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EX-32.1 - CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 OF EXEC - EXCO RESOURCES INCexhibit321peopfoq22018.htm
EX-31.2 - CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 OF PFO - EXCO RESOURCES INCexhibit312pfoq22018.htm
EX-31.1 - CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 OF PEO - EXCO RESOURCES INCexhibit311peoq22018.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________________
FORM 10-Q
______________________________
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2018
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to            
Commission File Number 001-32743
______________________________
EXCO RESOURCES, INC.
(Exact name of registrant as specified in its charter)
______________________________
Texas
(State of incorporation)
 
74-1492779
(I.R.S. Employer Identification No.)
 
 
 
12377 Merit Drive, Suite 1700, Dallas, Texas
(Address of principal executive offices)
 
75251
(Zip Code)
(214) 368-2084
(Registrant’s telephone number, including area code)
______________________________

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant is required to submit and post such files).    YES  þ    NO  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o
 
Accelerated filer o
Non-accelerated filer o
 
Smaller reporting company þ
Emerging growth company o
 
 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  o    NO  þ

The number of shares of common stock, par value $0.001 per share, outstanding as of August 9, 2018 was 21,595,457.



EXCO RESOURCES, INC.
TABLE OF CONTENTS
 
 
 
 
 
 
 
 
 
 
 



PART I—FINANCIAL INFORMATION

Item 1.
Financial Statements

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
 
June 30, 2018
 
December 31, 2017
 
 
(Unaudited)
 
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
54,995

 
$
39,597

Restricted cash
 
10,984

 
15,271

Accounts receivable, net:
 
 
 
 
Oil and natural gas
 
80,901

 
55,692

Joint interest
 
24,221

 
30,570

Other
 
1,919

 
1,976

Derivative financial instruments - commodity derivatives
 

 
1,150

Other current assets
 
24,455

 
23,574

Total current assets
 
197,475

 
167,830

Equity investments
 
4,736

 
14,181

Oil and natural gas properties (full cost accounting method):
 
 
 
 
Unproved oil and natural gas properties and development costs not being amortized
 
149,249

 
118,652

Proved developed and undeveloped oil and natural gas properties
 
3,281,104

 
3,107,566

Accumulated depletion
 
(2,791,918
)
 
(2,752,311
)
Oil and natural gas properties, net
 
638,435

 
473,907

Other property and equipment, net and other non-current assets
 
38,933

 
21,274

Goodwill
 
163,155

 
163,155

Total assets
 
$
1,042,734

 
$
840,347

Liabilities and shareholders’ equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable and accrued liabilities
 
$
49,988

 
$
68,277

Revenues and royalties payable
 
42,808

 
207,956

Accrued interest payable
 
7,203

 
27,637

Current portion of asset retirement obligations
 
600

 
600

Current maturities of long-term debt
 
473,364

 
1,362,500

Total current liabilities
 
573,963

 
1,666,970

Deferred income taxes
 

 
4,518

Derivative financial instruments - common share warrants
 

 
1,950

Asset retirement obligations and other long-term liabilities
 
26,127

 
13,108

Liabilities subject to compromise
 
1,490,943

 

Commitments and contingencies
 

 

Shareholders’ equity:
 
 
 
 
Common shares, par value $0.001, 260,000,000 shares authorized; 21,635,102 shares issued and 21,595,457 shares outstanding at June 30, 2018; 21,670,186 shares issued and 21,630,541 shares outstanding at December 31, 2017
 
22

 
22

Additional paid-in capital
 
3,540,627

 
3,539,422

Accumulated deficit
 
(4,581,316
)
 
(4,378,011
)
Treasury shares, at cost; 39,645 shares at June 30, 2018 and December 31, 2017
 
(7,632
)
 
(7,632
)
Total shareholders’ equity
 
(1,048,299
)
 
(846,199
)
Total liabilities and shareholders’ equity
 
$
1,042,734

 
$
840,347



See accompanying notes.

1


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in thousands, except per share data)
 
2018
 
2017
 
2018
 
2017
Revenues:
 
 
 
 
 
 
 
 
Oil
 
$
24,314

 
$
14,305

 
$
40,611

 
$
30,497

Natural gas
 
68,462

 
50,182

 
137,311

 
103,346

Purchased natural gas and marketing
 
5,354

 
6,528

 
10,672

 
13,701

Total revenues
 
98,130

 
71,015

 
188,594

 
147,544

Costs and expenses:
 
 
 
 
 
 
 
 
Oil and natural gas operating costs
 
10,874

 
8,215

 
18,782

 
16,713

Production and ad valorem taxes
 
4,081

 
3,415

 
8,077

 
6,850

Gathering and transportation
 
21,310

 
27,087

 
41,286

 
54,440

Purchased natural gas
 
3,743

 
6,353

 
7,858

 
12,805

Depletion, depreciation and amortization
 
22,000

 
11,622

 
40,206

 
23,130

Accretion of liabilities
 
561

 
215

 
903

 
427

General and administrative
 
6,303

 
(1,394
)
 
14,830

 
3,021

Gain on Appalachia JV Settlement
 

 

 
(119,477
)
 

Other operating items
 
(1,141
)
 
286

 
(1,007
)
 
1,355

Total costs and expenses
 
67,731

 
55,799

 
11,458

 
118,741

Operating income
 
30,399

 
15,216

 
177,136

 
28,803

Other income (expense):
 
 
 
 
 
 
 
 
Interest expense, net
 
(7,815
)
 
(22,480
)
 
(16,988
)
 
(42,432
)
Gain (loss) on derivative financial instruments - commodity derivatives
 

 
6,541

 
(615
)
 
22,074

Gain on derivative financial instruments - common share warrants
 
1,532

 
122,295

 
1,715

 
128,299

Loss on restructuring and extinguishment of debt
 

 
(108
)
 

 
(6,380
)
Other income (loss)
 
16

 
(25
)
 
38

 
(21
)
Equity income
 

 
338

 
179

 
655

Reorganization items, net
 
(16,388
)
 

 
(369,288
)
 

Total other income (expense)
 
(22,655
)
 
106,561

 
(384,959
)
 
102,195

Income (loss) before income taxes
 
7,744

 
121,777

 
(207,823
)
 
130,998

Income tax expense (benefit)
 

 
1,027

 
(4,518
)
 
2,055

Net income (loss)
 
$
7,744

 
$
120,750

 
$
(203,305
)
 
$
128,943

Earnings (loss) per common share:
 
 
 
 
 
 
 
 
Basic:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
0.36

 
$
6.13

 
$
(9.34
)
 
$
6.71

Weighted average common shares outstanding
 
21,615

 
19,702

 
21,758

 
19,217

Diluted:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
0.36

 
$
6.07

 
$
(9.34
)
 
$
6.65

Weighted average common shares and common share equivalents outstanding
 
21,615

 
19,886

 
21,758

 
19,393








See accompanying notes.

2


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
 
Six Months Ended June 30,
(in thousands)
 
2018
 
2017
Operating Activities:
 
 
 
 
Net income (loss)
 
$
(203,305
)
 
$
128,943

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
Deferred income tax expense (benefit)
 
(4,518
)
 
2,055

Depletion, depreciation and amortization
 
40,206

 
23,130

Equity-based compensation
 
921

 
(10,341
)
Accretion of liabilities
 
903

 
427

Income from equity investments
 
(179
)
 
(655
)
(Gain) loss on derivative financial instruments - commodity derivatives
 
615

 
(22,074
)
Cash receipts (payments) of commodity derivative financial instruments
 
535

 
(5,558
)
Gain on derivative financial instruments - common share warrants
 
(1,715
)
 
(128,299
)
Amortization of deferred financing costs and discount on debt issuance
 
4,166

 
11,437

Gain on Appalachia JV Settlement
 
(119,477
)
 

Non-cash and non-operating reorganization items, net
 
339,706

 

Loss on restructuring and extinguishment of debt
 

 
6,380

Paid in-kind interest expense
 
(21,078
)
 
15,914

Other non-operating items
 

 
261

Effect of changes in:
 
 
 
 
Accounts receivable
 
(12,148
)
 
17,778

Other current assets
 
1,946

 
(1,877
)
Accounts payable and other liabilities
 
42,918

 
(3,920
)
Net cash provided by operating activities
 
69,496

 
33,601

Investing Activities:
 
 
 
 
Additions to oil and natural gas properties, gathering assets and equipment
 
(98,110
)
 
(44,484
)
Property acquisitions
 
14,832

 
(4,457
)
Proceeds from disposition of property and equipment
 

 
25

Net changes in amounts due to joint ventures
 

 
(7,553
)
Other
 
950

 

Net cash used in investing activities
 
(82,328
)
 
(56,469
)
Financing Activities:
 
 
 
 
Borrowings under DIP Credit Agreement
 
156,406

 

Borrowings under EXCO Resources Credit Agreement
 

 
25,000

Repayments under EXCO Resources Credit Agreement
 
(126,401
)
 
(253,592
)
Proceeds received from issuance of 1.5 Lien Notes, net
 

 
295,530

Payments on Second Lien Term Loans
 

 
(11,057
)
Debt financing costs and other
 
(6,062
)
 
(21,976
)
Net cash provided by financing activities
 
23,943

 
33,905

Net increase in cash, cash equivalents and restricted cash
 
11,111

 
11,037

Cash, cash equivalents and restricted cash at beginning of period
 
54,868

 
20,218

Cash, cash equivalents and restricted cash at end of period
 
$
65,979

 
$
31,255

 
 
 
 
 
Supplemental Cash Flow Information:
 
 
 
 
Cash interest payments
 
$
17,240

 
$
17,884

Income tax payments
 

 

Supplemental non-cash investing and financing activities:
 
 
 
 
Capitalized equity-based compensation
 
$
284

 
$
693

Capitalized interest
 
2,158

 
2,898

Net assets acquired on Appalachia JV Settlement, excluding cash and cash equivalents
 
114,268

 




See accompanying notes.

3


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
 
 
Common shares
 
Treasury shares
 
Additional paid-in capital
 
Accumulated deficit
 
Total shareholders’ equity
(in thousands)
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
Balance at December 31, 2016
 
18,916

 
$
19

 
(40
)
 
$
(7,632
)
 
$
3,538,080

 
$
(4,402,373
)
 
$
(871,906
)
Issuance of common shares
 
2,746

 
3

 

 

 
11,395

 

 
11,398

Equity-based compensation
 

 

 

 

 
(9,561
)
 

 
(9,561
)
Restricted shares issued, net of cancellations
 
28

 

 

 

 

 

 

Net income
 

 

 

 

 

 
128,943

 
128,943

Balance at June 30, 2017
 
21,690

 
$
22

 
(40
)
 
$
(7,632
)
 
$
3,539,914

 
$
(4,273,430
)
 
$
(741,126
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2017
 
21,670

 
$
22

 
(40
)
 
$
(7,632
)
 
$
3,539,422

 
$
(4,378,011
)
 
$
(846,199
)
Equity-based compensation
 

 

 

 

 
1,205

 

 
1,205

Restricted shares issued, net of cancellations
 
(35
)
 

 

 

 

 

 

Net loss
 

 

 

 

 

 
(203,305
)
 
(203,305
)
Balance at June 30, 2018
 
21,635

 
$
22

 
(40
)
 
$
(7,632
)
 
$
3,540,627

 
$
(4,581,316
)
 
$
(1,048,299
)
 





































See accompanying notes.

4


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.Organization and basis of presentation

Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “EXCO,” “EXCO Resources,” the “Company,” “we,” “our,” and “us” are to EXCO Resources, Inc. and its consolidated subsidiaries.

We are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of onshore U.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areas including Texas, Louisiana and the Appalachia region. The following is a brief discussion of our producing regions:

East Texas and North Louisiana
The East Texas and North Louisiana regions are primarily comprised of our Haynesville and Bossier shale assets. We have a joint venture with a wholly owned subsidiary of Royal Dutch Shell, plc (“Shell”), covering an undivided 50% interest in the majority of our Haynesville and Bossier shale assets in East Texas and North Louisiana. The East Texas and North Louisiana regions also include certain assets outside of the joint venture in the Haynesville and Bossier shales. We serve as the operator for most of our properties in the East Texas and North Louisiana regions.

South Texas
The South Texas region is primarily comprised of our Eagle Ford shale assets. We serve as the operator for most of our properties in the South Texas region.

Appalachia
The Appalachia region is primarily comprised of our Marcellus shale assets. We had a joint venture with Shell covering our Marcellus shale and other assets in the Appalachian region (“Appalachia JV”). EXCO and Shell each owned an undivided 50% interest in the Appalachia JV and a 49.75% working interest in the Appalachia JV’s properties. The remaining 0.5% working interest is held by an entity that operates the Appalachia JV’s properties (“OPCO”), which was previously jointly owned by EXCO and Shell. On February 27, 2018, we closed a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region (“Appalachia JV Settlement”). As a result of the Appalachia JV Settlement, we acquired Shell’s interests in the Appalachia JV and OPCO. See further discussion of this transaction in “Note 3. Acquisitions, divestitures and other significant events”.

The accompanying Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017, Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the three and six months ended June 30, 2018 and 2017 are for EXCO and its subsidiaries. The unaudited Condensed Consolidated Financial Statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States (“GAAP”). Certain reclassifications have been made to prior period information to conform to current period presentation.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial statements and in the opinion of management, such financial statements reflect all adjustments necessary to fairly present the consolidated financial position of EXCO as of June 30, 2018 and its results of operations and cash flows for the periods presented. These unaudited interim financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes included in EXCO’s Annual Report on Form 10-K for the year ended December 31, 2017, filed with the SEC on March 15, 2018 (“2017 Form 10-K”).

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.

5


Chapter 11 Cases and Going Concern Assessment

On January 15, 2018 (“Petition Date”), the Company and certain of its subsidiaries, including EXCO Services, Inc., EXCO Partners GP, LLC, EXCO GP Partners OLP, LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, EXCO Midcontinent MLP, LLC, EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC, EXCO Resources (XA), LLC, EXCO Production Company (WV), LLC, EXCO Land Company, LLC, EXCO Holding MLP, Inc., Raider Marketing, LP and Raider Marketing GP, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Court”). The Chapter 11 Cases are being jointly administered under the caption In Re EXCO Resources, Inc., Case No. 18-30155 (MI) (“Chapter 11 Cases”). The Court granted all of the first day motions filed by the Debtors that were designed primarily to minimize the impact of the Chapter 11 proceedings on their operations, customers and employees. The Debtors continue to operate their businesses as “debtors in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Court. The Debtors expect to continue operations without interruption during the pendency of the Chapter 11 proceedings.

For the duration of the Chapter 11 proceedings, our operations and ability to develop and execute our business plan are subject to risks and uncertainties associated with Chapter 11 proceedings. As a result of these risks and uncertainties, our assets, liabilities, shareholders’ equity, officers and/or directors could be significantly different following the conclusion of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this quarterly report on Form 10-Q may not accurately reflect our operations, properties and capital plans following the conclusion of the Chapter 11 Cases. 

The Debtors have not reached an agreement with their creditors for a plan of reorganization and continue to engage in discussions regarding the terms of a financial restructuring plan. In conjunction with this process, we will explore potential strategic alternatives to maximize value for the benefit of our stakeholders, which may include a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certain indebtedness as an alternative to the sale process, or a combination thereof.

Therefore, the outcome of the Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of the Court and creditors. The significant risks and uncertainties related to our liquidity and the Chapter 11 proceedings raise substantial doubt about our ability to continue as a going concern. We define liquidity as cash and restricted cash plus the unused borrowing base under the debtor-in-possession credit agreement (“Liquidity”). These Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. The accompanying Condensed Consolidated Financial Statements do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classification of liabilities.
Chapter 11 filing impact on creditors and shareholders

We have filed schedules and statements with the Court setting forth, among other things, the assets and liabilities of each of the Debtors, subject to the assumptions filed in connection therewith. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the deadline for general claims, which was set by the Court as April 15, 2018 (“Bar Date”). The deadline for governmental units to file proofs of claim was set by the Court as September 4, 2018. Differences between amounts scheduled by the Debtors and claims by creditors are being investigated and will be reconciled and resolved to within an immaterial amount in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and likely will continue after the Debtors emerge from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently asserted.

Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities to creditors and post-petition liabilities must be satisfied in full before the holders of our existing common shares are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery for creditors, if any, will not be determined until confirmation and implementation of a plan of reorganization. The outcome of the Chapter 11 Cases remains uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors may receive. We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 Cases and the holders of our existing common shares will be entitled to a nominal recovery, if any.


6


Automatic stay     

Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial and administrative actions against the Debtors as well as efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors’ property, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are stayed.
Impact on indebtedness

As of the Petition Date, we had approximately $1.4 billion in principal amount of indebtedness, including approximately: (i) $126.4 million outstanding under our previous revolving credit agreement (“EXCO Resources Credit Agreement”), (ii) $317.0 million outstanding under our senior secured 1.5 lien notes due March 20, 2022 (“1.5 Lien Notes”), (iii) $708.9 million outstanding under our senior secured 1.75 lien term loans due October 26, 2020 (“1.75 Lien Term Loans”), (iv) $17.2 million outstanding under our senior secured second lien term loans due October 26, 2020 (“Second Lien Term Loans”), (v) $131.6 million outstanding under our senior unsecured notes due September 15, 2018 (“2018 Notes”), and (vi) $70.2 million outstanding under our senior unsecured notes due April 15, 2022 (“2022 Notes”). The commencement of the Chapter 11 Cases described above constituted an event of default that accelerated our obligations under the following debt instruments:

EXCO Resources Credit Agreement;
1.5 Lien Notes;
1.75 Lien Term Loans;
2018 Notes; and
2022 Notes.

These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions of the Bankruptcy Code. As a result of the Chapter 11 proceedings, the Court may limit post-petition interest on debt that may be under-secured or unsecured.

On January 22, 2018, we closed a debtor-in-possession credit agreement (“DIP Credit Agreement”) with lenders including affiliates of Fairfax Financial Holdings Limited (“Fairfax”), Bluescape Resources Company LLC (“Bluescape”) and JPMorgan Chase Bank, N.A. (collectively the “DIP Lenders”). The DIP Credit Agreement includes a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of $125.0 million (“Revolver A Facility”) and a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of $125.0 million (“Revolver B Facility”, and together with the Revolver A Facility, the “DIP Facilities”). Proceeds from the DIP Facilities were used to repay all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 process. As of June 30, 2018, we had $156.4 million in outstanding indebtedness and $81.6 million of available borrowing capacity under the DIP Facilities. See further discussion of the DIP Credit Agreement in “Note 8. Debt”. On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes.

