the Plan; (ii) his understanding of the standards developed by COPAS for evaluating the allocation of various operating expenses on a well-by-well basis; and (iii) a comprehensive overview of the Debtors’ process for evaluating the predictability of production for the wells located in the Haynesville and Cotton Valley plays in East Texas. Reflecting his unflagging commitment to the reorganization of Sabine, Mr. Sambrooks was present in the courtroom for the entirety of the Confirmation Hearing.
Mr. Sambrooks provided a brief description of the Debtors’ business, stating that natural gas reserves comprise eighty-five percent of the Company’s reserves and the majority of the value lies in the Company’s proved, developed producing (IP) wells. 141 Mr. Sambrooks explained that the Company’s reservoir engineers employ the SPEE industry-standard methodology to evaluate the predictability of the Company’s wells, the majority of which are located in “unconventional” 142 plays concentrated in East *220 Texas. 143 The projections are then entered into the ARIES Database and are typically updated at the end of each year. 144 Mr. Sambrooks testified that the Debtors verify the accuracy of their projections for the proved reserves by submitting the ARIES Database to an independent reservoir engineering consultant, Ryder Scott Petroleum Consultants (“Ryder Scott”). Once Ryder Scott completes its independent evaluation of the Company’s proved reserves, it returns the ARIES Database to the Company and provides the Company with a certified reserve report. The Company typically conducts a variance analysis upon receiving Ryder Scott’s evaluation; Mr. Sambrooks stated that the variance analysis for 2015 resulted in a .5 percent variation, meaning that the production projections of the Company and Ryder Scott were “essentially the same.” 145
Moreover, based on his extensive experience as a reservoir engineer, Mr. Sam-brooks stated his opinion that the Haynes-ville and Cotton Valley plays are among the “most predictable plays” that he has seen in his career due to their geologic characteristics and the substantial amount of subsurface and production information available with respect to these plays. 146 In his rebuttal report to the report of Mr. Reed, Mr. Sambrooks explained that the industry-standard methodology to assess the predictability of unconventional assets is provided by the SPEE 147 and instructs using ratios measuring well performance generally normalized for lateral length of the well in the case of horizontal wells. 148 In that same report, Mr. Sambrooks explained that Mr. Reed’s method of assessing predictability of the Debtors’ assets using the number of wells drilled in certain plays does not conform to the SPEE’s industry-standard methodology. 149 Mr. Sambrooks also stated his opinion that there is no basis to use, as Mr. Reed did, the Wood Mackenzie Report’s classification of certain Haynesville assets as “Tier II” to conclude that such assets are less predictable than other Haynesville assets because “Wood Mackenzie’s tiers relate to productivity, not predictability” based on a review of the well economics and natural geological constraints” of Tier II assets as compared to Tier I Haynesville assets. 150
Furthermore, in the Sambrooks Rebuttal Report, Mr. Sambrooks challenged the validity of Mr. Reed’s “regression analysis” which, according to Mr. Reed, was based on data from sixty-one wells. Mr. *221 Sambrooks expressed his opinion that Mr. Reed’s conclusions were in fact based on only two data points within that regression. 151 Mr. Sambrooks also challenged Mr. Reed’s conclusions arising from a comparison of type curves, explaining that Mr. Reed simply compared the Debtors’ type curves to type curves that he himself had generated for wells in Haynesville and Cotton Valley, a comparison that does not demonstrate how the Debtors’ type curve projections compare to recent well results. 152 Mr. Sambrooks opined that Mr. Cecil’s use of the mid-RAF and high-RAF customized range was appropriate.
