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EXCEL - IDEA: XBRL DOCUMENT - EXCO RESOURCES INCFinancial_Report.xls
EX-31.2 - CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 OF CFO - EXCO RESOURCES INCexhibit312pfo5.htm
EX-31.1 - CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 OF EXEC - EXCO RESOURCES INCexhibit311peo5.htm
EX-32.1 - CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 OF EXEC - EXCO RESOURCES INCexhibit321pfopeo5.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________________
FORM 10-Q
______________________________
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2014
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
 
74-1492779
(State of incorporation)
 
(I.R.S. Employer Identification No.)
 
 
12377 Merit Drive
Suite 1700, LB 82
Dallas, Texas
 
75251
(Address of principal executive offices)
 
(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  x    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  x    NO  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
 
x
  
Accelerated filer
 
o
 
 
 
 
 
 
 
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
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  x

The number of shares of common stock, par value $0.001 per share, outstanding as of October 23, 2014 was 273,783,402.



EXCO RESOURCES, INC.
INDEX
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

1


PART I—FINANCIAL INFORMATION

Item 1.
Financial Statements

EXCO RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)
 
September 30,
2014
 
December 31,
2013
 
 
(Unaudited)
 
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
47,950

 
$
50,483

Restricted cash
 
21,959

 
20,570

Accounts receivable, net:
 
 
 
 
Oil and natural gas
 
88,958

 
128,352

Joint interest
 
58,167

 
70,759

Other
 
6,027

 
18,022

Derivative financial instruments
 
19,230

 
8,226

Inventory and other
 
6,586

 
9,442

Total current assets
 
248,877

 
305,854

Equity investments
 
56,361

 
57,562

Oil and natural gas properties (full cost accounting method):
 
 
 
 
Unproved oil and natural gas properties and development costs not being amortized
 
354,225

 
425,307

Proved developed and undeveloped oil and natural gas properties
 
3,870,486

 
3,554,210

Accumulated depletion
 
(2,380,540
)
 
(2,183,464
)
Oil and natural gas properties, net
 
1,844,171

 
1,796,053

Gathering assets
 
33,884

 
33,473

Accumulated depreciation and amortization
 
(11,617
)
 
(10,338
)
Gathering assets, net
 
22,267

 
23,135

Office, field and other equipment, net
 
25,535

 
27,204

Deferred financing costs, net
 
33,166

 
28,807

Derivative financial instruments
 
8,813

 
6,829

Goodwill
 
163,155

 
163,155

Other assets
 
27

 
29

Total assets
 
$
2,402,372

 
$
2,408,628


See accompanying notes.












2



EXCO RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except per share and share data)

September 30,
2014

December 31,
2013


(Unaudited)


Liabilities and shareholders’ equity




Current liabilities:




Accounts payable and accrued liabilities

$
120,358


$
109,217

Revenues and royalties payable

168,331


154,862

Drilling advances
 
51,547

 
22,971

Accrued interest payable

22,836


18,144

Current portion of asset retirement obligations

216


191

Income taxes payable




Derivative financial instruments

9,297


11,919

Current maturities of long-term debt
 

 
31,866

Total current liabilities

372,585


349,170

Long-term debt
 
1,549,439

 
1,858,912

Deferred income taxes




Derivative financial instruments

7,987


9,671

Asset retirement obligations and other long-term liabilities

45,319


42,970

Commitments and contingencies




Shareholders’ equity:




Common stock, $0.001 par value; 350,000,000 authorized shares; 274,324,023 shares issued and 273,784,802 shares outstanding at September 30, 2014; 218,783,540 shares issued and 218,244,319 shares outstanding at December 31, 2013

270


215

Subscription rights, $0.001 par value; none issued and outstanding at September 30, 2014; 54,574,734 issued and outstanding at December 31, 2013
 

 
55

Additional paid-in capital

3,500,488


3,219,748

Accumulated deficit

(3,066,237
)

(3,064,634
)
Treasury stock, at cost; 539,221 shares at September 30, 2014 and December 31, 2013

(7,479
)

(7,479
)
Total shareholders’ equity

427,042


147,905

Total liabilities and shareholders’ equity

$
2,402,372


$
2,408,628


See accompanying notes.