Restrictions on trading of our equity securities to protect our use of net operating losses    

The Court has entered a final order pursuant to Sections 362(a)(3) and 541 of the Bankruptcy Code enabling the Company and the Filing Subsidiaries to avoid limitations on the use of our income tax net operating loss carryforwards (“NOLs”) and certain other tax attributes by imposing certain notice procedures and transfer restrictions on the trading of our equity securities. In general, the order applies to any person that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.5% of our outstanding common shares (“Substantial Shareholder”), and requires that each Substantial Shareholder file with the Court and serve us with notice of such status. Under the order, prior to any proposed acquisition or disposition of equity securities that would result in an increase or decrease in the amount of our equity securities owned by a Substantial Shareholder, or that would result in a person or entity becoming a Substantial Shareholder, such person or entity is required to file with the Court and notify us of such acquisition or disposition. We have the right to seek an injunction from the Court to prevent certain acquisitions or sales of our common shares if the acquisition or sale would pose a material risk of adversely affecting our ability to utilize such tax attributes.


7


Executory contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a breach as of the Petition Date of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a general unsecured claim against the Debtors for damages caused by such rejection. The assumption of an executory contract or unexpired lease generally requires the Debtors to cure existing monetary or other defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Any description of the treatment of an executory contract or unexpired lease with the Company or any of the Filing Subsidiaries, including any description of the obligations under any such executory contract or unexpired lease, is qualified by and subject to any rights they have with respect to executory contracts and unexpired leases under the Bankruptcy Code.

During March 2018, the Court approved the rejection of the following executory contracts:

Firm transportation agreements with Acadian Gas Pipeline System (“Acadian”), which required us to transport 325,000 Mmbtu per day on the Acadian Gas Pipeline System or pay reservation charges through October, 31, 2025;
Natural gas sales agreements with Enterprise Products Operating LLC (“Enterprise”), which required us to sell 75,000 Mmbtu per day of natural gas to Enterprise or incur certain costs through October 31, 2025;
Firm transportation agreements with Regency Intrastate Gas Systems LLC (“Regency”), which required us to either transport 237,500 Mmbtu per day of natural gas or pay reservation charges through January 31, 2020;
Marketing agreement with a subsidiary of Chesapeake Energy Corporation (“Chesapeake”), which required us to allow Chesapeake to purchase natural gas from certain wells in North Louisiana through 2021; and
Natural gas sales agreements with Shell, which required us to sell 100,000 Mmbtu per day of natural gas to Shell or incur certain costs through November 30, 2020.

On March 1, 2018, the Debtors filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure Midstream Energy, LLC and TGG Pipeline, Ltd. (collectively, “Azure”) through November 30, 2018.  The motion was abated on May, 8, 2018 and on May 16, 2018, EXCO Operating Company, LP and Raider Marketing, LP commenced an adversary proceeding under Adv. Proc. No. 18-03096.  The Debtors initiated this adversary proceeding against Azure to establish that the minimum volume commitment agreement is severable from the base gathering agreement between the parties.  The Debtors and the contract counterparties each filed various dispositive motions that were heard by the Court on August 9, 2018. The Court is anticipated to issue a ruling during the third quarter of 2018.
Accounting during bankruptcy

We have applied Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), in the preparation of these Condensed Consolidated Financial Statements. For periods subsequent to the Chapter 11 filings, ASC 852 requires the financial statements to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred during the bankruptcy proceedings, including losses related to executory contracts that have been approved for rejection by the Court, and adjustments to the carrying value of certain indebtedness are recorded as “Reorganization items, net” on the Condensed Consolidated Statement of Operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the Condensed Consolidated Balance Sheet as of June 30, 2018 as “Liabilities subject to compromise.”

Liabilities subject to compromise

The accompanying Condensed Consolidated Balance Sheet as of June 30, 2018 includes amounts classified as liabilities subject to compromise, which represent liabilities that are anticipated to be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 proceedings, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.

Liabilities subject to compromise include amounts related to the rejection of various executory contracts. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts or unexpired

8


leases are rejected. Conversely, to the extent that executory contracts or unexpired leases are not rejected and are instead assumed, liabilities associated therewith would constitute post-petition liabilities which will be satisfied in full under a plan of reorganization. The nature of certain potential claims arising under the Debtors’ executory contracts and unexpired leases has not been determined at this time, and therefore, such claims are not reasonably estimable at this time and may be material.

The following table summarizes the components of liabilities subject to compromise included on the Condensed Consolidated Balance Sheet as of June 30, 2018:

(in thousands)
 
June 30, 2018
Current maturities of long-term debt
 
$
927,917

Accrued interest payable
 
34,281

Accounts payable, accrued expenses and other liabilities
 
112,794

Liabilities related to rejected executory contracts
 
415,951

Liabilities subject to compromise
 
$
1,490,943


As of June 30, 2018, the principal and accrued interest associated with the DIP Credit Agreement and 1.5 Lien Notes were not classified as liabilities subject to compromise as a result of the adequate protection approved by the Court and our current estimates of the recoverability of claims related to these instruments.

Reorganization items, net

We have incurred significant expenses associated with the Chapter 11 process, primarily (i) the acceleration of deferred financing costs, debt discounts and deferred reductions in carrying value associated with debt instruments previously accounted for as a troubled debt restructuring pursuant to ASC 470-60, Troubled Debt Restructuring by Debtors, (ii) adjustments for estimated allowable claims related to executory contracts approved for rejection by the Court, and (iii) legal and professional fees incurred subsequent to the Petition Date related to the restructuring process. These costs, which are being expensed as incurred, significantly impact our results of operations. The following table summarizes the components included in “Reorganization items, net” in our Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2018:

(in thousands)
 
Three Months Ended June 30, 2018
 
Six Months Ended June 30, 2018
Legal and professional fees
 
$
16,355

 
$
29,582

Deferred financing costs, debt discounts and deferred reductions in carrying value
 
33

 
30,509

Rejection of executory contracts
 

 
309,197

Reorganization items, net
 
$
16,388

 
$
369,288


Interest expense

We have discontinued recording interest on debt instruments classified as liabilities subject to compromise as of the Petition Date. The contractual interest on liabilities subject to compromise not reflected in the Condensed Consolidated Statement of Operations was approximately $48.8 million, representing interest expense from the Petition Date through June 30, 2018. The cash interest rate of 12.5% was utilized in the determination of contractual interest expense that would have been incurred under the 1.75 Lien Term Loans for the period subsequent to the Petition Date.


9


2.Significant accounting policies

We consider significant accounting policies to be those related to our estimates of proved reserves, oil and natural gas properties, derivatives, business combinations, equity-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes. The policies include significant estimates made by management using information available at the time the estimates were made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our 2017 Form 10-K. In addition, see further discussion of our application of ASC 852 as a result of the Chapter 11 Cases in “Note 1. Organization and basis of presentation”.
Recent accounting pronouncements

In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) (“ASU 2016-02”). The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance leases. Operating leases will result in straight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases). Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted. ASU 2016-02 must be adopted using a modified retrospective transition, and provides for certain practical expedients. These transactions will require application of the new guidance at the beginning of the earliest comparative period presented. In January 2018, the FASB issued further guidance on the new lease standard in ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 provides a practical expedient to exclude existing or expired land easements from the evaluation of leases under ASU 2016-02 if the easements were not previously accounted for as leases under the current guidance. We are currently assessing the potential impact of ASU 2016-02 and related clarifying updates and expect they will have an impact on our consolidated financial condition and results of operations upon adoption. We are currently unable to quantify the impact the standard will have on our consolidated financial condition and results of operations.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) (“ASU 2016-18”). The amendments in this update require that a statement of cash flows explain the change during the period in total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for annual and interim periods beginning after December 15, 2017 and early adoption is permitted. We adopted ASU 2016-18 in the first quarter of 2018 utilizing retrospective application. The adoption resulted in an increase in reported investing cash flows of $10.7 million for the six months ended June 30, 2017 with a corresponding adjustment to the reported end of period cash balances.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. Under ASU 2017-01, an entity must first determine whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar assets. If this threshold is met, the set is not a business. If this threshold is not met, the entity then evaluates whether the set meets the requirement that a business includes, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs. ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. We adopted ASU 2017-01 in the first quarter of 2018 and will apply the guidance of ASU 2017-01 prospectively to future asset acquisitions, including the acquisitions as part of the Appalachia JV Settlement during the first quarter of 2018.

In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), Derivatives and Hedging (Topic 815): I. Accounting for Certain Financial Instruments with Down Round Features, II. Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception (“ASU 2017-11”). ASU 2017-11 revises the guidance for instruments with down round features in Subtopic 815-40, Derivatives and Hedging - Contracts in Entity’s Own Equity, which is considered in determining whether an equity-linked financial instrument qualifies

10


for a scope exception from derivative accounting. An entity is still required to determine whether instruments would be classified in equity under the guidance in Subtopic 815-40 in determining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified as liabilities. Our 2017 Warrants (as defined in “Note 7. Derivative financial instruments”) are required to be classified as liabilities under the current guidance due to their down round features. The amendments in Part I are required to be applied retrospectively to outstanding financial instruments with down round features. ASU 2017-11 is effective for annual and interim periods beginning after December 15, 2018, and early adoption is permitted, including adoption in an interim period. We are currently assessing the impact of ASU 2017-11; however, we believe that it could have an impact on our consolidated financial condition and results of operations if we determine the 2017 Warrants qualify for equity classification. However, we believe it is highly likely that our existing common shares as well as the 2017 Warrants will be canceled at the conclusion of our Chapter 11 Cases.

In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 (“ASU 2018-05”). The amendments in this update add various SEC paragraphs pursuant to the issuance of SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”). SAB 118 directs taxpayers to consider the implications of the Tax Cuts and Jobs Act (“Tax Act”) as provisional when it does not have the necessary information available, prepared, or analyzed in reasonable detail to complete its accounting for the change in the tax law. SAB 118 provides a one-year measurement period from a registrant’s reporting period that includes the Tax Act’s enactment date to allow the registrant sufficient time to obtain, prepare and analyze information to complete the required accounting under ASC 740. As described in the 2017 Form 10-K, we reflected the impact of the changes in rates on our deferred tax assets and liabilities at December 31, 2017, as we are required to reflect the change in the period in which the law is enacted. We are still analyzing certain aspects of the Tax Act, which could potentially affect the measurement of our income tax balances and future income tax expense or benefit. The ultimate impact of the Tax Act may differ from the estimates provided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of the Tax Act.

In June 2018, the FASB issued ASU No. 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The amendments in this update expand the scope of Topic 718 to include share-based payment transactions for acquiring goods or services from nonemployees. An entity should apply the requirements of Topic 718 to nonemployee awards except in certain circumstances. ASU 2018-07 clarifies that Topic 718 applies to all share-based payment transactions in which a grantor acquires goods or services to be consumed in a grantor’s operations unless the transaction effectively provides financing to the grantor or are awarded under a contract accounted for under Topic 606 (as defined below). ASU 2018-07 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2018. The amendments require that adjustments required upon application of the update be made through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. We have historically awarded share-based compensation to nonemployees; however, we do not currently have any outstanding share-based awards to nonemployees. Therefore, we do not believe the adoption of ASU 2018-07 will have an impact on our consolidated financial condition and results of operations unless share-based payments are issued to nonemployees in the future.

In July 2018, the FASB issued ASU No. 2018-09, Codification Improvements (“ASU 2018-09”). The amendments in this update include changes to clarify and make other incremental improvements to GAAP under the FASB’s perpetual project to address suggestions from stakeholders. The amendments in this update affect a wide variety of topics and apply to all reporting entities within the scope of the affected accounting guidance. The transition and effective date guidance is based on the facts and circumstances of each amendment. A number of the amendments do not require transition guidance and are effective as of the issuance of the update while many of the updates that have transition guidance are effective for annual periods beginning after December 15, 2018. For amendments relating to issued but not effective guidance, the effective date of these amendments follows that of the originally issued update. We are currently assessing the potential impact of the many amendments within ASU 2018-09 and are currently unable to quantify the impact, if any, the standard will have on our consolidated financial condition and results of operations.

Revenue from Contracts with Customers (Topic 606)

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). The FASB and the International Accounting Standards Board jointly issued this comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under GAAP. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The FASB issued additional ASUs that primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectability, presentation of sales taxes and other similar taxes collected from

11


customers, and non-cash consideration. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017 and permits the use of either the retrospective or cumulative effect transition method.

We adopted ASU 2014-09 and related updates in the first quarter of 2018 based on the modified retrospective method of adoption. The adoption of this standard did not have an impact on our consolidated financial condition and results of operations. We have implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the disclosures required under the new standard.

Overview of marketing arrangements

We produce oil and natural gas. We do not refine or process the oil or natural gas we produce. We sell the majority of the oil we produce under contracts using market sensitive pricing. The majority of our oil contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each area. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.

We sell the majority of our natural gas under individually negotiated gas purchase contracts using market sensitive pricing. Our sales contracts vary in length from spot market sales of a single day to term agreements that may extend for a month or more. Our natural gas customers primarily include natural gas marketing companies. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily, reflecting changing market conditions.

Revenue recognition under ASC 606

We use the sales method of accounting for oil and natural gas revenues. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes primarily on company-measured volume readings. We then adjust our oil and natural gas sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. Historically, these differences have been immaterial. Natural gas imbalances at June 30, 2018 and December 31, 2017 were not significant.

We generally sell oil and natural gas under two types of agreements that are common in our industry. Both types of agreements include transportation charges. We evaluate whether we are the principal or the agent in each transaction. The first type of agreement is a net-back arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation costs incurred by the purchaser. The purchaser takes custody, title and risk of loss of the oil or natural gas at the wellhead. In this case, we record revenue when the control transfers to the purchaser at the wellhead based on the price received, net of the transportation costs.

Under the second type of agreement, we sell oil or natural gas at a specific delivery point, pay transportation to a third-party and receive proceeds from the purchaser with no transportation deduction. The purchaser takes custody, title, and risk of loss of the oil or natural gas at the specific delivery point. In this case, we are deemed to be the principal and the ultimate third-party purchaser is deemed to be the customer. We recognize revenue when control transfers to the purchaser at the specific delivery point based on the price received from the purchaser. The costs that we incur to transport the oil or natural gas are recorded as gathering and transportation expenses. As such, our computed realized prices include revenues that are recognized under two separate bases.

Raider Marketing, LP (“Raider”) is a wholly owned subsidiary focused on the marketing of oil and natural gas. Raider purchases and resells natural gas from third-party producers, as well as oil and natural gas from operated wells in Texas and Louisiana, and charges a fee for marketing services to certain working interest owners in the related wells. Raider takes custody, title and risk of loss from the third-party producer upon the purchase of natural gas, then sells the natural gas to a separate third-party purchaser further downstream. The price paid for the purchase of natural gas from the third-party producer is not dependent on the price received from the ultimate purchaser. We are deemed to be the principal in these transactions. As such, third party purchases and sales are reported on a gross basis as “Purchased natural gas” expenses and “Purchased natural gas and marketing” revenues, respectively. The marketing fee charged by Raider to certain working interest owners in our operated wells is reported as “Purchased natural gas and marketing” revenues.


12


Transaction price allocated to remaining performance obligations

Our sales are short-term in nature with a contract term of one year or less. We have utilized the practical expedient in ASC 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Contract balances

Under our oil and natural gas sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our oil and natural gas sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil and natural gas sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three and six months ended June 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

3.Acquisitions, divestitures and other significant events

Appalachia JV Settlement

On January 26, 2018, we filed a motion in the Court to authorize the entry into a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region. The final order related to this settlement was approved on February 22, 2018 and we closed the settlement agreement on February 27, 2018. Under the terms of the Appalachia JV Settlement:
Shell transferred its interests to EXCO in each of BG Production Company (PA), LLC, BG Production Company (WV), LLC, OPCO, and Appalachia Midstream, LLC (“Appalachia Midstream”). On April 20, 2018, BG Production Company (PA), LLC legally changed its name to EXCO Production Company (PA) II, LLC and BG Production Company (WV), LLC legally changed its name to EXCO Production Company (WV) II, LLC;
Shell and EXCO terminated and considered to be fulfilled obligations and liabilities under certain specified agreements related to the Appalachia JV;
EXCO reconveyed its interests in certain leases, representing an interest in 364 net acres, that EXCO had previously acquired from Shell within the area of mutual interest, in exchange for consideration of $0.7 million;
EXCO and Shell mutually released all existing, future, known, and unknown claims for all existing, future, known, and unknown damages and remedies that each party may have against one another arising out of or relating to the joint development agreement, the area of mutual interest, the arbitration, the state court action, and all joint venture dealings among the parties and certain of their affiliates in the Appalachia region, except as expressly provided in the settlement; and
EXCO caused the arbitration and the state court action to be dismissed with prejudice.

The settlement increased our acreage in the Appalachia region by approximately 177,700 net acres, and the production from the additional interests in producing wells acquired was 26 net Mmcfe per day during December 2017. In addition, EXCO now owns 100% of OPCO and Appalachia Midstream subsequent to the settlement. Prior to the settlement, we accounted for our 50% ownership interests in OPCO and Appalachia Midstream as equity method investments. The entities associated with the Appalachia JV Settlement, including EXCO Production Company (PA) II, LLC, EXCO Production Company (WV) II, LLC, OPCO, and Appalachia Midstream, have not filed for relief under Chapter 11 of the Bankruptcy Code, and the operations of these entities are not expected to be affected by the Chapter 11 Cases.


13


We accounted for the acquisitions in accordance with FASB ASC 805, Business Combinations. The following table presents a summary of the fair value of assets acquired and liabilities assumed as part of the Appalachia JV Settlement as of the closing date.
(in thousands)
 
Amount
Assets acquired:
 
 
Cash and cash equivalents
 
$
14,832

Accounts receivable, net
 
6,493

Other current assets
 
5,264

Unproved oil and natural gas properties
 
33,542

Proved developed and undeveloped oil and natural gas properties, net
 
72,548

Other assets
 
18,109

Liabilities assumed:
 
 
Accounts payable and accrued liabilities
 
(9,478
)
Asset retirement obligations
 
(2,315
)
Other long-term liabilities
 
(9,895
)
Fair value of net assets acquired
 
$
129,100


The fair value of the assets and liabilities acquired as part of the Appalachia JV Settlement of $129.1 million resulted in a gain of $119.5 million after remeasurement of our previously held equity interest in OPCO and Appalachia Midstream. As of the closing date, the carrying value of our equity investments in OPCO and Appalachia Midstream was $9.6 million.