Mr. Sambrooks pointed out that among the costs included in the cash flow projections of the ARIES Database are COPAS Charges. According to Mr. Sambrooks, COPAS establishes guidelines for assigning indirect overhead costs on a well-by-well basis and such overhead costs include, among other things, inventory, human resources, and procurement. Mr. Sambrooks explained that pursuant to the COPAS guidelines, only overhead costs that relate to the maintenance and operation of the Company’s reserves are allocated to the wells. 153 Moreover, the amount of COPAS Charges that is reflected in the ARIES Database for a particular well depends, in part, on whether the well is jointly operated (ie., owned and operated by a third party) or owned and operated entirely by Sabine. With respect to wells that are jointly operated, Mr. Sambrooks explained that the categories and allocation of CO-PAS Charges are negotiated with the Company’s joint interest partners and subsequently memorialized in a joint operating agreement. With respect to wells that are not jointly operated, Mr. Sambrooks explained that the amount of COPAS Charges for such wells is determined by Sabine’s reviewing COPAS Charges allocated to comparable wells and then, in essence, charging itself an appropriate CO-PAS-based amount.
Mr. Sambrooks briefly described the negotiation process leading up to the proposal of the Plan. He stated that, in the fall of 2015, the Debtors engaged in negotiations with their secured lenders about the terms of a potential plan of reorganization. 154 However, when the Debtors met with the Committee in the fall of 2015, Mr. Sam-brooks learned that the Committee wanted to pursue a sale of the Debtors’ assets in lieu of pursuing a plan of reorganization. 155 Although the RBL Lenders and the Second Lien Lenders had not supported the Standalone Plan filed in January 2016, all of the Prepetition Secured Lenders supported the March 2016 Plan. Mr. Sam-brooks explained that, unlike the Standal *222 one Plan, the March 2016 Plan (i) did not contemplate the allowance of a deficiency claim for the RBL Lenders and (ii) contained a provision for the distribution of the Tranche 1 Warrants for the Second Lien Lenders and the Tranche 2 Warrants for unsecured creditors. Mr. Sambrooks stated that the Debtors continued negotiations and ultimately filed the Plan in April 2016, which was “materially consistent” with the March 2016 Plan. 156 Mr. Sam-brooks expressed his view that without a settlement of the Bucket II Claims, there would be no plan of reorganization and that the “plan would not be feasible without this settlement.” 157 Mr. Sambrooks believes that the Plan strikes a fair balance among the interests of the various creditor groups and provides a valuable distribution to unsecured creditors in light of his understanding that the RBL Lenders have an adequate protection claim that absorbs the entire value of the Debtors’ unencumbered assets.
Lastly, Mr. Sambrooks gave testimony regarding strip pricing. He explained that the “strip price” for oil and natural gas reflects market forecasts for prices based on forward contracts and is not necessarily a predictor of oil and gas market prices going forward. 158 Upon questioning from counsel to the Committee, Mr. Sambrooks confirmed his understanding that commodity prices have increased in 2016; however, Mr. Sambrooks stated that such increases have not been material. Moreover, although changes in commodity prices are taken into consideration when deciding whether to modify the Company’s business plan, Mr. Sambrooks stated that commodity prices are merely one of several factors that are considered. 159 Mr. Sambrooks also testified to the unpredictability of commodity prices and stated that it is difficult to predict how long an increase in commodity prices is going to continue or be sustained. 160
Mr. Sambrooks’ testimony reflected broad knowledge of the exploration and production industry and a deep mastery of virtually every facet of the Debtors’ business, including the financial, strategic, and scientific aspects. It is also worth noting that Mr. Sambrooks pioneered horizontal drilling techniques, 161 a fact which underscores the credibility of his testimony about the quality and predictability of the Company’s Reserves.
2. Mr. David Cecil
Mr. Cecil is a Managing Director at Lazard Fréres & Co. LLC (“Lazard”). Over the past seventeen years, he has been involved in over 100 energy-related mergers and acquisitions, asset acquisitions and divestitures, financings, and other transactions, totaling over $25 billion in transaction value. Prior to testifying at the Confirmation Hearing, Mr. Cecil had never served as a testifying expert. The majority of Mr. Cecil’s experience relates to asset acquisitions and divestitures, in which he *223 has advised clients in connection with the purchase and sale of discrete oil and natural gas assets. Mr. Cecil’s testimony comprehensively covered Lazard’s calculation of the value of the Reserves as of the Petition Date and the Forecasted Effective Date, relying upon a NAV analysis as his principal methodology. Mr. Cecil also testified as to the total enterprise value of the Reorganized Debtors as of the Forecasted Effective Date, relying upon an NAV analysis as his principal methodology and a comparable company analysis as a secondary methodology. 162
In performing the valuations described below, Mr. Cecil relied on the information in the ARIES Database that was provided to Lazard by the Debtors. Mr. Cecil stated that upon receiving the ARIES Database, his team conducted due diligence to (i) analyze the reasonableness of various cost assumptions and (ii) evaluate the reasonableness of the Reserves data reflected in the ARIES Database. The ARIES Database was used to prepare (a) the Company’s April 2015 business plan, which serves as the basis for valuation of the Reserves as of the Petition Date, and (b) the Company’s January 2016 business plan, which serves as the basis for valuation of the Reserves as of the Forecasted Effective Date. 163 Mr. Cecil stated that he calculated the value of the Debtors’ assets based on a going-concern value, which is consistent with “the fair market value of the same assets in a non-duress sale between a willing buyer and a willing seller under [non-constrained] market conditions.” 164
In conducting his NAV analysis, Mr. Cecil first identified the projected cash flows of the Debtors’ reserves using the ARIES Database, which reflects cash flow projections on a well-by-well basis. According to Mr. Cecil, the ARIES Database applied strip pricing as of (i) July 15, 2015 to calculate cash flows as of the Petition Date and (ii) March 22, 2016 to calculate cash flows as of the Forecasted Effective Date. Mr. Cecil explained that once he identified the projected cash flows, he applied an industry-standard PV-10 in order to estimate the present value of the cash flows. Lastly, Mr. Cecil stated that he applied a customized RAF range in order to risk-adjust the cash flows for each reserve category. According to Mr. Cecil, RAFs, which are formulated by the SPEE, reflect a suggested range of risk adjustments. 165
Mr. Cecil applied the midpoint between the mid-RAFs and the high-RAFs to the Reserves because it is industry practice to apply a customized RAF range based on the particular assets that are being evaluated; moreover, the application of the mid-RAFs and high-RAFs is consistent with Mr. Cecil’s prior experience with the Haynesville and Cotton Valley plays. Mr. Cecil noted that SPEE does not require that all three RAF ranges be applied when performing an asset evaluation. Although Mr. Cecil stated that the RAF ranges are based on results from an annual SPEE survey, 166 he failed to clearly articulate how the results from the survey inform the risk adjustments that are applied in each RAF category.
Mr. Cecil gave a detailed explanation of how his NAV analysis took account of cer *224 tain costs and expenses included in the ARIES Database, such as the costs and expenses associated with preserving and maintaining the value of the Debtors’ oil and gas assets. Examples of such costs and expenses include (i) capital expenditures; 167 (ii) workover expenses; 168 (iii) lease operating expenses; 169 and (iv) COPAS Charges. 170 According to Mr. Cecil, however, certain other costs and expenses are not accounted for in the ARIES Database because they are “unrelated to the operation” and maintenance of the Debtors’ wells. 171 Such costs'and expenses are those Indirect Costs that the Debtors do not include in the ARIES Database as COPAS Charges, including the costs associated with (i) acquisition and divestitures; (ii) investor relations; (iii) public company reporting; and (iv) remaining overhead not allocated to the field levél. 