We performed a valuation of the assets and liabilities acquired as of the closing date. A summary of the key inputs are as follows:

Working capital - The fair value approximated the carrying value for working capital including cash and cash equivalents, accounts receivable, other current assets, accounts payable and accrued liabilities.

Oil and natural gas properties - The fair value allocated to unproved and proved oil and natural gas properties was $33.5 million and $72.5 million, respectively. The fair value of oil and natural gas properties was determined based on a discounted cash flow model of the estimated reserves. The estimated quantities of reserves utilized assumptions based on our internal geological, engineering data and financial data. We utilized NYMEX forward strip prices to value the reserves then applied various discount rates depending on the classification of reserves and other risk characteristics.

Other assets - The fair value allocated to other assets was $18.1 million, which is primarily comprised of natural gas gathering assets held by Appalachia Midstream. The fair value of the natural gas gathering assets was determined based on transaction multiples of peer companies and a discounted cash flow model from our internally generated oil and natural gas reserves for the related properties.

Asset retirement liabilities - The fair value allocated to asset retirement obligations was $2.3 million. These asset retirement obligations represent the present value of the estimated amount to be incurred to plug, abandon and remediate proved producing properties at the end of their productive lives, in accordance with applicable state laws. The fair value was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate, and timing associated with the incurrence of these costs.

Firm transportation contract - OPCO holds a contract that requires it to transport a minimum volume of natural gas or pay reservation charges. The performance obligations under the contract exceeded the future economic benefit to be received over the life of the contract. We calculated the fair value as the present value of the remaining unused commitments discounted at a rate consistent with market participants. The fair value of the liability was $12.1 million, including the current portion of $2.2 million and the long-term portion of $9.9 million.

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Pro forma results of operations - The following table reflects the unaudited pro forma results of operations if the Appalachia JV Settlement had occurred on January 1, 2017:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in thousands except for per share data)
2018
 
2017
 
2018
 
2017
Oil and natural gas revenues
$
98,130

 
$
77,525

 
$
192,673

 
$
161,082

Net income (loss)
7,744

 
122,683

 
(202,045
)
 
132,842

Basic earnings (loss) per share
$
0.36

 
$
6.23

 
$
(9.29
)
 
$
6.91

Diluted earnings (loss) per share
$
0.36

 
$
6.17

 
$
(9.29
)
 
$
6.85


Related party transactions - As noted previously, prior to the Appalachia JV Settlement, we accounted for our 50% ownership interests in OPCO and Appalachia Midstream as equity method investments. OPCO served as the operator of our wells in the Appalachia JV and we advanced funds to OPCO on an as needed basis. Additionally, there were service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. Prior to the closing of the settlement, we had received $1.7 million under these agreements during 2018.

4.Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the six months ended June 30, 2018:
(in thousands)
 
 
Asset retirement obligations at beginning of period
 
$
12,017

Activity during the period:
 
 
Liabilities incurred during the period
 

Revisions in estimated assumptions
 
(1
)
Liabilities settled during the period
 
(47
)
Adjustment to liability due to acquisitions (1)
 
2,319

Adjustment to liability due to divestitures
 
(7
)
Accretion of discount
 
507

Asset retirement obligations at end of period
 
14,788

Less current portion
 
600

Long-term portion
 
$
14,188


(1)
The increase in our asset retirement obligations during the six months ended June 30, 2018 is primarily due to additional interests in oil and natural gas properties acquired as part of the Appalachia JV Settlement.

Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs and assumptions developed by management. We do not have any assets that are legally restricted for purposes of settling asset retirement obligations.

5.Oil and natural gas properties

We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties (collectively, the “full cost pool”). We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. The majority of our undeveloped properties are held-by-production, which reduces the risk of impairment as a result of lease expirations. There were no impairments of unproved properties during the three and six months ended June 30, 2018 and 2017.

At the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs (“ceiling test”). The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling

15


limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC, less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. The rejection of these executory contracts has positively impacted the present value of our proved reserves. See further discussion of the rejection of executory contracts in “Note 1. Organization and basis of presentation”.

The ceiling test for each period was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing twelve-month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.
 
 
Average spot prices
 
 
Oil (per Bbl)
 
Natural gas (per Mmbtu)
June 30, 2018
 
$
57.68

 
$
2.92

March 31, 2018
 
53.49

 
3.00

December 31, 2017
 
51.34

 
2.98


We did not recognize an impairment to our proved oil and natural gas properties for the three and six months ended June 30, 2018 and 2017. The possibility and amount of any future impairments is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves, future capital expenditures and operating costs.

As of June 30, 2018, our proved undeveloped reserves were limited to certain wells expected to be completed during 2018. Our recognition of proved undeveloped reserves continues to be affected by the uncertainty regarding our availability of capital required to develop these reserves. A significant amount of our proved undeveloped reserves that were previously reclassified to unproved remain economic at current prices, and we may report proved undeveloped reserves in the future if we determine we have the financial capability to execute a development plan.

The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are inherent uncertainties in estimating quantities of proved reserves including projecting the future rates of production and the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data, and engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.


16


6.Earnings (loss) per share

The following table presents the basic and diluted earnings (loss) per share computations, adjusted to give effect to our reverse share split on June 12, 2017, for the three and six months ended June 30, 2018 and 2017:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in thousands, except per share data)
 
2018
 
2017
 
2018
 
2017
Basic net income (loss) per common share:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
7,744

 
$
120,750

 
$
(203,305
)
 
$
128,943

Weighted average common shares outstanding
 
21,615

 
19,702

 
21,758

 
19,217

Net income (loss) per basic common share
 
$
0.36

 
$
6.13

 
$
(9.34
)
 
$
6.71

Diluted net income (loss) per common share:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
7,744

 
$
120,750

 
$
(203,305
)
 
$
128,943

Weighted average common shares outstanding
 
21,615

 
19,702

 
21,758

 
19,217

Dilutive effect of:
 
 
 
 
 
 
 
 
Restricted shares and restricted share units
 

 
184

 

 
176

Weighted average common shares and common share equivalents outstanding
 
21,615

 
19,886

 
21,758

 
19,393

Net income (loss) per diluted common share
 
$
0.36

 
$
6.07

 
$
(9.34
)
 
$
6.65


Basic net income (loss) per common share is based on the weighted average number of common shares outstanding during the period. In addition, warrants representing the right to purchase our common shares at an exercise price of $0.01 are included in our weighted average common shares outstanding and used in the computation of our basic net income (loss) per common share.

Diluted net income (loss) per common share for the three and six months ended June 30, 2018 and 2017 is computed in the same manner as basic net income (loss) per share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards, warrants representing the right to purchase our common shares at an exercise price of $13.95, and for the three and six months ended June 30, 2017, warrants issued to Energy Strategic Advisory Services LLC (“ESAS”), whether exercisable or not. The computation of diluted net income (loss) per share excluded 10,832,383 and 7,647,365 antidilutive share equivalents for the three months ended June 30, 2018 and 2017, respectively, and 11,731,347 and 4,026,159 antidilutive common share equivalents for the six months ended June 30, 2018 and 2017, respectively. The antidilutive common share equivalents for the three and six months ended June 30, 2018 primarily related to the warrants representing the right to purchase our common shares at an exercise price of $13.95. The antidilutive common share equivalents for the three and six months ended June 30, 2017 primarily related to warrants issued to ESAS. On November 9, 2017, the ESAS Warrants were forfeited as a result of suspension of the services and investment agreement with ESAS.

7.Derivative financial instruments

Our derivative financial instruments are comprised of commodity derivatives and common share warrants.

The table below presents the effect of derivative financial instruments on our Condensed Consolidated Balance Sheets:
(in thousands)
 
 
 
June 30, 2018
 
December 31, 2017
Current assets
 
Derivative financial instruments - commodity derivatives
 
$

 
$
1,150

Liabilities subject to compromise
 
Derivative financial instruments - common share warrants
 
(235
)
 

Long-term liabilities
 
Derivative financial instruments - common share warrants
 

 
(1,950
)

17



The table below presents the effect of derivative financial instruments on our Condensed Consolidated Statements of Operations.
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in thousands)
 
2018
 
2017
 
2018
 
2017
Gain (loss) on derivative financial instruments - commodity derivatives
 
$

 
$
6,541

 
$
(615
)
 
$
22,074

Gain on derivative financial instruments - common share warrants
 
1,532

 
122,295

 
1,715

 
128,299

Commodity derivative financial instruments

We have historically entered into commodity derivative financial instruments to manage our exposure to commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow from operations. These transactions limit exposure to declines in commodity prices, but also limit the benefits we would realize if commodity prices increase. Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursements to, our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts, which include both cash settlements and non-cash changes in fair value, are included in earnings with a corresponding increase or decrease in the Condensed Consolidated Balance Sheets fair value amounts.

At December 31, 2017, we had outstanding swap contracts covering 3,650 Bbtu of natural gas at a weighted average strike price of $3.15 per Mmbtu. In January 2018, the counterparty to our remaining open swap contracts early terminated the outstanding contracts effective January 31, 2018.  We received proceeds of $0.5 million for the settlement of these contracts in February 2018. As of June 30, 2018, we did not have any outstanding commodity derivative financial instruments.

Common share warrants

In connection with the issuance of the 1.5 Lien Notes, on March 15, 2017, we issued warrants to the investors of the 1.5 Lien Notes representing the right to purchase an aggregate of up to 21,505,383 common shares (assuming a cash exercise) at an exercise price of $13.95 per share (“Financing Warrants”), and warrants representing the right to purchase an aggregate of up to 431,433 common shares (assuming a cash exercise) at an exercise price of $0.01 per share (“Commitment Fee Warrants”). In addition, certain exchanging holders of the Second Lien Term Loans received warrants representing the right to purchase an aggregate of up to 1,325,546 common shares (assuming a cash exercise) at an exercise price of $0.01 per share (“Amendment Fee Warrants”, and with the Commitment Fee Warrants and Financing Warrants, collectively referred to as the “2017 Warrants”).

On January 16, 2018, affiliates of Fairfax, which had previously been identified as a related party, surrendered all of their rights to the Commitment Fee, Amendment Fee and Financing Warrants. Their rights under the 2017 Warrants entitled them to purchase in aggregate up to 10,824,376 common shares at $13.95 per share and 1,725,576 common shares at $0.01 per share.

Pursuant to the terms of the 2017 Warrants, the 2017 Warrants may not be exercised, subject to certain exceptions and limitations, if, as a result of such exercise, the holder or its affiliates would beneficially own, directly or indirectly, more than 50% of our outstanding common shares. Each of the 2017 Warrants has an exercise term of 5 years from May 31, 2017 and, subject to certain exceptions, may be exercised by cash or cashless exercise. The Financing Warrants are subject to an anti-dilution adjustment in the event we issue common shares for consideration less than the market value of our common shares or exercise price of the Financing Warrants, subject to certain adjustments and exceptions. The Commitment Fee Warrants and the Amendment Fee Warrants are subject to an anti-dilution adjustment in the event we issue common shares at a price per share less than $10.50 per share, subject to certain exceptions and adjustments. The 2017 Warrants are accounted for as derivatives in accordance with FASB ASC 815, Derivatives and Hedging, (“ASC 815”), and are required to be classified as liabilities due to the types of anti-dilution adjustments.

We record the 2017 Warrants as non-current liabilities at fair value, with the increase or decrease in fair value being recognized in earnings. The 2017 Warrants will be measured at fair value on a recurring basis until the date of exercise or the date of expiration. As a result of the change in the fair value of the 2017 Warrants, we recorded gains of $1.5 million and $122.3 million during the three months ended June 30, 2018 and 2017, respectively, and $1.7 million and $128.3 million during the six months ended June 30, 2018 and 2017, respectively, on the revaluation of the warrants, in “Gain on derivative financial instruments - common share warrants” on the Condensed Consolidated Statements of Operations. The gains were primarily due to a decrease in EXCO’s share price and the cancellation of warrants by affiliates of Fairfax.

18


8.Debt

The carrying value of our total debt is summarized as follows:
(in thousands)
 
June 30, 2018
 
December 31, 2017
DIP Credit Agreement
 
$
156,406

 
$

EXCO Resources Credit Agreement
 

 
126,401

1.5 Lien Notes, net of unamortized discount
 
316,958

 
176,560

1.75 Lien Term Loans, net of unamortized discount
 
708,926

 
845,763

Second Lien Term Loans
 
17,246

 
23,543

2018 Notes, net of unamortized discount
 
131,576

 
131,345

2022 Notes
 
70,169

 
70,169

Deferred financing costs, net
 

 
(11,281
)
Total debt, net
 
1,401,281

 
1,362,500

Less amounts included in liabilities subject to compromise
 
927,917

 

Current maturities of long-term debt
 
$
473,364

 
$
1,362,500


As of December 31, 2017, we classified all of our outstanding indebtedness as a current liability as a result of agreements entered into in anticipation of events of default under certain debt agreements, as well as any outstanding debt with cross-default provisions, and an event of default under the Second Lien Term Loans. The commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the EXCO Resources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, 2018 Notes and 2022 Notes. These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code.

As of the Petition Date, we adjusted the carrying value of our indebtedness to the estimated amount that will be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate and may materially differ from actual future settlement amounts paid. This resulted in expenses of $24.4 million for the acceleration of (i) deferred financing costs, (ii) debt discounts, and (iii) deferred reductions in carrying value associated with debt instruments previously accounted for as a troubled debt restructuring pursuant to ASC 470-60, which was classified as “Reorganization items, net” in our Condensed Consolidated Statement of Operations for the six months ended June 30, 2018. As discussed below, the proceeds from the DIP Facilities were used to repay all obligations under the EXCO Resources Credit Agreement and the EXCO Resources Credit Agreement was terminated. The financing costs of $6.1 million that were directly attributable to the DIP Credit Agreement were expensed as “Reorganization items, net” in our Condensed Consolidated Statement of Operations for the six months ended June 30, 2018.

On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. We accrued interest on 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes through the Petition Date with no interest accrued subsequent to the filings. The 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes have been reclassified as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheet as of June 30, 2018. As of June 30, 2018, the carrying value for each of our debt instruments approximates the principal amount. As of June 30, 2018, the principal and accrued interest associated with the DIP Credit Agreement and 1.5 Lien Notes were not classified as liabilities subject to compromise as a result of the adequate protection approved by the Court and our current estimate of the recoverability of claims related to these debt instruments.
DIP Credit Agreement

On January 18, 2018, the Court entered into an interim order that authorized us to enter into the DIP Credit Agreement. On January 22, 2018, we closed the DIP Credit Agreement, which includes the Revolver A Facility in an aggregate principal amount of $125.0 million and the Revolver B Facility in an aggregate principal amount of $125.0 million with the DIP Lenders. Hamblin Watsa Investment Counsel Ltd. is the administrative agent (“DIP Agent”) for the DIP Credit Agreement. The proceeds of the DIP Facilities may be used in accordance with the DIP Credit Agreement to (i) repay obligations outstanding under the EXCO Resources Credit Agreement, (ii) pay for operating expenses incurred during the Chapter 11 Cases subject to a budget provided to the DIP Lenders under the DIP Credit Agreement, (iii) pay for certain transaction costs, fees and expenses,

19


and (iv) pay for certain other costs and expenses of administering the Chapter 11 Cases. We used approximately $104.0 million of the proceeds provided through the DIP Facilities to repay all obligations outstanding under the EXCO Resources Credit Agreement. Under the DIP Credit Agreement, approximately $24.0 million of outstanding letters of credit were deemed issued under the Revolver A Facility, and approximately $21.6 million of loans outstanding under the EXCO Resources Agreement were deemed exchanged for loans under the Revolver B Facility.

On February 22, 2018, the Court entered into a final order authorizing entry into the DIP Credit Agreement on a final basis. The entry into the final order resulted in the termination of the EXCO Resources Credit Agreement. As of June 30, 2018, we had $156.4 million in outstanding indebtedness and $12.0 million of letters of credit outstanding under the DIP Facilities. Our available borrowing capacity under the DIP Facilities was $81.6 million as of June 30, 2018.

All amounts outstanding under the DIP Facilities bear interest at an adjusted LIBOR plus 4.00% per annum. During the continuance of an event of default under the DIP Facilities, the outstanding amounts bear interest at an additional 2.00% per annum above the interest rate otherwise applicable.

The DIP Facilities will mature on the earliest of (a) 12 months from the initial borrowings on January 22, 2018, (b) the effective date of a plan of reorganization in the Chapter 11 Cases, or (c) the date of termination of all revolving commitments and/or the acceleration of the obligations under the DIP Facilities following an event of default. The DIP Credit Agreement provided us with an option to extend the maturity of the DIP Facilities to the date that is 18 months from the initial borrowing date if certain conditions are met. These conditions included a requirement to file a plan of reorganization with the Court no later than July 1, 2018. We did not file a plan of reorganization with the Court prior to July 1, 2018; therefore, an extension of the DIP Facilities beyond the original maturity date would require a waiver or consent from the DIP Lenders. Borrowings under the DIP Credit Agreement are subject to an initial borrowing base of $250.0 million. The initial borrowing base redetermination will occur on or about January 1, 2019. Thereafter, the borrowing base will be subject to adjustment semi-annually, on April 1 and October 1 of each year based upon the value of our oil and gas reserves. The DIP Lenders have considerable discretion in setting our borrowing base as part of the redetermination process. However, we may elect to redetermine the borrowing base to an amount equal to two-thirds of the net present value, discounted at nine percent, of our proved developed reserves.

The DIP Lenders and the DIP Agent, subject to the Carve-Out (as defined below), at all times: (i) are entitled to joint and several super-priority administrative expense claim status in the Chapter 11 Cases; (ii) have a first priority lien on substantially all of our assets; (iii) have a junior lien on any of our assets subject to a valid, perfected and non-avoidable lien as of the Petition Date, other than such liens securing the obligations under the 1.5 Lien Notes, 1.75 Lien Term Loans and Second Lien Term Loans, and (iv) have a first priority pledge of 100% of the stock and other equity interests in each of our direct and indirect subsidiaries. Our obligations to the DIP Lenders and the liens and super-priority claims are subject in each case to a carve out (“Carve-Out”) that accounts for certain administrative, court and legal fees payable in connection with the Chapter 11 Cases.

The DIP Credit Agreement contains certain financial covenants, including, but not limited to:

our cash (as defined in the DIP Credit Agreement) plus unused commitments under the DIP Credit Agreement cannot be less than $20.0 million; and
aggregate disbursements cannot exceed 120% of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) set forth in the 13-week forecasts provided to the DIP Agent. The testing period is based on the immediately preceding four-week period and is measured every two weeks. The 13-week forecast is provided to the DIP Agent on a monthly basis and shall be consistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to the DIP Agent.