172 Another category of expenses that is excluded from the ARIES Database is the capitalized general and administrative costs (“Capitalized G&A”), which represent pre-drilling costs for activities performed on a well before the well produces any cash flow. Mr. Cecil testified that it is not customary to account for those costs, like Capitalized G&A, that are not field-level expenses relating to maintaining the value of assets in an oil and gas asset valuation, citing an excerpt from an SPEE handbook which states that “costs projected in the economic evaluation [of oil and gas reserves] are generally field-level expenses and exclude general and administrative overhead costs.” 173 Moreover, Mr. Cecil pointed out that, unlike the Committee’s expert, Mr. Zelin, Mr. Cecil did not include Land Expense 174 costs in his NAV analysis. According to Mr. Cecil, Land Expense is not typically accounted for in the standard methodology for valuing oil and gas assets. Moreover, Mr. Cecil deemed it inappropriate to account for Land Expense based on the fact that the Debtors’ Land Expense projec *225 tions were merely “placeholders” in the Debtors’ budget. 175
Mr. Cecil explained that a significant difference exists between the Petition Date and Forecasted Effective Date NAV calculations due to the value of approximately 225 locations in the Haynesville play (the “Additional Haynesville Locations”) that was accounted for in the Forecasted Effective Date NAV analysis but excluded from the Petition Date NAV analysis. According to Mr. Cecil, the Additional Haynesville Locations were not reflected in the ARIES Database as of the Petition Date because (i) as of the Petition Date, the Debtors were in the process of determining the extent of their rights in the Additional Haynesville Locations and (ii) the Debtors did not include the Additional Haynesville Locations in the April 2015 business plan. The Additional Haynesville Locations were subsequently included in the January 2016 business plan. Nonetheless, Mr. Cecil conducted an illustrative valuation of the Additional Haynesville Locations and, after adjusting for risk, concluded that the value of the Additional Haynesville Locations fell within the range of $90 million to $155 million. Mr. Cecil stated that including the Additional Haynesville Locations in the Petition Date NAV analysis would have increased the value of the Reserves as of the Petition Date; therefore, omitting the value of the Additional Haynesville Locations from the Petition Date NAV analysis resulted in a “conservative” valuation. 176 The NAV analysis applied by Mr. Cecil to value the Debtors’ oil and gas assets resulted in midpoint values of (i) $1.13 billion as of the Petition Date; (ii) $670 million as of the Forecasted Effective Date based on a March 22, 2016 strip price; (iii) $745 million as of the Forecasted Effective Date based on a May 20, 2016 strip price; and (iv) $800 million as of the Forecasted Effective Date based on a June 10, 2016 strip price.
Mr. Cecil testified that, in conducting an enterprise valuation, he utilized an NAV analysis as his primary methodology and a comparable company analysis as a secondary methodology. Mr. Cecil explained that the NAV analysis for the Forecasted Effective Date enterprise valuation considered the same reserves, PV-10 discounted cash flow calculations, and risk adjustment factors as the NAV analysis for the Fore-casted Effective Date asset valuation. Unlike the NAV analysis for the Forecasted Effective Date asset valuation, however, the NAV analysis for purposes of determining enterprise value took into account all of the Indirect Costs over the life of the wells, including the portion not covered by the COPAS Charges which, according to Mr. Cecil’s estimate, totaled $154 million. The NAV analysis applied by Mr. Cecil indicated a value range of approximately $425 million to $600 million (with a midpoint of $515 million) as of the Forecasted Effective Date.
Given the lack of truly comparable companies, Mr. Cecil “deemed the comparable company analysis to be a less reliable value indicator for purposes of an enterprise valuation” and “relied upon the comparable company analysis as a secondary methodology” in forming his opinion about the total enterprise value of the Reorganized Debtors. 177 The comparable company analysis performed by Mr. Cecil indicated a value range of approximately $480 million to $1.1 billion (with a midpoint of $780 million). Based on his NAV analysis and the comparable company analysis, Mr. Cecil concluded that the total enterprise val *226 ue of the Reorganized Debtors is approximately $450 million to $650 million (with a midpoint of $550 million).
On cross-examination by counsel for the Committee, Mr. Cecil was asked about the apparent increase in COPAS Charges between the Petition Date and the Forecast-ed Effective Date reflected in his analyses despite the overall decrease in the Company’s total G&A costs during that same time period. Mr. Cecil explained that at the time the Company was preparing its April 2015 business plan, the Company was in the process of integrating the businesses of Legacy Forest and Legacy Sabine post-Combination and was reviewing the COPAS Charges that Legacy Forest had applied to the assets that it had owned prior to the Combination. After the Company finalized its April 2015 business plan, the Company realized that the COPAS Charges of Legacy Forest “were understated” and as a result, the Company corrected the issue “when they put together the January plan.” 178 In addition, when questioned about the inclusion of $154 million of Indirect Costs in his Forecasted Effective Date enterprise valuation that he did not include in his NAV assets valuation, Mr. Cecil explained that he arrived at this estimate using two methods. Under the PV-10 of G&A approach, Mr. Cecil used the Debtors’ G&A forecast through 2018 and essentially “took the present value using a ten percent discount rate.” 179 Under the capitalization of G&A approach, Mr. Cecil applied a 4x to 5x multiple using the Company’s 2016 G&A forecast, noting that this multiple range is a “typical G&A valuation range” based on “public research reports.” 180
Mr. Cecil’s significant experience performing valuations, especially valuations of oil and gas assets, lends considerable weight to his testimony and to the various methods he applied in this case. Although Mr. Cecil has admittedly limited experience performing valuations for the purpose of calculating an adequate protection claim, his extensive experience in the oil and gas industry is notable and his testimony will be afforded substantial weight by the Court.
3. Mr. James Seery
Mr. Seery is the President of River Birch Capital (“River Birch”), which is a long-short credit fund with offices in New York and London. River Birch currently holds approximately $60 million of debt under the Second Lien Credit Agreement. Mr. Seery’s testimony provided an overview of (i) the credit bid proposal submitted to the Company by the Second Lien Lenders shortly before the Petition Date and (ii) the settlement between the Debtors and the Second Lien Lenders that is incorporated in the Plan. 181
Mr. Seery testified that the Second Lien Lenders presented a credit bit proposal (“Second Lien Credit Bid Proposal”) to the Company shortly before the Petition Date in an effort to establish a framework for a pre-arranged plan of reorganization. Pursuant to the Second Lien Credit Bid Proposal, the Second Lien Lenders sought to (i) exchange the secured portion of their debt for equity in reorganized Sabine; (ii) contribute cash to pay down the RBL Lenders; and (iii) provide the Company with new capital in the range of $120 million to $300 million, depending on the form of the transaction. According to Mr. Seery, *227 the Second Lien Lenders sought to achieve these objectives through a chapter 11 plan of reorganization or through a section 363 sale. Mr. Seery stated that the Second Lien Credit Bid Proposal was premised on an estimated total asset value of approximately $1.3 billion; Mr. Seery believed that the Company’s assets were worth more than $1.3 billion. 182
Mr. Seery testified that River Birch performed its own analysis to value the Company’s oil and gas assets. In conducting his valuation analysis, Mr. Seery reviewed the Company’s reserve report and analyzed the Company’s G&A costs that were included within the report. Mr. Seery explained that based on his experience valuing oil and gas companies, his valuation included only G&A costs that were directly related to the Company’s wells. Although the Second Lien Lenders and the Company engaged in discussions following the Second Lien Credit Bid Prpposal, Mr. Seery stated that the Company did not respond with a counter-proposal of any kind.