As of June 30, 2018, we were in compliance with all of the covenants under the DIP Credit Agreement. The DIP Credit Agreement contains events of default, including: (i) conversion of the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code and (ii) appointment of a trustee, examiner or receiver in the Chapter 11 Cases. The DIP Facilities contained an event of default if we failed to pursue a Court hearing no later than July 1, 2018 to consider the sale of all or substantially all of our assets; however, the final order entered by the Court deemed this requirement to be no longer in force and effect.

9.Fair value measurements

We value our derivatives and other financial instruments according to FASB ASC 820, Fair Value Measurements and Disclosures, which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability
(“exit price”) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.

We categorize the inputs used in measuring fair value into a three-tier fair value hierarchy. These tiers include:
Level 1 – Observable inputs, such as quoted market prices in active markets, for substantially identical assets and liabilities.
Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability.
Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring development of fair value assumptions by management.

During the six months ended June 30, 2018 and 2017 there were no changes in the fair value level classifications.
Fair value of derivative financial instruments

The following table presents a summary of the estimated fair value of our derivative financial instruments as of June 30, 2018 and December 31, 2017.
 
 
As of June 30, 2018
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total
Liabilities:
 
 
 
 
 
 
 
 
Derivative financial instruments - common share warrants
 
$

 
$
235

 
$

 
$
235

 
 
As of December 31, 2017
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets:
 
 
 
 
 
 
 
 
Derivative financial instruments - commodity derivatives
 
$

 
$
1,150

 
$

 
$
1,150

Liabilities:
 
 
 
 
 
 
 
 
Derivative financial instruments - common share warrants
 

 
1,950

 

 
1,950

Derivative financial instruments - commodity derivatives

We have historically evaluated commodity derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis in our Condensed Consolidated Balance Sheets. Net commodity derivative asset values are determined primarily by quoted NYMEX futures prices, notional volumes and utilization of the counterparties’ credit-adjusted risk-free rate curves and net commodity derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the LIBOR curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period. The fair value of our commodity derivative financial instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers or sellers.
Derivative financial instruments - common share warrants

The liability attributable to our common share warrants as of the issuance date and the end of each reporting period is measured using the Black-Scholes model based on inputs including our share price, volatility, expected remaining life and the risk-free rate of return. The implied rates of volatility were determined based on historical prices of our common shares over a period consistent with the expected remaining life. Common share warrants are measured at fair value on a recurring basis until the date of exercise or the date of expiration.

See further details on our derivative financial instruments in “Note 7. Derivative financial instruments”.

20


Fair value of other financial instruments

Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued liabilities.  The carrying amount of these instruments approximates fair value because of their short-term nature.

The carrying values of our borrowings under the DIP Credit Agreement approximate fair value, as these are subject to short-term floating interest rates that approximate the rates available to us for those periods.

The estimated fair values of our senior notes and term loans are presented below. The estimated fair values of the 2018 Notes and 2022 Notes have been calculated based on quoted prices in active markets. The estimated fair value of the 1.5 Lien Notes was calculated based on a model internally prepared by management that lacks significant observable inputs and was classified as Level 3. The 1.75 Lien Term Loans and the Second Lien Term Loans have been calculated based on quoted prices obtained from third-party pricing sources that lack significant observable inputs and are classified as Level 3. The 2017 Warrants are considered freestanding financial instruments and are not considered in the determination of the fair value of the 1.5 Lien Notes and 1.75 Lien Term Loans. See “Note 8. Debt” for the carrying value and the principal balance of each debt instrument included in the table below.
 
 
As of June 30, 2018
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total
1.5 Lien Notes
 
$

 
$

 
$
224,447

 
$
224,447

1.75 Lien Term Loans
 

 

 
317,244

 
317,244

Second Lien Term Loans
 

 

 
7,718

 
7,718

2018 Notes
 
21,751

 

 

 
21,751

2022 Notes
 
12,250

 

 

 
12,250

 
 
As of December 31, 2017
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total
1.5 Lien Notes
 
$

 
$

 
$
232,276

 
$
232,276

1.75 Lien Term Loans
 

 

 
372,186

 
372,186

Second Lien Term Loans
 

 

 
9,054

 
9,054

2018 Notes
 
4,658

 

 

 
4,658

2022 Notes
 
2,586

 

 

 
2,586


10.Income taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our annual effective tax rate is highly sensitive to estimates of ordinary income or loss primarily due to significant permanent differences related to the non-taxable gains or losses on the 2017 Warrants and non-deductible interest on our 1.5 Lien Notes and 1.75 Lien Term Loans.

We have accumulated financial net deferred tax assets primarily due to losses arising from impairments to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Our valuation allowances increased $40.1 million for the six months ended June 30, 2018. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $883.6 million that have fully offset our net deferred tax assets as of June 30, 2018. The valuation allowances will continue to be recognized until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowances do not impact future utilization of the underlying tax attributes.

The utilization of our NOLs to offset taxable income in future periods may be limited if we undergo an ownership change pursuant to the criteria in Section 382 of the Internal Revenue Code. Generally, an ownership change occurs for Section 382 purposes when the percentage of stock held by one or more five-percent shareholders increases by more than 50 percentage points over the lowest stock ownership held by such shareholders on any testing date within a three-year period. See further discussion of restrictions imposed by the Court on the trading of our equity securities to protect our use of NOLs in “Note 1. Organization and basis of presentation”. The Internal Revenue Code permits the exclusion of cancellation of debt income from taxable income if the discharge occurs during a Chapter 11 case. If this occurs, the amount of cancellation of debt income would reduce a company’s tax attributes unless it is offset by NOLs. The NOLs that are available to offset cancellation of debt

21


income in a Chapter 11 case are not limited by Section 382 of the Internal Revenue Code. As of June 30, 2018, we had estimated NOLs of $2.2 billion.

On December 22, 2017, the United States enacted the Tax Act which, among other things, lowered the U.S. Federal tax rate from 35% to 21%, repealed the corporate alternative minimum tax, and provided for a refund of previously accrued alternative minimum tax credits. We reflected the impact of this rate on our deferred tax assets and liabilities at December 31, 2017, as it is required to reflect the change in the period in which the law is enacted. The Tax Act also repealed the corporate alternative minimum tax for tax years beginning after January 1, 2018 and provided that prior alternative minimum tax credits would be refundable. We have credits that are expected to be refunded between 2018 and 2020 as a result of the Tax Act and monetization opportunities under current law in 2017. In addition, the Tax Act limits the amount taxpayers are able to deduct for NOLs generated in taxable years beginning after December 31, 2017 to 80% of the taxpayer’s taxable income. The law also generally repeals all carrybacks for losses generated in taxable years ending after December 31, 2017. However, any NOLs generated in taxable years ending after December 31, 2017 can be carried forward indefinitely. We are still analyzing certain aspects of the Tax Act, which could potentially affect the measurement of our income tax balances and future income tax expense or benefit. The ultimate impact of the Tax Act may differ from the estimates provided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of the Tax Act.

As of December 31, 2017, we recognized a deferred tax liability of $4.5 million for tax-deductible goodwill. The deferred tax liability related to goodwill was considered to have an indefinite life based on the nature of the underlying asset and could not be offset under GAAP with a deferred tax asset with a definite life, such as NOLs. As a result of the Tax Act, deferred tax assets resulting from NOLs generated in taxable years subsequent to December 31, 2017 are considered to have an indefinite life. Therefore, we recognized an income tax benefit of $4.5 million during the six months ended June 30, 2018 because we expect to be able to utilize deferred tax assets related to NOLs to offset the deferred tax liability related to goodwill.

11.Condensed consolidating financial statements

As of June 30, 2018, the majority of EXCO’s subsidiaries were guarantors under the DIP Credit Agreement, the indenture governing the 1.5 Lien Notes, the credit agreements governing the 1.75 Lien Term Loans and Second Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes. All of our unrestricted subsidiaries under the 1.5 Lien Notes, 1.75 Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes are considered non-guarantor subsidiaries.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The DIP Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by substantially all of our subsidiaries (referred to as Guarantor Subsidiaries). For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish it from the Guarantor Subsidiaries. Each of the Guarantor Subsidiaries is a 100% owned subsidiary of Resources and the guarantees are unconditional as they relate to the assets of the Guarantor Subsidiaries. Resources and the Guarantor Subsidiaries solely consist of entities that are Debtors in the Chapter 11 Cases, including each of the Filing Subsidiaries. The non-guarantor subsidiaries solely consist of entities that are not included in the Chapter 11 Cases, including OPCO, Appalachia Midstream, EXCO Production Company (PA) II, LLC, EXCO Production Company (WV) II, LLC and certain other entities (referred to as Non-Guarantor Subsidiaries).

The following financial information presents consolidating financial statements, which include:
Resources;
the Guarantor Subsidiaries;
the Non-Guarantor Subsidiaries;
elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and
EXCO on a consolidated basis.

Investments in subsidiaries are accounted for using the equity method of accounting for the disclosures within this footnote. The financial information for the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.

22


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING BALANCE SHEET
(Unaudited)
As of June 30, 2018
(in thousands)
 
Resources
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
52,501

 
$
(16,482
)
 
$
18,976

 
$

 
$
54,995

Restricted cash
 
915

 
10,069

 

 

 
10,984

Other current assets
 
10,150

 
115,430

 
5,916

 

 
131,496

Total current assets
 
63,566

 
109,017

 
24,892

 

 
197,475

Equity investments
 

 

 
4,736

 

 
4,736

Oil and natural gas properties (full cost accounting method):
 
 
 
 
 
 
 
 
 
 
Unproved oil and natural gas properties and development costs not being amortized
 

 
115,707

 
33,542

 

 
149,249

Proved developed and undeveloped oil and natural gas properties
 
334,666

 
2,873,719

 
72,719

 

 
3,281,104

Accumulated depletion
 
(330,776
)
 
(2,458,662
)
 
(2,480
)
 

 
(2,791,918
)
Oil and natural gas properties, net
 
3,890

 
530,764

 
103,781

 

 
638,435

Other property and equipment, net and other non-current assets
 
984

 
20,188

 
17,761

 

 
38,933

Investments in and (advances to) affiliates, net
 
334,865

 

 

 
(334,865
)
 

Goodwill
 
13,293

 
149,862

 

 

 
163,155

Total assets
 
$
416,598

 
$
809,831

 
$
151,170

 
$
(334,865
)
 
$
1,042,734

Liabilities and shareholders’ equity
 
 
 
 
 
 
 
 
 
 
Current maturities of long-term debt
 
$
473,364

 
$

 
$

 
$

 
$
473,364

Other current liabilities
 
27,515

 
68,606

 
4,478

 

 
100,599

Other long-term liabilities
 

 
14,411

 
11,716

 

 
26,127

Liabilities subject to compromise
 
964,018

 
526,925

 

 

 
1,490,943

Payable to parent
 

 
2,462,964

 
1,499

 
(2,464,463
)
 

Total shareholders’ equity
 
(1,048,299
)
 
(2,263,075
)
 
133,477

 
2,129,598

 
(1,048,299
)
Total liabilities and shareholders’ equity
 
$
416,598

 
$
809,831

 
$
151,170

 
$
(334,865
)
 
$
1,042,734


23


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2017
(in thousands)
 
Resources
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
49,170

 
$
(9,573
)
 
$

 
$

 
$
39,597

Restricted cash
 

 
15,271

 

 

 
15,271

Other current assets
 
22,697

 
90,265

 

 

 
112,962

Total current assets
 
71,867

 
95,963

 

 

 
167,830

Equity investments
 

 

 
14,181

 

 
14,181

Oil and natural gas properties (full cost accounting method):
 
 
 
 
 
 
 
 
 
 
Unproved oil and natural gas properties and development costs not being amortized
 

 
118,652

 

 

 
118,652

Proved developed and undeveloped oil and natural gas properties
 
333,719

 
2,773,847

 

 

 
3,107,566

Accumulated depletion
 
(330,777
)
 
(2,421,534
)
 

 

 
(2,752,311
)
Oil and natural gas properties, net
 
2,942

 
470,965

 

 

 
473,907

Other property and equipment, net and other non-current assets
 
892

 
20,382

 

 

 
21,274

Investments in and (advances to) affiliates, net
 
466,055

 

 

 
(466,055
)
 

Goodwill
 
13,293

 
149,862

 

 

 
163,155

Total assets
 
$
555,049

 
$
737,172

 
$
14,181

 
$
(466,055
)
 
$
840,347

Liabilities and shareholders’ equity
 
 
 
 
 
 
 
 
 
 
Current maturities of long-term debt
 
$
1,362,500

 
$

 
$

 
$

 
$
1,362,500

Other current liabilities
 
32,280

 
272,190

 

 

 
304,470

Derivative financial instruments - common share warrants
 
1,950

 

 

 

 
1,950

Other long-term liabilities
 
4,518

 
13,108

 

 

 
17,626

Payable to parent
 

 
2,447,586

 

 
(2,447,586
)
 

Total shareholders’ equity
 
(846,199
)
 
(1,995,712
)
 
14,181

 
1,981,531

 
(846,199
)
Total liabilities and shareholders’ equity
 
$
555,049

 
$
737,172

 
$
14,181

 
$
(466,055
)
 
$
840,347


24


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the Three Months Ended June 30, 2018
(in thousands)
 
Resources
 
Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$

 
$
87,752

 
$
5,024

 
$

 
$
92,776

Purchased natural gas and marketing
 

 
5,213

 
141

 

 
5,354

Total revenues
 

 
92,965

 
5,165

 

 
98,130

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 

 
14,071

 
884

 

 
14,955

Gathering and transportation
 

 
20,255

 
1,055

 

 
21,310

Purchased natural gas
 

 
3,743

 

 

 
3,743

Depletion, depreciation and amortization
 
77

 
19,858

 
2,065

 

 
22,000

Accretion of liabilities
 

 
230

 
331

 

 
561

General and administrative
 
(9,543
)
 
14,511

 
1,335

 

 
6,303

Other operating items
 
(1
)
 
(1,042
)
 
(98
)
 

 
(1,141
)
    Total costs and expenses
 
(9,467
)
 
71,626

 
5,572

 

 
67,731

Operating income (loss)
 
9,467

 
21,339

 
(407
)
 

 
30,399

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(7,815
)
 

 

 

 
(7,815
)
Gain on derivative financial instruments - common share warrants
 
1,532

 

 

 

 
1,532

Other income
 
4

 
10

 
2

 

 
16

Equity income (loss)
 

 
(179
)
 
179

 

 

Reorganization items, net
 
(16,388
)
 

 

 

 
(16,388
)
Net income from consolidated subsidiaries
 
20,944

 

 

 
(20,944
)
 

    Total other income (expense)
 
(1,723
)
 
(169
)
 
181

 
(20,944
)
 
(22,655
)
Income (loss) before income taxes
 
7,744

 
21,170

 
(226
)
 
(20,944
)
 
7,744

Income tax expense
 

 

 

 

 

Net income (loss)
 
$
7,744

 
$
21,170

 
$
(226
)
 
$
(20,944
)
 
$
7,744



25


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the Three Months Ended June 30, 2017
(in thousands)
 
Resources
 
Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$

 
$
64,487

 
$

 
$

 
$
64,487

Purchased natural gas and marketing
 

 
6,528

 

 

 
6,528

Total revenues
 

 
71,015

 

 

 
71,015

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 

 
11,630

 

 

 
11,630

Gathering and transportation
 

 
27,087

 

 

 
27,087

Purchased natural gas
 

 
6,353

 

 

 
6,353

Depletion, depreciation and amortization
 
75

 
11,547

 

 

 
11,622

Accretion of liabilities
 

 
215

 

 

 
215

General and administrative
 
(16,460
)
 
15,066

 

 

 
(1,394
)
Other operating items
 
179

 
107

 

 

 
286

    Total costs and expenses
 
(16,206
)
 
72,005

 

 

 
55,799

Operating income (loss)
 
16,206

 
(990
)
 

 

 
15,216

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(22,478
)
 
(2
)
 

 

 
(22,480
)
Gain on derivative financial instruments - commodity derivatives
 
6,541

 

 

 

 
6,541

Gain on derivative financial instruments - common share warrants
 
122,295

 

 

 

 
122,295

Loss on restructuring of debt
 
(108
)
 

 

 

 
(108
)
Other expense
 

 
(25
)
 

 

 
(25
)
Equity income
 

 

 
338

 

 
338

Net loss from consolidated subsidiaries
 
(679
)
 

 

 
679

 

    Total other income (expense)
 
105,571

 
(27
)
 
338

 
679

 
106,561

Income (loss) before income taxes
 
121,777

 
(1,017
)
 
338

 
679

 
121,777

Income tax expense
 
1,027

 

 

 

 
1,027

Net income (loss)
 
$
120,750

 
$
(1,017
)
 
$
338

 
$
679

 
$
120,750



26


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the Six Months Ended June 30, 2018
(in thousands)
 
Resources
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$

 
$
171,048

 
$
6,874

 
$

 
$
177,922

Purchased natural gas and marketing
 

 
10,531

 
141

 

 
10,672

Total revenues
 

 
181,579

 
7,015

 

 
188,594

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 

 
25,518

 
1,341

 

 
26,859

Gathering and transportation
 

 
39,906

 
1,380

 

 
41,286

Purchased natural gas
 

 
7,858

 

 

 
7,858

Depletion, depreciation and amortization
 
157

 
37,321

 
2,728

 

 
40,206

Accretion of liabilities
 

 
459

 
444

 

 
903

General and administrative
 
(16,323
)
 
29,383

 
1,770

 

 
14,830

Gain on Appalachia JV Settlement
 

 

 
(119,477
)
 

 
(119,477
)
Other operating items
 
(35
)
 
8,758

 
(9,730
)
 

 
(1,007
)
Total costs and expenses
 
(16,201
)
 
149,203

 
(121,544
)
 

 
11,458

Operating income
 
16,201

 
32,376

 
128,559

 

 
177,136

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(16,988
)
 

 

 

 
(16,988
)
Loss on derivative financial instruments - commodity derivatives
 
(615
)
 

 

 

 
(615
)
Gain on derivative financial instruments - common share warrants
 
1,715

 

 

 

 
1,715

Other income
 
21

 
15

 
2

 

 
38

Equity income
 

 

 
179

 

 
179

Reorganization items, net
 
(60,091
)
 
(309,197
)
 

 

 
(369,288
)
Net loss from consolidated subsidiaries
 
(148,066
)
 

 

 
148,066

 

Total other income (expense)
 
(224,024
)
 
(309,182
)
 
181

 
148,066

 
(384,959
)
Income (loss) before income taxes
 
(207,823
)
 
(276,806
)
 
128,740

 
148,066

 
(207,823
)
Income tax benefit
 
(4,518
)
 

 

 

 
(4,518
)
Net income (loss)
 
$
(203,305
)
 
$
(276,806
)
 
$
128,740

 
$
148,066

 
$
(203,305
)



27


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the Six Months Ended June 30, 2017
(in thousands)
 
Resources
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$

 
$
133,843

 
$

 
$

 
$
133,843

Purchased natural gas and marketing
 

 
13,701

 

 

 
13,701

Total revenues
 

 
147,544

 

 

 
147,544

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 

 
23,563

 

 

 
23,563

Gathering and transportation
 

 
54,440

 

 

 
54,440

Purchased natural gas
 

 
12,805

 

 

 
12,805

Depletion, depreciation and amortization
 
136

 
22,994

 

 

 
23,130

Accretion of liabilities
 

 
427

 

 

 
427

General and administrative
 
(27,127
)
 
30,148

 

 

 
3,021

Other operating items
 
577

 
778

 

 

 
1,355

Total costs and expenses
 
(26,414
)
 
145,155

 

 

 
118,741

Operating income
 
26,414

 
2,389

 

 

 
28,803

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(42,430
)
 
(2
)
 

 

 
(42,432
)
Gain on derivative financial instruments - commodity derivatives
 
22,074

 

 

 

 
22,074

Gain on derivative financial instruments - common share warrants
 
128,299

 

 

 

 
128,299

Loss on restructuring of debt
 
(6,380
)
 

 

 

 
(6,380
)
Other income (expense)
 
1

 
(22
)
 

 

 
(21
)
Equity income
 

 

 
655

 

 
655

Net income from consolidated subsidiaries
 
3,020

 

 

 
(3,020
)
 

Total other income (expense)
 
104,584

 
(24
)
 
655

 
(3,020
)
 
102,195

Income before income taxes
 
130,998

 
2,365

 
655

 
(3,020
)
 
130,998

Income tax expense
 
2,055

 

 

 

 
2,055

Net income
 
$
128,943

 
$
2,365

 
$
655

 
$
(3,020
)
 
$
128,943




28


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Unaudited)
For the Six Months Ended June 30, 2018
(in thousands)
 
Resources
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Operating Activities:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
(1,898
)
 
$
68,917

 
$
2,477

 
$

 
$
69,496

Investing Activities:
 
 
 
 
 
 
 
 
 
 
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
 
(922
)
 
(97,356
)
 
15,000

 

 
(83,278
)
Other
 

 
950

 

 

 
950

Advances/investments with affiliates
 
(16,877
)
 
15,378

 
1,499

 

 

Net cash provided by (used in) investing activities
 
(17,799
)
 
(81,028
)
 
16,499

 

 
(82,328
)
Financing Activities:
 
 
 
 
 
 
 
 
 
 
Borrowings under DIP Credit Agreement
 
156,406

 

 

 

 
156,406

Repayments under EXCO Resources Credit Agreement
 
(126,401
)
 

 

 

 
(126,401
)
Debt financing costs and other
 
(6,062
)
 

 

 

 
(6,062
)
Net cash provided by financing activities
 
23,943

 

 

 

 
23,943

Net increase (decrease) in cash, cash equivalents and restricted cash
 
4,246

 
(12,111
)
 
18,976

 

 
11,111

Cash, cash equivalents and restricted cash at beginning of period
 
49,170

 
5,698

 

 

 
54,868

Cash, cash equivalents and restricted cash at end of period
 
$
53,416

 
$
(6,413
)
 
$
18,976

 
$

 
$
65,979


29


EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Unaudited)
For the Six Months Ended June 30, 2017
(in thousands)
 
Resources
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Operating Activities:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
(5,001
)
 
$
38,602

 
$

 
$

 
$
33,601

Investing Activities:
 
 
 
 
 
 
 
 
 
 
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
 
(727
)
 
(48,214
)
 

 

 
(48,941
)
Proceeds from disposition of property and equipment
 

 
25

 

 

 
25

Net changes in amounts due to joint ventures
 

 
(7,553
)
 

 

 
(7,553
)
Advances/investments with affiliates
 
(34,067
)
 
34,067

 

 

 

Net cash used in investing activities
 
(34,794
)
 
(21,675
)
 

 

 
(56,469
)
Financing Activities:
 
 
 
 
 
 
 
 
 
 
Borrowings under EXCO Resources Credit Agreement
 
25,000

 

 

 

 
25,000

Repayments under EXCO Resources Credit Agreement
 
(253,592
)
 

 

 

 
(253,592
)
Proceeds received from issuance of 1.5 Lien Notes, net
 
295,530

 

 

 

 
295,530

Payments on Second Lien Term Loans
 
(11,057
)
 

 

 

 
(11,057
)
Debt financing costs and other
 
(21,976
)
 

 

 

 
(21,976
)
Net cash provided by financing activities
 
33,905

 

 

 

 
33,905

Net increase (decrease) in cash, cash equivalents and restricted cash
 
(5,890
)
 
16,927

 

 

 
11,037

Cash, cash equivalents and restricted cash at beginning of period
 
24,610

 
(4,392
)
 

 

 
20,218

Cash, cash equivalents and restricted cash at end of period
 
$
18,720

 
$
12,535

 
$

 
$

 
$
31,255



30


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

Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “our,” and “us” are to EXCO Resources, Inc. and its consolidated subsidiaries.
Forward-looking statements

This Quarterly Report on Form 10-Q contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (“the Exchange Act”). These forward-looking statements relate to, among other things, the following:

our future financial and operating performance and results;
our business strategy;
market prices;
our future use of commodity derivative financial instruments;
our liquidity and capital resources; and
our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events. We use the words “may,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “potential,” “project,” “budget” and other similar words to identify forward-looking statements. The statements that contain these words should be read carefully because they discuss future expectations, contain projections of our results of operations or financial condition and/or state other “forward-looking” information. We do not undertake any obligation to update or revise any forward-looking statements, except as required by applicable securities laws. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Quarterly Report on Form 10-Q and the documents incorporated herein by reference, including, but not limited to:

bankruptcy proceedings and the effect of those proceedings on our ongoing and future operations, including the actions of the Court and our creditors;
the outcome of potential strategic alternatives to maximize value for the benefit of our stakeholders as part of the Chapter 11 process, which may include a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certain indebtedness as an alternative to the sale process or a combination thereof;
our ability to negotiate a plan of reorganization in connection with the Chapter 11 process, including the restructuring of our indebtedness;
our future cash flows and the adequacy to fund the significant costs associated with the bankruptcy process, including our ability to limit these costs by obtaining confirmation of a successful plan of reorganization in a timely manner;
our ability to maintain compliance with debt covenants and to meet debt service obligations associated with the DIP Credit Agreement;
our ability to enter into transactions as a result of our Chapter 11 filing, including commodity derivative contracts with financial institutions and services with vendors;
future capital requirements and availability of financing, including limitations on our ability to incur certain types of indebtedness under our debt agreements and to refinance or replace existing debt obligations;
fluctuations in the prices of oil and natural gas;
the availability of oil and natural gas;
disruption of credit and capital markets and the ability of financial institutions to honor their commitments;
estimates of reserves and economic assumptions, including estimates related to acquisitions and dispositions of oil and natural gas properties;
geological concentration of our reserves;
risks associated with drilling and operating wells;
exploratory risks, including those related to our activities in shale formations;
discovery, acquisition, development and replacement of oil and natural gas reserves;
timing and amount of future production of oil and natural gas;
availability of drilling and production equipment;
availability of water, sand and other materials for drilling and completion activities;
marketing of oil and natural gas;
political and economic conditions and events in oil-producing and natural gas-producing countries;
title to our properties;

31


litigation;
competition;
our ability to attract and retain key personnel;
general economic conditions, including costs associated with drilling and operations of our properties;
environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases, legislation of derivative financial instruments, regulation of hydraulic fracture stimulation and elimination of income tax incentives available to our industry;
receipt and collectability of amounts owed to us by purchasers of our production;
our ability and decisions whether or not to enter into commodity derivative financial instruments;
potential acts of terrorism;
our ability to manage joint ventures with third parties, including the resolution of any material disagreements and our partners’ ability to satisfy obligations under these arrangements;
actions of third party co-owners of interests in properties in which we also own an interest;
fluctuations in interest rates;
our ability to effectively integrate companies and properties that we acquire;
our ability to execute our business strategies and other corporate actions; and
our ability to continue as a going concern.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution users of the financial statements not to place undue reliance on any forward-looking statements. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this Quarterly Report on Form 10-Q, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2017, filed with the Securities and Exchange Commission (“SEC”) on March 15, 2018 (“2017 Form 10-K”).

Our revenues, operating results and financial condition depend substantially on prevailing prices for oil and natural gas and the availability of capital from our credit agreement (“DIP Credit Agreement”) and other sources. Declines in oil or natural gas prices may have a material adverse effect on our financial condition, Liquidity, results of operations, the amount of oil or natural gas that we can produce economically and the ability to fund our operations. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Overview and history

We are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of onshore U.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areas including Texas, Louisiana and the Appalachia region.
Recent developments

Chapter 11 Cases

On January 15, 2018 (“Petition Date”), the Company and certain of its subsidiaries, including EXCO Services, Inc., EXCO Partners GP, LLC, EXCO GP Partners OLP, LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, EXCO Midcontinent MLP, LLC, EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC, EXCO Resources (XA), LLC, EXCO Production Company (WV), LLC, EXCO Land Company, LLC, EXCO Holding MLP, Inc., Raider Marketing, LP and Raider Marketing GP, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (“Court”). The Chapter 11 Cases are being jointly administered under the caption In Re EXCO Resources, Inc., Case No. 18-30155 (MI) (“Chapter 11 Cases”). The Court has granted all of the first day motions filed by the Debtors that were designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees. The Debtors continue to operate their businesses as “debtors in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Court. The Debtors expect to continue operations without interruption during the pendency of the Chapter 11 proceedings.

On January 22, 2018, we closed the DIP Credit Agreement with lenders including affiliates of Fairfax Financial Holdings Limited (“Fairfax”), Bluescape Resources Company LLC (“Bluescape”) and JPMorgan Chase Bank, N.A. (collectively the “DIP Lenders”), which includes an initial borrowing base of $250.0 million. Proceeds from the DIP Facilities were used to repay all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 process. The Debtors have not reached an agreement with their creditors

32


for a plan of reorganization and continue to engage in discussions regarding the terms of a financial restructuring plan. In conjunction with this process, we will explore potential strategic alternatives to maximize value for the benefit of our stakeholders, which may include a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certain indebtedness as an alternative to the sale process or a combination thereof.

For the duration of the Chapter 11 proceedings, our operations and ability to develop and execute our business plan are subject to risks and uncertainties associated with Chapter 11 proceedings. As a result of these risks and uncertainties, our assets, liabilities, shareholders’ equity, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this quarterly report on Form 10-Q may not accurately reflect our operations, properties and capital plans following the conclusion of the Chapter 11 Cases. See further discussion of the impact of the bankruptcy proceedings as part of “Note 1. Organization and basis of presentation” in the Notes to our Condensed Consolidated Financial Statements.

Impact on our indebtedness

The commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under our previous revolving credit agreement (“EXCO Resources Credit Agreement”), senior secured 1.5 lien notes due March 20, 2022 (“1.5 Lien Notes”), senior secured 1.75 lien term loans due October 26, 2020 (“1.75 Lien Term Loans”), senior unsecured notes due September 15, 2018 (“2018 Notes”), and senior unsecured notes due April 15, 2022 (“2022 Notes”). These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code.

As of the Petition Date, we adjusted the carrying value of our indebtedness to the estimated amount that will be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate and may materially differ from actual future settlement amounts paid. As of June 30, 2018, the carrying value for each of our debt instruments approximates the principal amount. The corresponding expense associated with the adjustments was recorded as “Reorganization items, net” on our Condensed Consolidated Statement of Operations for the six months ended June 30, 2018.

On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. We accrued interest on 1.75 Lien Term Loans, senior secured second lien term loans due October 26, 2020 (“Second Lien Term Loans”), 2018 Notes and 2022 Notes through the Petition Date, with no interest accrued subsequent to the filings. As a result, we expect our interest expense to decrease in the future.

Rejection of executory contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a breach as of the Petition Date of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a general unsecured claim against the Company or the applicable Filing Subsidiaries for damages caused by such rejection. During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. Our estimate of allowable claims related to the executory contracts approved for rejection by the Court was recorded as “Liabilities subject to compromise” on our Condensed Consolidated Balance Sheet as of June 30, 2018 and the corresponding expense was recorded as “Reorganization items, net” in our Condensed Consolidated Statement of Operations for the six months ended June 30, 2018. We expect our realized natural gas price differentials and transportation expenses to improve in the future as a result of the rejection of these contracts.

On March 1, 2018, the Debtors filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure Midstream Energy, LLC and TGG Pipeline, Ltd. (collectively, “Azure”) through November 30, 2018.  The motion was abated on May, 8, 2018 and on May 16, 2018, EXCO Operating Company, LP and Raider Marketing, LP commenced an adversary proceeding under Adv. Proc. No. 18-03096.  The Debtors initiated this adversary proceeding against Azure to establish that the minimum volume commitment agreement is severable from the base gathering agreement between the parties.  The Debtors and the contract counterparties each filed various dispositive motions that were heard by the Court on August 9, 2018. The Court is anticipated to issue a ruling during the third quarter of 2018.


33


Appalachia JV Settlement

On February 27, 2018, we closed a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region (“Appalachia JV Settlement”). As a result of the Appalachia JV Settlement, we acquired Shell’s interests in our joint venture in Appalachia, including entities that own interests in oil and natural gas properties, an entity that operates the wells in the joint venture in Appalachia (“OPCO”) and an entity that owns and operates midstream assets in the Appalachia region (“Appalachia Midstream”). As a result, our production, revenues and expenses in the Appalachia region are expected to increase in the future. Also, our recoveries of general and administrative expenses related to the joint venture in Appalachia are expected to decrease in the future. See further discussion of this settlement as part of “Note 3. Acquisitions, divestitures and other significant events” in the Notes to our Condensed Consolidated Financial Statements.

Critical accounting policies

We consider accounting policies related to our estimates of proved reserves, oil and natural gas properties, derivatives, business combinations, equity-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the date of the condensed consolidated financial statements. Actual results could differ from these estimates. These policies and others are summarized in the 2017 Form 10-K. In addition, see further discussion of our application of ASC 852 (as defined below) as a result of the Chapter 11 Cases in “Note 1. Organization and basis of presentation” in the Notes to our Condensed Consolidated Financial Statements.

Accounting during bankruptcy

We have applied Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), in the preparation of these Condensed Consolidated Financial Statements. For periods subsequent to the Chapter 11 filings, ASC 852 requires the financial statements to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred during the bankruptcy proceedings, including losses related to executory contracts that have been approved for rejection by the Court, and adjustments to the carrying value of certain indebtedness are recorded as “Reorganization items, net” on the Condensed Consolidated Statement of Operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the Condensed Consolidated Balance Sheet as of June 30, 2018 as “Liabilities subject to compromise.” See further discussion of the impact of the application of ASC 852 as part of “Note 1. Organization and basis of presentation” in the Notes to our Condensed Consolidated Financial Statements.


34


Our results of operations

A summary of key financial data for the three and six months ended June 30, 2018 and 2017 related to our results of operations is presented below:
 
 
Three Months Ended June 30,
 
Quarter to quarter change
 
Six Months Ended June 30,
 
Period to period change
(dollars in thousands, except per unit prices)
 
2018
 
2017
 
 
2018
 
2017
 
Production:
 
 
 
 
 
 
 
 
 
 
 
 
Oil (Mbbls)
 
356

 
303

 
53

 
612

 
634

 
(22
)
Natural gas (Mmcf)
 
27,468

 
19,063

 
8,405

 
51,310

 
38,786

 
12,524

Total production (Mmcfe) (1)
 
29,604

 
20,881

 
8,723

 
54,982

 
42,590

 
12,392

Average daily production (Mmcfe)
 
325

 
229

 
96

 
304

 
235

 
69

Revenues before commodity derivative financial instrument activities:
Oil
 
$
24,314

 
$
14,305

 
$
10,009

 
$
40,611

 
$
30,497

 
$
10,114

Natural gas
 
68,462

 
50,182

 
18,280

 
137,311

 
103,346

 
33,965

Total oil and natural gas revenues
 
92,776

 
64,487

 
28,289

 
177,922

 
133,843

 
44,079

Purchased natural gas and marketing
 
5,354

 
6,528

 
(1,174
)
 
10,672

 
13,701

 
(3,029
)
Total revenues
 
$
98,130

 
$
71,015

 
$
27,115

 
$
188,594

 
$
147,544

 
$
41,050

Commodity derivative financial instruments:
Gain (loss) on derivative financial instruments - commodity derivatives
 
$

 
$
6,541

 
$
(6,541
)
 
$
(615
)
 
$
22,074

 
$
(22,689
)
Average sales price (before cash settlements of commodity derivative financial instruments):
Oil (per Bbl)
 
$
68.30

 
$
47.21

 
$
21.09

 
$
66.36

 
$
48.10

 
$
18.26

Natural gas (per Mcf)
 
2.49

 
2.63

 
(0.14
)
 
2.68

 
2.66

 
0.02

Natural gas equivalent (per Mcfe)
 
3.13

 
3.09

 
0.04

 
3.24

 
3.14

 
0.10

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas operating costs
 
$
10,874

 
$
8,215

 
$
2,659

 
$
18,782

 
$
16,713

 
$
2,069

Production and ad valorem taxes
 
4,081

 
3,415

 
666

 
8,077

 
6,850

 
1,227

Gathering and transportation
 
21,310

 
27,087

 
(5,777
)
 
41,286

 
54,440

 
(13,154
)
Purchased natural gas
 
3,743

 
6,353

 
(2,610
)
 
7,858

 
12,805

 
(4,947
)
Depletion
 
21,640

 
11,359

 
10,281

 
39,607

 
22,561

 
17,046

Depreciation and amortization
 
360

 
263

 
97

 
599

 
569

 
30

General and administrative (2)
 
6,303

 
(1,394
)
 
7,697

 
14,830

 
3,021

 
11,809

Interest expense, net
 
7,815

 
22,480

 
(14,665
)
 
16,988

 
42,432

 
(25,444
)
Costs and expenses (per Mcfe):
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas operating costs
 
$
0.37

 
$
0.39

 
$
(0.02
)
 
$
0.34

 
$
0.39

 
$
(0.05
)
Production and ad valorem taxes
 
0.14

 
0.16

 
(0.02
)
 
0.15

 
0.16

 
(0.01
)
Gathering and transportation
 
0.72

 
1.30

 
(0.58
)
 
0.75

 
1.28

 
(0.53
)
Depletion
 
0.73

 
0.54

 
0.19

 
0.72

 
0.53

 
0.19

Depreciation and amortization
 
0.01

 
0.01

 

 
0.01

 
0.01

 

Net income (loss)
 
$
7,744

 
$
120,750

 
$
(113,006
)
 
$
(203,305
)
 
$
128,943

 
$
(332,248
)

(1)
Mmcfe is calculated by converting one barrel of oil into six Mcf of natural gas.
(2)
Equity-based compensation included in general and administrative expense was expense of $0.5 million and income of $8.0 million for the three months ended June 30, 2018 and 2017, respectively, and expense of $0.9 million and income of $10.3 million for the six months ended June 30, 2018 and 2017, respectively.