Mr. Seery also provided an overview of the material terms of the Settlement between the Debtors and the Second Lien Lenders. In exchange for settlement of the adequate protection claim of the Second Lien Lenders (which Mr. Seery valued at $150 million to $200 million), Mr. Seery stated that the Second Lien Lenders will receive five percent of the equity of the Reorganized Debtors and the Tranche 1 Warrants. As a settlement of the Second Lien Lenders’ deficiency claim, Mr. Seery stated that the Second Lien Lenders will receive Tranche 2 Warrants and share in two percent of the equity of the Reorganized Debtors. Mr. Seery expressed his view that the Warrants “certainly have value” based on several factors. 183 First, Mr. Seery noted that the Warrants have enhanced value in part due to the minority protections that were negotiated between the Debtors and the Second Lien Lenders, which protections “weren’t given away freely.” 184 Mr. Seery described the most valuable protection the Warrants have as the “Black-Scholes cash out,” which, upon the occurrence of a “trigger event” (such as a change of control of the company), allows for an independent third party to value the Warrants using the Black-Scholes formula and requires that the Company cash out the warrant holders. 185 According to Mr. Seery, this type of minority protection, which he insisted on in the settlement negotiations, is not common because such protection can be “very valuable to the warrant holder versus the majority equity holder.” 186 Moreover,' Mr. Seery explained that the ten-year maturity of the Warrants provides value because “it gives [the holder of the Warrant] more opportunity for [the] option to come into the money.” 187 When questioned about the quantitative value of the Tranche 1 Warrants, he testified that, depending on the volatility percentage applied, the value of the. Tranche 1 Warrants “could range any *228 where from $15-$25 million,” 188 and that he believed a fifty percent volatility figure was fair. He also stated that he supports the Settlement and the Plan, opining that “it’s not an ideal outcome from our perspective,” but, in his view “this is a fair settlement.” 189
On cross-examination, Mr. Seery testified that at the time the Second Lien Credit Bid Proposal was delivered to the Company, he strongly disagreed with the Company’s view that it could avoid the liens that were previously granted to the Second Lien Lenders. According to Mr. Seery, the additional liens “were required to be given to [the. Second Lien Lenders] under the second lien credit agreement that had been in place since 2012.” 190 Although the Debtors expressed a view that they had a fraudulent conveyance claim against the Second Lien Lenders, Mr. Seery stated that the Debtors did not provide him with a view on the value of such claim. In describing the compromises that the Second Lien Lenders were making with respect to their adequate protection claim, Mr. Seery testified that “but for the settlement, [the Second Lien Lenders] would have a position in this case that [they] could try to enforce that claim.” 191 In other words, Mr. Seery stated that “it would be very difficult to confirm a plan without paying [the Second Lien Lenders] in full” and in the absence of a settlement, Mr. Seery believed the remaining options were either a foreclosure or a liquidation of the Company. 192
4. Mr. Michael Magilton
Mr. Magilton is the Senior Vice President and Chief Financial Officer of Sabine. His testimony principally outlined the process by which his land team performed an extensive encumbrance analysis of the Company’s wells and also described the Company’s treatment of COPAS Charges in the ARIES Database. 193 Like Mr. Sam-brooks, Mr. Magilton was in attendance for the duration of the Confirmation Hearing.
Mr. Magilton explained that the Company is required to pledge at least eighty percent of the value of its total proved reserves under its existing credit agreement with the RBL Lenders. 194 Mr. Ma-gilton stated that because the Company needed to understand the allocation of value between ¡its encumbered assets and unencumbered assets, his land team conducted a bottom-up review that involved reviewing the Company’s assets on a well-by-well basis rather than a lease-by-lease basis. Mr. Magilton provided a thorough description of the lien and mortgage review his land team conducted in order to determine which wells were encumbered (the “Encumbrance Review”). According to Mr. Magilton, the Company undertook the Encumbrance Review because (i) the *229 Company was in the midst of restructuring discussions that were developing quickly; and (ii) the Company was aware that the Independent Directors Committee would be reviewing potential causes of action relating to the Company’s liens and mortgages.
As Mr. Magilton and his land team reviewed the mortgages covering the Company’s oil and gas properties, the language of the granting clause contained in each mortgage informed the Encumbrance Review in two ways. First, Mr. Magilton stated that if a “unit” 195 was listed on an exhibit to a mortgage, Mr. Magilton’s team assumed that all leases in that particular unit were mortgaged. Second, if a lease was listed on an exhibit to a mortgage, Mr. Magilton’s team assumed that all leases of wells existing .within the unit relating to such lease were also mortgaged. 196
Mr. Magilton thoroughly explained the process by which his land team classified the Company’s wells as encumbered or unencumbered. He testified that the Company’s oil and gas properties in Louisiana, North Dakota, and Wyoming were designated as unencumbered because no mortgages on those properties were recorded. With respect to potentially encumbered properties, Mr. Magilton and his land team sorted such properties into three separate categories: (i) Legacy Sabine properties located in East Texas; (ii) Legacy Sabine properties located in North Texas and South Texas; and (iii) Legacy Forest properties.