The following is a discussion of our financial condition and results of operations for the three and six months ended June 30, 2018 and 2017. The comparability of our results of operations for the three and six months ended June 30, 2018 and 2017 was affected by:

changes in general and administrative expenses as a result of legal and professional fees incurred in connection with the restructuring process;

35


rejection of certain executory contracts as part of the Chapter 11 Cases related to the sale, marketing and transportation of natural gas in the North Louisiana region;
impact of the Chapter 11 Cases on our indebtedness, including the adjustments to the carrying value as well as the accrual of interest during the pendency of the bankruptcy proceedings;
gains from the settlement of litigation with our Appalachian joint venture partner during 2018;
fluctuations in oil and natural gas prices, which impact our oil and natural gas reserves, revenues, cash flows and net income or loss;
mark-to-market gains and losses from our derivative financial instruments, including gains on the 2017 Warrants due to a decrease in EXCO’s share price;
changes in proved reserves and production volumes and their impact on depletion; and
the impact of development activities on our oil and natural gas production.

The availability of a ready market and the prices for oil and natural gas are dependent upon a number of factors that are beyond our control. These factors include, among other things:

supply and demand for oil and natural gas and expectations regarding supply and demand;
the level of domestic and international production;
the availability of imported oil and natural gas;
federal regulations applicable to the export of, and construction of export facilities for, natural gas;
political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
the cost and availability of transportation and pipeline systems with adequate capacity;
the cost and availability of other competitive fuels;
fluctuating and seasonal demand for oil, natural gas and refined products;
concerns about global warming or other conservation initiatives and the extent of governmental price controls and regulation of production;
regional price differentials and quality differentials of oil and natural gas;
the availability of refining capacity;
technological advances affecting oil and natural gas production and consumption;
weather conditions and natural disasters;
foreign and domestic government relations; and
overall domestic and global economic conditions.

Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of oil and natural gas from any producing well in which we have or may acquire an interest.

Oil and natural gas production, revenues and prices

The following table presents our production, revenue and average sales prices for the three and six months ended June 30, 2018 and 2017:
 
 
Three Months Ended June 30,
 
 
 
 
 
 
 
 
2018
 
2017
 
Quarter to quarter change
(dollars in thousands, except per unit rate)
 
Production (Mmcfe)
 
Revenue
 
$/Mcfe
 
Production (Mmcfe)
 
Revenue
 
$/Mcfe
 
Production (Mmcfe)
 
Revenue
 
$/Mcfe
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 
19,546

 
$
51,185

 
$
2.62

 
11,958

 
$
31,633

 
$
2.65

 
7,588

 
$
19,552

 
$
(0.03
)
East Texas
 
2,804

 
7,274

 
2.59

 
4,231

 
12,327

 
2.91

 
(1,427
)
 
(5,053
)
 
(0.32
)
South Texas
 
2,123

 
24,248

 
11.42

 
2,022

 
14,183

 
7.01

 
101

 
10,065

 
4.41

Appalachia and other
 
5,131

 
10,069

 
1.96

 
2,670

 
6,344

 
2.38

 
2,461

 
3,725

 
(0.42
)
Total
 
29,604

 
$
92,776

 
$
3.13

 
20,881

 
$
64,487

 
$
3.09

 
8,723

 
$
28,289

 
$
0.04


36


 
 
Six Months Ended June 30,
 
 
 
 
 
 
 
 
2018
 
2017
 
Period to period change
(dollars in thousands, except per unit rate)
 
Production (Mmcfe)
 
Revenue
 
$/Mcfe
 
Production (Mmcfe)
 
Revenue
 
$/Mcfe
 
Production (Mmcfe)
 
Revenue
 
$/Mcfe
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 
37,118

 
$
103,398

 
$
2.79

 
23,996

 
$
64,807

 
$
2.70

 
13,122

 
$
38,591

 
$
0.09

East Texas
 
5,809

 
16,322

 
2.81

 
9,016

 
26,362

 
2.92

 
(3,207
)
 
(10,040
)
 
(0.11
)
South Texas
 
3,692

 
40,380

 
10.94

 
4,188

 
29,524

 
7.05

 
(496
)
 
10,856

 
3.89

Appalachia and other
 
8,363

 
17,822

 
2.13

 
5,390

 
13,150

 
2.44

 
2,973

 
4,672

 
(0.31
)
Total
 
54,982

 
$
177,922

 
$
3.24

 
42,590

 
$
133,843

 
$
3.14

 
12,392

 
$
44,079

 
$
0.10


Production for the three and six months ended June 30, 2018 increased by 8.7 Bcfe, or 41.8%, and 12.4 Bcfe, or 29.1%, as compared to the same period in 2017. Significant components of the changes in production were a result of:

Increased production of 7.6 Bcfe and 13.1 Bcfe for the three and six months ended June 30, 2018, respectively, in the North Louisiana region, primarily due to 11 gross (6.7 net) operated wells turned-to-sales in the first quarter of 2018. There were no operated wells turned-to-sales in the first quarter of 2017 and 4 gross (3.5 net) operated wells turned-to-sales in second quarter of 2017.
Decreased production of 1.4 Bcfe and 3.2 Bcfe for the three and six months ended June 30, 2018, respectively, in the East Texas region, primarily due to natural production declines as we have not turned an operated well to sales in the region since the first quarter of 2016.
Increased production of 0.1 Bcfe for the three months ended June 30, 2018 and decreased production of 0.5 Bcfe for the six months ended June 30, 2018 in the South Texas region, primarily due to production declines offset by 9 gross (8.6 net) operated wells turned-to-sales in the first half of 2018. Prior to the first quarter of 2018, the most recent operated well turned-to-sales in this region was in the fourth quarter of 2015.
Increased production of 2.5 Bcfe and 3.0 Bcfe for the three and six months ended June 30, 2018, respectively, in the Appalachia region, primarily due to the acquisition of additional interests in the Appalachia JV Settlement and 1 gross (0.9 net) operated well turned-to-sales in the first quarter of 2018. The last well that turned to sales in the Appalachia region prior to the first quarter of 2018 was in late 2015.
Oil and natural gas revenues for the three months ended June 30, 2018 increased by $28.3 million, or 43.9%, as compared to the same period in 2017. The increase in revenues was primarily due to an increase in production and higher oil prices, partially offset by lower natural gas prices. Our average natural gas sales price decreased 5.3% to $2.49 per Mcf for the three months ended June 30, 2018 from $2.63 per Mcf for the three months ended June 30, 2017, primarily due to lower market prices partially offset by improved natural gas differentials as a result of the rejection of certain executory contracts for the sale and marketing of natural gas in the North Louisiana region. Our average oil sales price per Bbl increased 44.7% to $68.30 per Bbl for the three months ended June 30, 2018 from $47.21 per Bbl for the three months ended June 30, 2017, primarily due to higher market prices.

Oil and natural gas revenues for the six months ended June 30, 2018 increased by $44.1 million, or 32.9%, as compared to the same period in 2017. The increase in revenues was primarily the result of an increase in oil prices and net increase in production. Our average natural gas sales price increased 0.8% to $2.68 per Mcf for the six months ended June 30, 2018 from $2.66 per Mcf for the six months ended June 30, 2017, primarily due to improved natural gas price differentials as a result of the rejection of certain executory contracts for the sale and marketing of natural gas in the North Louisiana region. Our average sales price of oil per Bbl increased 38.0% to $66.36 per Bbl for the six months ended June 30, 2018 from $48.10 per Bbl for the six months ended June 30, 2017, primarily due to higher market prices.

Purchased natural gas and marketing revenues

Purchased natural gas and marketing revenues include revenues we receive as a result of selling natural gas purchased from third parties and marketing fees we receive from third parties. Purchased natural gas and marketing revenues for the three months ended June 30, 2018 decreased by $1.2 million, or 18.0%, as compared to the same period in 2017. Purchased natural gas and marketing revenues for the six months ended June 30, 2018 decreased by $3.0 million, or 22.1%, as compared to the same period in 2017. The decrease for the three and six months ended June 30, 2018 was primarily due to lower marketing fees charged to third parties and lower volumes purchased. The decrease in marketing fees charged to third parties was primarily due to an increase in our average working interests in production from operated wells compared to the same period in prior year.


37


Oil and natural gas operating costs

The following tables present our oil and natural gas operating costs for the three and six months ended June 30, 2018 and 2017:
 
 
Three Months Ended June 30,
 
 
 
 
 
 
 
 
2018
 
2017
 
Quarter to quarter change
(in thousands)
 
Lease operating expenses
 
Workovers and other
 
Total
 
Lease operating expenses
 
Workovers and other
 
Total
 
Lease operating expenses
 
Workovers and other
 
Total
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 
$
4,939

 
$
65

 
$
5,004

 
$
3,389

 
$
74

 
$
3,463

 
$
1,550

 
$
(9
)
 
$
1,541

East Texas
 
932

 
540

 
1,472

 
1,207

 
225

 
1,432

 
(275
)
 
315

 
40

South Texas
 
3,101

 
4

 
3,105

 
2,885

 

 
2,885

 
216

 
4

 
220

Appalachia and other
 
1,115

 
178

 
1,293

 
427

 
8

 
435

 
688

 
170

 
858

Total
 
$
10,087

 
$
787

 
$
10,874

 
$
7,908

 
$
307

 
$
8,215

 
$
2,179

 
$
480

 
$
2,659

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30,
 
 
 
 
 
 
 
 
2018
 
2017
 
Quarter to quarter change
(per Mcfe)
 
Lease operating expenses
 
Workovers and other
 
Total
 
Lease operating expenses
 
Workovers and other
 
Total
 
Lease operating expenses
 
Workovers and other
 
Total
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 
$
0.25

 
$

 
$
0.25

 
$
0.28

 
$
0.01

 
$
0.29

 
$
(0.03
)
 
$
(0.01
)
 
$
(0.04
)
East Texas
 
0.33

 
0.19

 
0.52

 
0.29

 
0.05

 
0.34

 
0.04

 
0.14

 
0.18

South Texas
 
1.46

 

 
1.46

 
1.43

 

 
1.43

 
0.03

 

 
0.03

Appalachia and other
 
0.22

 
0.03

 
0.25

 
0.16

 

 
0.16

 
0.06

 
0.03

 
0.09

Total
 
$
0.34

 
$
0.03

 
$
0.37

 
$
0.38

 
$
0.01

 
$
0.39

 
$
(0.04
)
 
$
0.02

 
$
(0.02
)

 
 
Six Months Ended June 30,
 
 
 
 
 
 
 
 
2018
 
2017
 
Period to period change
(in thousands)
 
Lease operating expenses
 
Workovers and other
 
Total
 
Lease operating expenses
 
Workovers and other
 
Total
 
Lease operating expenses
 
Workovers and other
 
Total
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 
$
8,607

 
$
225

 
$
8,832

 
$
6,418

 
$
416

 
$
6,834

 
$
2,189

 
$
(191
)
 
$
1,998

East Texas
 
1,852

 
650

 
2,502

 
2,427

 
797

 
3,224

 
(575
)
 
(147
)
 
(722
)
South Texas
 
5,470

 
71

 
5,541

 
5,749

 
2

 
5,751

 
(279
)
 
69

 
(210
)
Appalachia and other
 
1,676

 
231

 
1,907

 
896

 
8

 
904

 
780

 
223

 
1,003

Total
 
$
17,605

 
$
1,177

 
$
18,782

 
$
15,490

 
$
1,223

 
$
16,713

 
$
2,115

 
$
(46
)
 
$
2,069

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30,
 
 
 
 
 
 
 
 
2018
 
2017
 
Period to period change
(per Mcfe)
 
Lease operating expenses
 
Workovers and other
 
Total
 
Lease operating expenses
 
Workovers and other
 
Total
 
Lease operating expenses
 
Workovers and other
 
Total
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 
$
0.23

 
$
0.01

 
$
0.24

 
$
0.27

 
$
0.02

 
$
0.29

 
$
(0.04
)
 
$
(0.01
)
 
$
(0.05
)
East Texas
 
0.32

 
0.11

 
0.43

 
0.27

 
0.09

 
0.36

 
0.05

 
0.02

 
0.07

South Texas
 
1.48

 
0.02

 
1.50

 
1.37

 

 
1.37

 
0.11

 
0.02

 
0.13

Appalachia and other
 
0.20

 
0.03

 
0.23

 
0.17

 

 
0.17

 
0.03

 
0.03

 
0.06

Total
 
$
0.32

 
$
0.02

 
$
0.34

 
$
0.36

 
$
0.03

 
$
0.39

 
$
(0.04
)
 
$
(0.01
)
 
$
(0.05
)

Oil and natural gas operating costs for the three and six months ended June 30, 2018 increased by $2.7 million and $2.1 million, or 32.4% and 12.4%, respectively as compared to the same period in 2017, primarily due to higher variable costs as a

38


result of increased production and the acquisition of Shell’s interests in the Appalachia JV Settlement. Oil and natural gas operating costs decreased from $0.39 per Mcfe for the three months ended June 30, 2017 to $0.37 per Mcfe for the three months ended June 30, 2018. Oil and natural gas operating costs decreased from $0.39 per Mcfe for the six months ended June 30, 2017 to $0.34 per Mcfe for the six months ended June 30, 2018. The decrease on a per Mcfe basis was primarily due to increased production in relation to certain fixed oil and natural gas operating costs.

Production and ad valorem taxes

The following table presents our production and ad valorem taxes on a percentage of revenue basis and per Mcfe basis for the three and six months ended June 30, 2018 and 2017:

 
 
Three Months Ended June 30,
 
 
2018
 
2017
(in thousands, except per unit rate)
 
Production and ad valorem taxes
 
% of revenue
 
Taxes $/Mcfe
 
Production and ad valorem taxes
 
% of revenue
 
Taxes $/Mcfe
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 
$
1,707

 
3.3
%
 
$
0.09

 
$
1,666

 
5.3
%
 
$
0.14

East Texas
 
240

 
3.3
%
 
0.09

 
293

 
2.4
%
 
0.07

South Texas
 
1,712

 
7.1
%
 
0.81

 
1,303

 
9.2
%
 
0.64

Appalachia and other
 
422

 
4.2
%
 
0.08

 
153

 
2.4
%
 
0.06

Total
 
$
4,081

 
4.4
%
 
$
0.14

 
$
3,415

 
5.3
%
 
$
0.16


 
 
Six Months Ended June 30,
 
 
2018
 
2017
(in thousands, except per unit rate)
 
Production and ad valorem taxes
 
% of revenue
 
Taxes $/Mcfe
 
Production and ad valorem taxes
 
% of revenue
 
Taxes $/Mcfe
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 
$
3,442

 
3.3
%
 
$
0.09

 
$
3,258

 
5.0
%
 
$
0.14

East Texas
 
568

 
3.5
%
 
0.10

 
625

 
2.4
%
 
0.07

South Texas
 
2,900

 
7.2
%
 
0.79

 
2,698

 
9.1
%
 
0.64

Appalachia and other
 
1,167

 
6.5
%
 
0.14

 
269

 
2.0
%
 
0.05

Total
 
$
8,077

 
4.5
%
 
$
0.15

 
$
6,850

 
5.1
%
 
$
0.16


Production and ad valorem taxes for the three and six months ended June 30, 2018 increased by $0.7 million and $1.2 million or 19.5% and 17.9%, respectively, as compared to the same period in 2017. The increase was primarily due to an increase in oil prices of 44.7% and 38.0%, respectively, for the three and six months ended June 30, 2018. The increase in oil prices primarily impacted properties located in our South Texas region because production taxes are based on a fixed percentage of gross value of production sold. In addition, we incurred higher assessments for the impact fee required to be paid to the Commonwealth of Pennsylvania. The increase in the impact fee was primarily due to higher natural gas market prices and the additional interests in oil and natural gas properties acquired as a result of the Appalachia JV Settlement.

Gathering and transportation

Gathering and transportation expenses for the three months ended June 30, 2018 decreased by $5.8 million, or 21.3%, as compared to the same period in 2017. Gathering and transportation expenses for the six months ended June 30, 2018 decreased by $13.2 million, or 24.2%, as compared to the same period in 2017. Gathering and transportation expenses were $0.72 per Mcfe for the three months ended June 30, 2018 as compared to $1.30 per Mcfe for the same period in 2017. Gathering and transportation expenses were $0.75 per Mcfe for the six months ended June 30, 2018 as compared to $1.28 per Mcfe for the same period in 2017. The decreases were primarily due to the impact of the rejection of executory contracts for the transportation of natural gas in the North Louisiana region that occurred in the first quarter of 2018.

Purchased natural gas expenses

Purchased natural gas expenses are purchases of natural gas from third parties plus the related costs of transportation. Purchased natural gas expenses for the three and six months ended June 30, 2018 decreased by $2.6 million and $4.9 million or

39


41.1% and 38.6%, respectively, as compared to the same period in 2017. The decrease was primarily due to lower volumes purchased, lower market prices for natural gas, and lower transportation costs as a result of the rejection of executory contracts for the transportation of natural gas in the North Louisiana region.

Depletion, depreciation and amortization
Depletion, depreciation and amortization for the three and six months ended June 30, 2018 increased from the same period in 2017 primarily due to an increase in depletion expense of $10.3 million and $17.0 million, or 90.5% and 75.6%, respectively. The increase in depletion expense was primarily due to an increase in production and higher depletion rate. On a per Mcfe basis, the depletion rate for the three months ended June 30, 2018 was $0.73 per Mcfe, compared to $0.54 per Mcfe in the same period in 2017. The depletion rate for the six months ended June 30, 2018 was $0.72 per Mcfe, compared to $0.53 per Mcfe in the same period in 2017. The increase in the depletion rate was primarily due to the additional costs associated with our development of the South Texas and North Louisiana regions.