Mr. Magilton explained that Legacy Sabine acquired a substantial number of its wells in- East Texas through acquisitions. Each acquisition contained a bill of sale, which was subsequently attached to . the mortgages of the RBL Lenders and filed with a county recorder’s office; each bill of sale contained a complete list of the leases, units, and wells that were acquired by Legacy Sabine pursuant to such acquisitions. Rather than assuming that the wells acquired by .the Company in East Texas were encumbered, Mr. Magilton and his land team performed a cross-check to confirm that the bill of sale exhibits were attached as exhibits to the mortgages.
Unlike the process for East Texas wells, the mortgage exhibits for wells located in North Texas and South Texas were created internally through the Company’s BOLO system, 197 which includes a list of all of the leases owned by the Company. The Company printed out the leases for the wells that Legacy Sabine owned in North-Texas and South Texas and provided these *230 leases to the RBL Lenders, who subsequently attached them to the mortgages as exhibits. In order to confirm that the North Texas and South Texas leases were listed on the mortgages, Mr. Magilton’s land team performed a cross-check of the information contained on the BOLO system against the mortgage exhibits filed in the North Texas and South Texas counties.
Mr. Magilton testified that the wells owned by Legacy Forest were mortgaged in the same way as the Company’s wells located in North Texas and South Texas. Using the Legacy Forest BOLO system, the land team at Legacy Forest had produced a list of the leases, units, and wells owned by Legacy Finest in each county in. which the RBL Lenders intended to file mortgages; the list was delivered to the RBL Lenders, who subsequently attached the list to the mortgages. Mr. Magilton’s land team performed a cross-check of the information listed in the mortgage exhibits against a comprehensive list of the Legacy Forest leases, wells, and units listed in the Company’s BOLO system. Mr. Magilton noted that at the time of the Combination, there were two categories of Legacy Forest properties that were not mortgaged: (i) certain leases that were associated with a purchase by Legacy Forest in late 2014; and • (ii) certain leases that the Company intended to sell shortly after the Combination.
Mr. Magilton’s thoughtful and methodical testimony readily supports a finding that the Encumbrance Review resulted in a comprehensive list of the Company’s encumbered and unencumbered wells on a well-by-well basis. Yet, according to Mr. Magilton, the Company performed further encumbrance analyses following the Encumbrance Review. In the fall of 2015, the Company received a list from the Committee regarding specific leases that it believed were unencumbered. The Company investigated such claims and, in many cases, provided the Committee with evidence that the leases in question were actually listed on mortgages. 198 The Company performed another analysis in connection with generating an encumbrance list for the Forecasted Effective Date; such analysis included updating the ARIES Database with changes that had occurred throughout the pendency of the Debtors’ chapter 11 cases (e.g., proved undeveloped (2P) wells that had become proved developed producing (IP) wells or the addition of new probable or possible locations as a result of continued engineering work). 199 Lastly, Mr. Magilton stated that the Company updated the encumbrance list in late March in connection with filing the Plan.
Mr. Magilton also gave extensive testimony regarding the Company’s G&A cost structure. He explained that the total G&A costs of the Company decreased between the Petition Date and the Forecasted Effective Date due to the effect of the Combination as well as due to challenging market conditions. The decrease in total G&A costs of the Company, however, does not necessarily mean that COPAS Charges will decrease over time because, as Mr. Magilton explained, COPAS Charges are a function of well count and the Company’s well count has maintained relatively static. Therefore, even though the Company’s January 2016 business plan does not reflect the operation of any rigs, Mr. Magil-ton stated that the Company continues to incur COPAS Charges for its approximately 1,600 producing wells.