Impairment of oil and natural gas properties

We did not record an impairment to our oil and natural gas properties for the three and six months ended June 30, 2018 and 2017. The possibility and amount of any future impairment is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

General and administrative

The following table presents our general and administrative expenses for the three and six months ended June 30, 2018 and 2017:
 
 
Three Months Ended June 30,
 
 
 
Six Months Ended June 30,
 
 
(in thousands)
 
2018
 
2017
 
Quarter to quarter change
 
2018
 
2017
 
Period to period change
General and administrative expenses:
 
 
 
 
 
 
 
 
 
 
 
 
Gross general and administrative expenses
 
$
10,936

 
$
12,489

 
$
(1,553
)
 
$
24,940

 
$
24,786

 
$
154

Technical services and service agreement charges
 
(860
)
 
(1,504
)
 
644

 
(2,423
)
 
(2,898
)
 
475

Operator overhead reimbursements
 
(3,459
)
 
(3,697
)
 
238

 
(7,033
)
 
(7,078
)
 
45

Capitalized salaries
 
(787
)
 
(723
)
 
(64
)
 
(1,575
)
 
(1,448
)
 
(127
)
General and administrative expenses, excluding equity-based compensation
 
5,830

 
6,565

 
(735
)
 
13,909

 
13,362

 
547

Gross equity-based compensation
 
610

 
(7,622
)
 
8,232

 
1,205

 
(9,648
)
 
10,853

Capitalized equity-based compensation
 
(137
)
 
(337
)
 
200

 
(284
)
 
(693
)
 
409

General and administrative expenses
 
$
6,303

 
$
(1,394
)
 
$
7,697

 
$
14,830

 
$
3,021

 
$
11,809


General and administrative expenses for the three months ended June 30, 2018 increased by $7.7 million compared to the same period in 2017. General and administrative expenses for the six months ended June 30, 2018 increased by $11.8 million compared to the same period in 2017. Significant components of the changes in general and administrative expenses were a result of:

Higher equity-based compensation of $8.4 million and $11.3 million for the three and six months ended June 30, 2018, primarily due to income in prior year of $9.3 million and $13.7 million, respectively, related to a significant decline in the fair value of the warrants issued to Energy Strategic Advisory Services LLC (“ESAS”). This was partially offset by a decrease in equity-based compensation of $0.9 million and $2.3 million for the three and six months ended June 30, 2018, respectively, due to the discontinuation of grants of share-based compensation to employees and lower employee headcount.

40


Increased personnel costs of $1.6 million and $3.6 million for the three and six months ended June 30, 2018, respectively. The increase was primarily due to higher bonus expense during the current year, partially offset by lower headcount. The increase in bonus expense was due to the adoption of new cash-based retention and incentive plans in connection with our restructuring activities. The cash-based retention and incentive plans are intended to replace grants under the equity-based incentive plans. As a result, cash-based personnel costs increased and equity-based compensation expense decreased.
Decreased consulting and contract labor costs of $0.8 million and $1.6 million for the three and six months ended June 30, 2018, respectively, primarily due to the suspension of the services and investment agreement with ESAS that was effective November 9, 2017.
Decreased legal and professional fees of $1.8 million and $0.5 million for the three and six months ended June 30, 2018, respectively. Any legal and professional fees incurred subsequent to the Petition Date are classified as “Reorganization items, net” on the Condensed Consolidated Statement of Operations.
Decreased overhead reimbursement, technical services and service agreement charges of $0.9 million and $0.5 million for the three and six months ended June 30, 2018, respectively. The decreases are primarily a result of lower recoveries from third-parties due to the acquisition of our joint venture partner’s interests in the Appalachia JV Settlement.
Decreased various other gross general and administrative expenses of $0.6 million and $1.4 million for the three and six months ended June 30, 2018, respectively. These decreases reflect our continued efforts to reduce our general and administrative costs.

Interest expense, net

Interest expense, net for the three and six months ended June 30, 2018 decreased $14.7 million and $25.4 million, respectively, from the same periods in 2017. The decreases were primarily due to the suspension of interest accrued on certain instruments subsequent to the Petition Date. As a result of the bankruptcy proceedings, the Court limited post-petition interest on certain indebtedness that may be under-secured or unsecured. On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. We continued to accrue and pay interest on the DIP Credit Agreement and the 1.5 Lien Notes subsequent to the Petition Date. We accrued interest on 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes through the Petition Date with no interest accrued subsequent to the Petition Date. See “Note 8. Debt” in the Notes to our Condensed Consolidated Financial Statements for additional information.

Gain (loss) on derivative financial instruments - commodity derivatives

Our oil and natural gas derivative financial instruments resulted in a net gain of $6.5 million for the three months ended June 30, 2017. Our oil and natural gas derivative financial instruments resulted in a net loss of $0.6 million and a net gain of $22.1 million for the six months ended June 30, 2018 and 2017, respectively. In January 2018, the counterparty to our remaining open swap contracts early terminated the outstanding contracts effective January 31, 2018. As a result, we did not have any outstanding oil and natural gas derivative financial instruments subsequent to the termination of these contracts.


41


The following table presents our oil and natural gas prices, before and after the impact of the cash settlement of our commodity derivatives:
 
 
Three Months Ended June 30,
 
 
 
Six Months Ended June 30,
 
 
Average realized pricing:
 
2018
 
2017
 
Quarter to quarter change
 
2018
 
2017
 
Period to period change
Natural gas (per Mcf):
 
 
 
 
 
 
 
 
 
 
 
 
Net price, excluding derivatives
 
$
2.49

 
$
2.63

 
$
(0.14
)
 
$
2.68

 
$
2.66

 
$
0.02

Cash receipts (payments) on derivatives
 

 
(0.06
)
 
0.06

 
0.01

 
(0.14
)
 
0.15

Net price, including derivatives
 
$
2.49

 
$
2.57

 
$
(0.08
)
 
$
2.69

 
$
2.52

 
$
0.17

Oil (per Bbl):
 
 
 
 
 
 
 
 
 
 
 
 
Net price, excluding derivatives
 
$
68.30

 
$
47.21

 
$
21.09

 
$
66.36

 
$
48.10

 
$
18.26

Cash receipts (payments) on derivatives
 

 
0.26

 
(0.26
)
 

 
(0.01
)
 
0.01

Net price, including derivatives
 
$
68.30

 
$
47.47

 
$
20.83

 
$
66.36

 
$
48.09

 
$
18.27

Natural gas equivalent (per Mcfe):
 
 
 
 
 
 
 
 
 
 
 
 
Net price, excluding derivatives
 
$
3.13

 
$
3.09

 
$
0.04

 
$
3.24

 
$
3.14

 
$
0.10

Cash receipts (payments) on derivatives
 

 
(0.05
)
 
0.05

 
0.01

 
(0.13
)
 
0.14

Net price, including derivatives
 
$
3.13

 
$
3.04

 
$
0.09

 
$
3.25

 
$
3.01

 
$
0.24


Our total cash payments for the three months ended June 30, 2017 were $1.1 million, or $0.05 per Mcfe. Our total cash receipts for the six months ended June 30, 2018 were $0.5 million, or $0.01 per Mcfe, compared to cash payments of $5.6 million, or $0.13 per Mcfe, for the six months ended June 30, 2017.

Gain on derivative financial instruments - common share warrants

Pursuant to FASB ASC Topic 815, Derivatives and Hedging, (“ASC 815”), we account for the 2017 Warrants as derivative financial instruments and carry the warrants as a non-current liability at their fair value, with the increase or decrease in fair value being recognized in earnings. These warrants are measured at fair value on a recurring basis until the date of exercise or the date of expiration. On January 16, 2018, affiliates of Fairfax surrendered all of their rights to the 2017 Warrants, which had entitled them rights to purchase in aggregate up to 10,824,376 common shares at $13.95 per share and 1,725,576 common shares at $0.01 per share. During the three and six months ended June 30, 2018, we recorded gains of $1.5 million and $1.7 million, respectively, primarily due to the cancellation of warrants by Fairfax and a decrease in EXCO’s share price. During the three and six months ended June 30, 2017, we recorded a gains of $122.3 million and $128.3 million, respectively, primarily due to a decrease in EXCO’s share price.

Reorganization items, net

Pursuant to ASC 852, any costs directly related to an entity’s bankruptcy proceedings are presented separately as reorganization items. We recorded a net loss on reorganization items of $16.4 million for the three months ended June 30, 2018 primarily due to legal and professional fees related to the bankruptcy proceedings. We recorded a net loss on reorganization items of $369.3 million for the six months ended June 30, 2018 primarily due to the rejection of executory contracts of $309.2 million; legal and professional fees of $29.6 million and the acceleration of deferred financing costs, debt discounts and deferred reductions in carrying value of debt instruments of $30.5 million. The losses associated with the rejection of executory contracts and adjustments to the carrying value of debt instruments are based on our current estimate of the allowable claims and may differ from actual claims or future settlement amounts paid. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material. See “Note 1. Organization and basis of presentation” in the Notes to our Condensed Consolidated Financial Statements for additional information.

Loss on restructuring and extinguishment of debt

For the three and six months ended June 30, 2017, we recorded a loss on restructuring of debt of $6.4 million related to the transaction costs associated with the exchange of Second Lien Term Loans for 1.75 Lien Term Loans.


42


Equity income

Equity income (loss) was net income of $0.3 million for the three months ended June 30, 2017. Equity income was $0.2 million and $0.7 million for the six months ended June 30, 2018 and 2017, respectively. We acquired the remaining ownership interests in OPCO and Appalachia Midstream as a result of the Appalachia JV Settlement on February 27, 2018. Prior to the settlement, we accounted for our ownership interests in OPCO and Appalachia Midstream as equity method investments. As a result of the settlement, OPCO and Appalachia Midstream are wholly owned subsidiaries and are consolidated within our financial results.

Income taxes

During the three months ended June 30, 2018, we did not recognize any income tax expense. During the three months ended June 30, 2017, we recognized income tax expense of $1.0 million. During the six months ended June 30, 2018 and 2017, we recognized an income tax benefit of $4.5 million and income tax expense of $2.1 million, respectively. The following table presents our income tax benefit and expense for the three and six months ended June 30, 2018 and 2017:
 
 
Three Months Ended June 30,
 
 
 
Six Months Ended June 30,
 
 
(in thousands)
 
2018
 
2017
 
Quarter to quarter 
change
 
2018
 
2017
 
Period to period change
Income tax (benefit) expense:
 
 
 
 
 
 
 
 
 
 
 
 
Current income tax (benefit) expense
 
$

 
$

 
$

 
$

 
$

 
$

Deferred income tax (benefit) expense
 

 
1,027

 
(1,027
)
 
(4,518
)
 
2,055

 
(6,573
)
Total income tax (benefit) expense
 
$

 
$
1,027

 
$
(1,027
)
 
$
(4,518
)
 
$
2,055

 
$
(6,573
)

Deferred income tax benefit during the six months ended June 30, 2018 related to changes in a deferred tax liability for tax-deductible goodwill. As of December 31, 2017, we recognized a deferred tax liability of $4.5 million for tax-deductible goodwill. The deferred tax liability related to goodwill was considered to have an indefinite life based on the nature of the underlying asset and could not be offset under GAAP with a deferred tax asset with a definite life, such as net operating loss carryforwards (“NOLs”). As a result of the Tax Cuts and Jobs Act (“Tax Act”), deferred tax assets resulting from NOLs generated in taxable years subsequent to December 31, 2017 are considered to have an indefinite life. Therefore, we recognized an income tax benefit of $4.5 million during the three months ended March 31, 2018 because we expect to be able to utilize deferred tax assets related to NOLs to offset the deferred tax liability related to goodwill. We recognized deferred income tax expense of $1.0 million and $2.1 million during the three and six months ended June 30, 2017, respectively, for changes in the deferred tax liability related to tax-deductible goodwill with an indefinite life that could not be offset by NOLs that were considered to have a definite life prior to the enactment of the Tax Act.

Our net deferred tax assets have been fully reserved with valuation allowances. Our accumulated valuation allowance as of June 30, 2018 was approximately $883.6 million and has fully offset our net deferred tax assets. We will continue to recognize deferred tax valuation allowances until the realization of deferred benefits becomes more-likely-than-not.

The effective income tax rates, excluding the impact of the valuation allowances, would have been 41.5% and 21.5% for the three and six months ended June 30, 2018, respectively, and 78.6% and 76.0% for the three and six months ended June 30, 2017, respectively. The effective tax rates, excluding the impact of the valuation allowance, differ from the statutory tax rates primarily due to permanent differences between the amounts recorded for financial reporting purposes and the amounts used for income tax purposes. The lower effective tax rate for the three and six months ended June 30, 2018 was primarily due to the lower enacted tax rate under the Tax Act.

Our Liquidity, capital resources and capital commitments
Overview

Our primary sources of capital resources and Liquidity (defined as cash and restricted cash plus the unused borrowing base under the DIP Credit Agreement) have historically consisted of internally generated cash flows from operations, borrowings under certain credit agreements, issuances of debt securities, dispositions of non-strategic assets, joint ventures and the capital markets when conditions are favorable. Our ability to issue additional indebtedness, dispose assets, enter into joint ventures or access the capital markets may be substantially limited or nonexistent during our Chapter 11 proceedings and will require court approval in most instances. Accordingly, our Liquidity will depend mainly on cash generated from operating

43


activities and available funds under the DIP Credit Agreement. Factors that could impact our Liquidity, capital resources and capital commitments include the following:

the outcome of potential strategic alternatives to maximize value for the benefit of our stakeholders as part of the Chapter 11 process, which may include a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certain indebtedness, or a combination thereof;
significant costs associated with the bankruptcy process, including our ability to limit these costs by obtaining confirmation of a successful plan of reorganization in a timely manner;
decisions from the Court related to requirements to pay interest on certain debt instruments during the bankruptcy process;
decisions from the Court related to the rejection of certain executory contracts;
our ability to maintain compliance with debt covenants under the DIP Credit Agreement;
reductions to our borrowing base under the DIP Credit Agreement, which may begin on January 1, 2019 or later if the maturity of the DIP Credit Agreement is extended;
our ability to fund, finance or repay indebtedness, including our ability to restructure our indebtedness during the Chapter 11 Cases;
limitations on our ability to incur certain types of indebtedness in accordance with our debt agreements;
requirements to provide certain vendors and other parties with letters of credit or cash deposits as a result of our credit quality, which reduce the amount of available borrowings under the DIP Credit Agreement;
the level of planned drilling activities;
the results of our ongoing drilling programs;
potential acquisitions and/or dispositions of oil and natural gas properties or other assets;
the integration of acquisitions of oil and natural gas properties or other assets;
our ability to effectively manage operating, general and administrative expenses and capital expenditure programs, specifically related to pricing pressures from key vendors utilized in our drilling, completion and operating activities;
reduced oil and natural gas revenues resulting from, among other things, depressed oil and natural gas prices and lower production from reductions in our drilling and development activities;
our ability to mitigate commodity price volatility with commodity derivative financial instruments; and
the potential outcome of litigation.

Recent events affecting Liquidity
On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. On January 22, 2018, we closed the DIP Credit Agreement, which includes an initial borrowing base of $250.0 million. Proceeds from the DIP Credit Agreement were used to repay all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 process. We have limited our 2018 capital budget to $140.0 million in order to preserve our Liquidity during the pendency of the bankruptcy process. Our Liquidity was $147.6 million as of June 30, 2018. We believe our cash flow from operations, borrowing capacity under the DIP Credit Agreement and cash on hand will provide sufficient Liquidity during the bankruptcy process. We expect to incur significant costs associated with the bankruptcy process, including legal, financial and restructuring advisors to the Company and certain of our creditors. Additionally, the DIP Credit Agreement matures on January 22, 2019 unless we are able to extend the maturity by obtaining a waiver or consent from the DIP Lenders. Therefore, our ability to obtain confirmation of a successful plan of reorganization in a timely manner is critical to ensuring our Liquidity is sufficient during the bankruptcy process.

44


The following table presents our Liquidity and outstanding principal balances of our debt as of June 30, 2018:
(in thousands)
 
June 30, 2018
DIP Credit Agreement
 
$
156,406

1.5 Lien Notes
 
316,958

1.75 Lien Term Loans
 
708,926

Second Lien Term Loans
 
17,246

2018 Notes
 
131,576

2022 Notes
 
70,169

Total debt
 
$
1,401,281

Net debt
 
$
1,335,302

Borrowing base
 
$
250,000

Unused borrowing base (1)
 
$
81,600

Cash (2)
 
$
65,979

Unused borrowing base plus cash
 
$
147,579


(1)
Net of $12.0 million in letters of credit at June 30, 2018.
(2)
Includes restricted cash of $11.0 million at June 30, 2018.
As of the Petition Date, we had approximately $1.4 billion in principal amount of indebtedness. The filing of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the following debt instruments: (i) EXCO Resources Credit Agreement; (ii) 1.5 Lien Notes; (iii) 1.75 Lien Term Loans; (iv) 2018 Notes; and (v) 2022 Notes. These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. In addition, we were in default under the Second Lien Term Loans as a result of our failure to make interest payments. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code. Proceeds from the DIP Credit Agreement were used to repay all obligations under the EXCO Resources Credit Agreement and the EXCO Resources Credit Agreement was terminated. On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes.
The DIP Credit Agreement contains certain financial covenants, including, but not limited to:

our cash (as defined in the DIP Credit Agreement) plus unused commitments under the DIP Credit Agreement cannot be less than $20.0 million (“Minimum Liquidity Test”); and
aggregate disbursements cannot exceed 120% of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) set forth in the 13-week forecasts provided to the administrative agent of the DIP Credit Agreement. The testing period is based on the immediately preceding four-week period and is measured every two weeks. The 13-week forecast is provided to the administrative agent on a monthly basis and shall be consistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to the administrative agent of the DIP Credit Agreement.
As of June 30, 2018, we were in compliance with all of the covenants under the DIP Credit Agreement. The DIP Credit Agreement contains events of default, including: (i) conversion of the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code and (ii) appointment of a trustee, examiner or receiver in the Chapter 11 Cases. The DIP Credit Agreement will mature on the earliest of (a) 12 months from the initial borrowings on January 22, 2018, (b) the effective date of a plan of reorganization in the Chapter 11 Cases and (c) the date of termination of all revolving commitments and/or the acceleration of the obligations under the DIP Facilities following an event of default. The DIP Credit Agreement provided us with an option to extend the maturity of the DIP Facilities to the date that is 18 months from the initial borrowing date if certain conditions are met. These conditions included a requirement to file a plan of reorganization with the Court no later than July 1, 2018. We did not file a plan of reorganization with the Court prior to July 1, 2018; therefore, an extension of the DIP Facilities beyond the original maturity date would require a waiver or consent from the DIP Lenders. See further discussion of the DIP Credit Agreement in “Note 8. Debt” in the Notes to our Condensed Consolidated Financial Statements.