*231 Mr. Magilton also described Lazard’s treatment of COPAS Charges in the ARIES Database for the purposes of its Petition Date and Forecasted Effective Date valuations. When the team at Lazard initially analyzed the ARIES Database as part of its due diligence process, they informed the Company that the treatment of COPAS Charges differed between the Petition Date reserve report and the Fore-casted Effective Date reserve report. In order to reflect accurately the treatment of COPAS Charges, Lazard ensured that each database reflected COPAS Charges for the economic life of the wells, which is approximately fifty years.
When questioned by counsel as to why COPAS Charges had increased from the Petition Date ($155 million) to the Forecasted Effective Date ($179 million) despite the overall decrease in the Company’s total G&A costs, Mr. Magil-ton explained that the discrepancy largely resulted from the integration process of Legacy Sabine and Legacy Forest. Following the completion of the April 2015 business plan, the Company discovered that Legacy Forest had not charged itself COPAS Charges for all of the wells that Legacy Forest operated. The Company subsequently adjusted the COPAS Charges for the Legacy Forest properties in its October 2015 business plan. Mr. Magilton also stated that the inputs in the ARIES Database are based on the Company’s intended treatment of the assets.
Lastly, when questioned by counsel as to whether the favorable market conditions prior to the Confirmation Hearing changed his view on the appropriateness of the January 2016 business plan, Mr. Magilton stated that such conditions did not change his view,- for two reasons. First, Mr. Magil-ton stated that “in the [exploration and production] industry you need to see sustained higher prices for a period of time.” 200 Therefore, although prices increased in the weeks preceding the Confirmation Hearing, Mr. Magilton stated that he needed “to see sustained prices” because thus far, he has “seen a lot of volatility.” 201 Second, Mr. Magilton explained that although “near term changes are important ... the curve going out multiple years is also very, very important” and he has not seen “a lot of change as you go out in time in 2018, T9, ’20 to the price curve.” 202 Because the Company is not “picking up a rig” until 2017, Mr. Magilton stated that the near term price increases will not change the Company’s business plan “from a new drilling perspective.” 203 Mr. Magilton’s testimony was remarkably detailed and thorough; as was the case, at the STN Hearing, his candor and credibility are noteworthy.
5. Mr. Jonathan (Joff) A. Mitchell
After serving as an advisor to the Company beginning in March 2015, Mr. Mitchell, a Senior Managing Director at Zolfo Cooper, became the Chief Restructuring Officer of the Debtors on the Petition Date. At the Confirmation Hearing, the Debtors offered Mr. Mitchell as an expert in restructuring and bankruptcy reorganization. Mr. Mitchell submitted three expert reports 204 — the first to provide opin *232 ions relating-to confirmation matters; the second to serve as a rebuttal to the rebuttal reports of Mr. Kearns and Mr. Zelin; and the third to update his opinions to reflect changes in strip pricing as of June 10, 2016. His testimony and expert reports covered four areas: (i) the Plan and the Settlement; (ii) the Adequate Protection Claims; (iii) calculations of the maximum and risk-adjusted value of each of the Bucket II Claims; and (iv) a liquidation analysis.
Mr. Mitchell’s testimony evidenced a detailed understanding of a number of critical subjects, including the Company’s operations and financial condition; the positions of the parties in the “acrimonious” and “tense” 205 "negotiations' leading to the Settlement; and the components of his analysis and estimation of the value of the claims and potential causes of action being settled by the Plan and Settlement.
Mr. Mitchell described the claims being settled, including the Adequate Protection Claims and the Bucket II Claims, and his involvement in negotiations and discussions with all creditor groups both prepetition and postpetition regarding potential settlemen

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Source: Frix Law Library, https://www.frixlaw.com/law-library/cases/8499700. Public record. Not legal advice.