45


Capital expenditures
Our 2018 capital budget of $140.0 million is focused primarily on the development of the Haynesville and Eagle Ford shales. During 2018, we revised our original capital budget for 2018 to reflect the impact of non-consent elections by partners in certain of our operated wells and drill additional wells in South Texas with attractive rates of return. The development of the Haynesville shale in North Louisiana includes drilling 1 gross (0.7 net) operated well and completing 11 gross (6.7 net) operated wells. The completion activities in North Louisiana primarily include wells drilled in prior year. Our development program for the Eagle Ford shale includes drilling 13 gross (10.9 net) operated wells and completing 15 gross (12.5 net) operated wells that will preserve the value of certain acreage with leasehold obligations and provide attractive rates of return. Our drilling and completion activities include $21.0 million to participate in the development of non-operated wells. In addition, we plan to spend a limited amount of capital on maintenance and leasehold costs.
For the six months ended June 30, 2018, our capital expenditures totaled $98.7 million, of which $93.9 million was primarily related to development capital expenditures. Our development activities in North Louisiana included drilling 1 gross (0.7 net) operated well and completing 11 gross (6.7 net) operated wells in the Haynesville shale. The forecasted development activities for 2018 in North Louisiana were substantially complete as of the end of the first quarter of 2018. Our development activities in South Texas included drilling 8 gross (8.0 net) operated wells and completing 9 gross (8.6 net) operated wells in the Eagle Ford shale. We expect to complete the forecasted development activities for 2018 in South Texas in the fourth quarter of 2018. In addition, we turned-to-sales 1 gross (0.9 net) operated Marcellus shale well in Northeast Pennsylvania that was previously awaiting the connection of a pipeline.
The following table presents our capital expenditures for the six months ended June 30, 2018 and our budgeted capital expenditures for the remainder of 2018:
 
 
Six Months Ended June 30, 2018
 
July - December Forecast
 
2018
(in thousands)
 
 
2018
 
Capital Budget
Capital expenditures:
 
 
 
 
 
 
Lease purchases and seismic
 
$
484

 
$
2,516

 
$
3,000

Development capital expenditures
 
93,854

 
34,146

 
128,000

Field operations, gathering and water pipelines
 
140

 
3,860

 
4,000

Corporate and other
 
4,216

 
784

 
5,000

Total
 
$
98,694

 
$
41,306

 
$
140,000


Historical sources and uses of funds
Net increases (decreases) in cash are summarized as follows:
 
 
Six Months Ended June 30,
(in thousands)
 
2018
 
2017
Net cash provided by operating activities
 
$
69,496

 
$
33,601

Net cash used in investing activities
 
(82,328
)
 
(56,469
)
Net cash provided by financing activities
 
23,943

 
33,905

Net increase in cash
 
$
11,111

 
$
11,037


Operating activities

The primary factors impacting our cash flows from operating activities include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from sales of oil and natural gas production, including settlement proceeds or payments related to our oil and natural gas derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs of our general and administrative activities and (v) interest expense. Our cash flows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes.

For the six months ended June 30, 2018, our net cash provided by operating activities was $69.5 million as compared to net cash provided by operating activities of $33.6 million for the six months ended June 30, 2017. The increase in cash provided by operating activities was primarily due to increases in revenues, reductions in operating expenses, reductions in cash interest payments and favorable changes in working capital. As a result of the bankruptcy proceedings, we experienced

46


favorable changes in working capital during the six months ended June 30, 2018 due to the deferral of payments that are subject to the approval of the Court, our creditors or confirmation of a plan of reorganization. See “Note 1. Organization and basis of presentation” in the Notes to our Condensed Consolidated Financial Statements for further discussion of the impact of the Chapter 11 Cases.

Investing activities

Our investing activities consist primarily of drilling and development expenditures, acquisitions and divestitures. For the six months ended June 30, 2018, our net cash used in investing activities was $82.3 million, which primarily consisted of development activities in the North Louisiana and South Texas regions of $98.1 million. This is partially offset by $14.8 million of cash held by OPCO and Appalachia Midstream that was acquired as a result of the Appalachia JV Settlement. For the six months ended June 30, 2017, our net cash used in investing activities was $56.5 million, which primarily consisted of development activities in the North Louisiana region.

Financing activities

For the six months ended June 30, 2018, our net cash provided by financing activities was $23.9 million. Proceeds from the DIP Credit Agreement were used to repay all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 process. In addition, we spent $6.1 million of financing costs related to issuance of the DIP Facilities. See “Note 8. Debt” in the Notes to our Condensed Consolidated Financial Statements for further discussion of the DIP Facilities.

For the six months ended June 30, 2017, our net cash provided by financing activities was $33.9 million primarily due to $295.5 million of net proceeds received from the 1.5 Lien Notes and $25.0 million in borrowings under the EXCO Resources Credit Agreement. We used the majority of the proceeds from the 1.5 Lien Notes to repay the entire outstanding balance under the EXCO Resources Credit Agreement of $253.6 million. In addition, we used cash to pay $22.0 million of costs primarily related to recent debt restructuring activities, and we made payments of $11.1 million on the Second Lien Term Loans, which reduced its carrying value.

Commodity derivative financial instruments

Our production is generally sold at prevailing market prices. Historically, we have entered into oil and natural gas derivative contracts for a portion of our production to mitigate the impact of commodity price fluctuations and achieve a more predictable cash flow associated with our operations. These transactions limit our exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase.

During the Chapter 11 Cases, our ability to enter into commodity derivative contracts covering estimated future production is limited under the DIP Credit Agreement. We are only permitted to enter into commodity derivative contracts with lenders under the DIP Credit Agreement. As a result, we may not be able to enter into commodity derivative contracts covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivative contracts in the future, we could be more affected by changes in commodity prices. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations. Our exposure to commodity price fluctuations will increase in 2018 due to lower oil and natural gas volumes covered by derivative contracts compared to historical levels.

See further details on our derivative financial instruments in “Note 7. Derivative financial instruments” and “Note 9. Fair value measurements” in the Notes to our Condensed Consolidated Financial Statements.

Off-balance sheet arrangements

As of June 30, 2018, we had no arrangements or any guarantees of off-balance sheet debt to third parties.

Contractual obligations and commercial commitments

As of December 31, 2017, our contractual obligations and commercial commitments primarily consisted of debt instruments; sales, marketing, gathering and transportation agreements; and leases of office space and certain equipment. The filing of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the following debt instruments: (i) EXCO Resources Credit Agreement; (ii) 1.5 Lien Notes; (iii) 1.75 Lien Term Loans; (iv) 2018 Notes; and (v) 2022 Notes. In addition, we were in default under the Second Lien Term Loans as a result of our failure to make interest

47


payments. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions of the Bankruptcy Code. As of the Petition Date, we adjusted the carrying value of our indebtedness to the estimated amount that will be allowed as claims in the Chapter 11 Cases. On January 22, 2018, proceeds from the DIP Credit Agreement were used to repay all obligations outstanding under the EXCO Resources Credit Agreement. On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. We accrued interest on the 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes through Petition Date, with no interest accrued subsequent to the Petition Date. The 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes have been reclassified as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheet as of June 30, 2018.

During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. The rejection of these executory contracts was treated as a breach as of the Petition Date and relieved us from performing future obligations under such contract but is expected to result in a general unsecured claim against certain of the Debtors for damages caused by such rejection. Our estimate of allowable claims related to the executory contracts approved for rejection by the Court was recorded as “Liabilities subject to compromise” on our Condensed Consolidated Balance Sheet as of June 30, 2018. See “Item 1. Legal Proceedings” for further discussion regarding the adversary proceeding related to an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure through November 30, 2018.

See further discussion of the impact of the Chapter 11 Cases on our indebtedness and the rejection of executory contracts in “Note 1. Organization and basis of presentation” in the Notes to our Condensed Consolidated Financial Statements.

Item 3.     Quantitative and Qualitative Disclosures about Market Risk

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices, and interest rates charged on borrowings and earned on cash equivalent investments. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive derivative financial instruments have historically been entered into for hedging and investment purposes, not for trading purposes.

Commodity price risk

Our most significant market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices for natural gas as well as local and regional differentials. Pricing for oil and natural gas production is volatile. We have historically entered into commodity derivative financial instruments to manage our exposure to commodity price fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our financing activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase.

During the Chapter 11 Cases, our ability to enter into commodity derivative contracts covering estimated future production is limited under the DIP Credit Agreement. We are only permitted to enter into commodity derivative contracts with lenders under the DIP Credit Agreement. As a result, we may not be able to enter into commodity derivative contracts covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivative contracts in the future, we could be more affected by changes in commodity prices. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial

48


condition and results of operations. Our exposure to commodity price fluctuations will increase in 2018 due to lower oil and natural gas volumes covered by derivative contracts compared to historical levels. For the three and six months ended June 30, 2018, a $1.00 decrease in the average commodity price per Mcfe would have resulted in a decrease in oil and natural gas revenues, excluding the impact of commodity derivative financial instruments, of approximately $29.6 million and $55.0 million, respectively.

Interest rate risk

Our exposure to interest rate changes relates primarily to borrowings under the DIP Credit Agreement. Interest is payable on borrowings under the DIP Credit Agreement based on a floating rate as more fully described in “Note 8. Debt” in the Notes to our Condensed Consolidated Financial Statements. At June 30, 2018, we had $156.4 million in borrowings outstanding under the DIP Credit Agreement. A 1.0% increase in interest rates (100 bps) based on the variable borrowings as of June 30, 2018 would result in an increase in our interest expense of approximately $1.6 million per year. The interest rate we pay on these borrowings is set periodically based upon market rates. The interest rates on the 1.5 Lien Notes, 1.75 Lien Term Loans, Second Lien Terms Loans, 2018 Notes, and 2022 Notes are fixed and not subject to change based on fluctuations in interest rates.

Item 4.     Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, EXCO’s management has evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that EXCO’s disclosure controls and procedures were effective as of June 30, 2018 to ensure that information that is required to be disclosed by EXCO in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to EXCO’s management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There were no changes in EXCO’s internal control over financial reporting that occurred during the quarter ended June 30, 2018 that have materially affected, or are reasonably likely to materially affect, EXCO’s internal control over financial reporting.

PART II—OTHER INFORMATION
Item 1.
Legal Proceedings

In the ordinary course of business and in connection with the Chapter 11 Cases, we are party to various litigation matters. As described in “Item 3. Legal Proceedings” in our 2017 Form 10-K, we are currently in litigation with Enterprise Products Operating LLC and Acadian Gas Pipeline System (collectively, “Enterprise”) in which Enterprise filed a suit claiming that we improperly terminated certain sales and transportation contracts. On February 12, 2018, Enterprise filed a motion to lift the automatic stay of the suit under the Bankruptcy Code and continue the suit against us in state court. On March 19, 2018, we filed a motion to extend the automatic stay in the Court. On April 19, 2018, the Court entered a stipulation and agreed order pursuant to which, among other matters, Enterprise agreed to, among other things, (i) dismiss with prejudice all claims against Harold Hickey and Steve Estes and (ii) withdraw its motion to lift the automatic stay.

On March 29, 2018, the Court entered an order granting our motion to dismiss without prejudice the adversary proceeding we had initiated against Shell Energy North America (US) LP (“Shell Energy”), a subsidiary of Shell, regarding Shell Energy’s improper withholding of revenue owed to us for sales of natural gas.

On March 1, 2018, the Debtors filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure Midstream Energy, LLC and TGG Pipeline, Ltd. (collectively, “Azure”) through November 30, 2018.  The motion was abated on May, 8, 2018 and on May 16, 2018, EXCO Operating Company, LP and Raider Marketing, LP commenced an adversary proceeding under Adv. Proc. No. 18-03096.  The Debtors initiated this adversary proceeding against Azure to establish that the minimum volume commitment agreement is severable from the base gathering agreement between the parties.  The Debtors and the contract counterparties each filed various dispositive motions that were heard by the Court on August 9, 2018. The Court is anticipated to issue a ruling during the third quarter of 2018.



49


Item 1A.
Risk Factors

We have not reached an agreement with our creditors for a plan of reorganization and are subject to the risks and uncertainties associated with our exclusive right to file a plan of reorganization.

At the outset of the Chapter 11 proceedings, the Bankruptcy Code provides debtors-in-possession the exclusive right to file and solicit acceptance of a plan of reorganization for the first 120 days of the bankruptcy case, subject to extension at the discretion of the court.  All other parties are prohibited from filing or soliciting a plan of reorganization during this period.  Our initial filing exclusivity period was set to expire on May 15, 2018 and the solicitation exclusivity period was set to expire on July 14, 2018.  On April 13, 2018, the Court approved a motion to extend the filing exclusivity period through August 13, 2018 and the solicitation exclusivity period through October 12, 2018.  On July 13, 2018, we filed a second motion to extend the exclusivity period through December 11, 2018 and the solicitation exclusivity period through February 11, 2019.  With our creditors’ agreement, the Debtors filed a revised proposed order to extend the filing exclusivity period through October 15, 2018 and the solicitation exclusivity period through December 14, 2018, and on August 8, 2018, the Court approved the request. If the Court terminates that right or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of a plan in order to achieve our stated goals. The possible decision of creditors and/or other third parties, whose interest may be inconsistent with our own, to file alternative plans of reorganization could further protract the Chapter 11 proceedings, leading us to continue to incur significant professional fees and costs. Because of these risks and uncertainties associated with the termination or expiration of our exclusivity rights, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 cases may have on our corporate or capital structure.

Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
    
Recent sales of unregistered equity securities

There were no sales of unregistered equity securities during the quarter ended June 30, 2018 that were not previously reported on a Current Report on Form 8-K.

Issuer repurchases of common shares

We did not repurchase any common shares during the quarter ended June 30, 2018.

Item 3.
Defaults upon Senior Securities

As described herein, the commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the following debt instruments:

EXCO Resources Credit Agreement;
1.5 Lien Notes;
1.75 Lien Term Loans;
2018 Notes; and
2022 Notes.

In addition, we were in default under the Second Lien Term Loans as a result of our failure to make interest payments. For additional information, please see "Note 1. Organization and basis of presentation" and “Note 8. Debt” in the Notes to our Condensed Consolidated Financial Statements.

Item 6.
Exhibits

50


 
 
 
4.1
 
 
 
 
4.2
 
 
 
 
4.3
 
 
 
 
4.4
 
 
 
 
4.5
 
 
 
 
4.6
 
 
 
 
4.7
 
 
 
 
4.8
 
 
 
 
4.9
 
 
 
 
4.10
 
 
 
 
4.11
 
 
 
 
4.12
 
 
 
 
4.13
 
 
 
 
4.14
 

51


 
 
 
4.15
 
 
 
 
4.16
 
 
 
 
4.17
 
 
 
 
4.18
 
 
 
 
4.19
 
 
 
 
4.20
 
 
 
 
4.21
 
 
 
 
4.22
 
 
 
 
4.23
 
 
 
 
10.1
 
 
 
 
10.2
 
 
 
 
10.3
 
 
 
 
10.4
 
 
 
 
10.5
 
 
 
 

52


10.6
 
 
 
 
10.7
 
 
 
 
10.8
 
 
 
 
10.9
 
 
 
 
10.10
 
 
 
 
10.11
 
 
 
 
10.12
 
 
 
 
10.13
 
 
 
 
10.14
 
 
 
 
10.15
 
 
 
 
10.16
 
 
 
 
10.17
 
 
 
 
10.18
 
 
 
 
10.19
 
 
 
 
10.20
 
 
 
 
10.21
 

53


 
 
 
10.22
 
 
 
 
10.23
 
 
 
 
10.24
 
 
 
 
10.25
 
 
 
 
10.26
 
 
 
 
10.27
 
 
 
 
10.28
 
 
 
 
10.29
 
 
 
 
10.30
 
 
 
 
10.31
 
 
 
 
10.32
 
 
 
 
10.33
 
 
 
 
10.34
 
 
 
 

54


10.35
 
 
 
 
10.36
 
 
 
 
10.37
 
 
 
 
10.38
 
 
 
 
10.39
 
 
 
 
10.40
 
 
 
 
10.41
 
 
 
 
10.42
 
 
 
 
10.43
 
 
 
 
10.44
 
 
 
 
10.45
 
 
 
 
10.46
 
 
 
 
10.47
 
 
 
 

55


10.48
 
 
 
 
10.49
 
 
 
 
10.50
 
 
 
 
10.51
 
 
 
 
10.52
 
 
 
 
10.53
 
 
 
 
10.54
 
 
 
 
10.55
 
 
 
 
10.56
 
 
 
 
10.57
 
 
 
 
10.58
 
 
 
 
10.59
 
 
 
 
10.60
 
 
 
 

56


10.61
 
 
 
 
10.62
 
 
 
 
10.63
 
 
 
 
10.64
 
 
 
 
10.65
 
 
 
 
10.66
 
 
 
 
10.67
 
 
 
 
10.68
 
 
 
 
10.69
 
 
 
 
10.70
 
 
 
 
10.71
 
 
 
 
10.72
 
 
 
 
10.73
 
 
 
 

57


10.74
 
 
 
 
31.1
 
 
 
 
31.2
 
 
 
 
32.1
 
 
 
 
101.INS
 
XBRL Instance Document.
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema Document.
 
 
 
101.CAL
 
XBRL Taxonomy Calculation Linkbase Document.
 
 
 
101.DEF
 
XBRL Taxonomy Definition Linkbase Document.
 
 
 
101.LAB
 
XBRL Taxonomy Label Linkbase Document.
 
 
 
101.PRE
 
XBRL Taxonomy Presentation Linkbase Document.
 
 
 
*
 
These exhibits are management contracts.


58


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
EXCO RESOURCES, INC.
 
 
(Registrant)
 
 
 
 
Date:
August 14, 2018
 
/s/ Harold L. Hickey
 
 
 
Harold L. Hickey
 
 
 
Chief Executive Officer and President
 
 
 
(Principal Executive Officer)
 
 
 
 
 
 
 
/s/ Tyler S. Farquharson
 
 
 
Tyler S. Farquharson
 
 
 
Vice President, Chief Financial Officer and Treasurer
 
 
 
(Principal Financial Officer)
 
 
 
 
 
 
 
/s/ Brian N. Gaebe
 
 
 
Brian N. Gaebe
 
 
 
Chief Accounting Officer and Corporate Controller
 
 
 
(Principal Accounting Officer)

59