3


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands, except per share data)
 
2014
 
2013
 
2014
 
2013
Revenues:
 
 
 
 
 
 
 
 
Oil
 
$
50,746

 
$
39,297

 
$
159,131

 
$
52,155

Natural gas
 
98,595

 
124,319

 
367,747

 
395,462

Natural gas liquids
 
1,701

 
1,698

 
5,602

 
6,252

Total revenues
 
151,042

 
165,314

 
532,480

 
453,869

Costs and expenses:
 
 
 
 
 
 
 
 
Oil and natural gas operating costs
 
14,099

 
17,187

 
48,713

 
42,706

Production and ad valorem taxes
 
7,978

 
6,074

 
22,951

 
15,303

Gathering and transportation
 
25,822

 
26,665

 
76,473

 
74,549

Depletion, depreciation and amortization
 
64,913

 
74,499

 
201,441

 
163,195

Impairment of oil and natural gas properties
 

 

 

 
10,707

Accretion of discount on asset retirement obligations
 
709

 
619

 
2,085

 
1,865

General and administrative
 
14,059

 
21,937

 
50,901

 
66,495

(Gain) loss on divestitures and other operating items
 
663

 
2,739

 
6,382

 
(179,503
)
Total costs and expenses
 
128,243

 
149,720

 
408,946

 
195,317

Operating income
 
22,799

 
15,594

 
123,534

 
258,552

Other income (expense):
 
 
 
 
 
 
 
 
Interest expense, net
 
(23,974
)
 
(36,474
)
 
(70,106
)
 
(71,771
)
Gain (loss) on derivative financial instruments
 
42,844

 
7,443

 
(14,896
)
 
19,175

Other income
 
53

 
94

 
176

 
340

Equity income (loss)
 
(153
)
 
(85,308
)
 
548

 
(61,229
)
Total other income (expense)
 
18,770

 
(114,245
)
 
(84,278
)
 
(113,485
)
Income (loss) before income taxes
 
41,569

 
(98,651
)
 
39,256

 
145,067

Income tax expense
 

 

 

 

Net income (loss)
 
$
41,569

 
$
(98,651
)
 
$
39,256

 
$
145,067

Earnings (loss) per common share:
 
 
 
 
 
 
 
 
Basic:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
0.15

 
$
(0.46
)
 
$
0.15

 
$
0.68

Weighted average common shares outstanding
 
270,631

 
215,056

 
267,316

 
214,877

Diluted:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
0.15

 
$
(0.46
)
 
$
0.15

 
$
0.67

Weighted average common shares and common share equivalents outstanding
 
272,066

 
215,056

 
267,690

 
215,195


See accompanying notes.


4


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
 
Nine Months Ended September 30,
(in thousands)
 
2014
 
2013
Operating Activities:
 
 
 
 
Net income
 
$
39,256

 
$
145,067

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depletion, depreciation and amortization
 
201,441

 
163,195

Share-based compensation expense
 
4,370

 
9,493

Accretion of discount on asset retirement obligations
 
2,085

 
1,865

Impairment of oil and natural gas properties
 

 
10,707

(Income) loss from equity method investments
 
(548
)
 
61,229

(Gain) loss on derivative financial instruments
 
14,896

 
(19,175
)
Cash settlements (payments) of derivative financial instruments
 
(32,187
)
 
28,416

Amortization of deferred financing costs and discount on debt issuance
 
9,891

 
22,440

Gain on divestitures and other non-operating items
 
(8
)
 
(186,466
)
Effect of changes in:
 
 
 
 
Accounts receivable
 
60,201

 
(32,121
)
Other current assets
 
(1,135
)
 
4,879

Accounts payable and other current liabilities
 
60,103

 
13,842

Net cash provided by operating activities
 
358,365

 
223,371

Investing Activities:
 
 
 
 
Additions to oil and natural gas properties, gathering assets and equipment
 
(297,736
)
 
(180,603
)
Property acquisitions
 
(12,987
)
 
(1,007,362
)
Proceeds from disposition of property and equipment
 
76,536

 
745,733

Restricted cash
 
(1,389
)
 
33,948

Net changes in advances to joint ventures
 
(3,181
)
 
10,055

Equity method investments
 
1,749

 
(363
)
Net cash used in investing activities
 
(237,008
)
 
(398,592
)
Financing Activities:
 
 
 
 
Borrowings under credit agreements
 
40,000

 
1,004,523

Repayments under credit agreements
 
(884,970
)
 
(777,470
)
Proceeds received from issuance of 2022 Notes
 
500,000

 

Proceeds from issuance of common stock, net
 
271,760

 
1,712

Payment of common stock dividends
 
(40,604
)
 
(32,237
)
Deferred financing costs and other
 
(10,076
)
 
(33,458
)
Net cash provided by (used in) financing activities
 
(123,890
)
 
163,070

Net decrease in cash
 
(2,533
)
 
(12,151
)
Cash at beginning of period
 
50,483

 
45,644

Cash at end of period
 
$
47,950

 
$
33,493

Supplemental Cash Flow Information:
 
 
 
 
Cash interest payments
 
$
69,257

 
$
74,949

Income tax payments
 

 

Supplemental non-cash investing and financing activities:
 
 
 
 
Capitalized share-based compensation
 
$
4,432

 
$
5,533

Capitalized interest
 
15,410

 
15,264

Issuance of common stock for director services
 
185

 
65

Accrued restricted stock dividends
 
255

 
349

Debt assumed upon formation of Compass, net
 

 
58,613


See accompanying notes.

5


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
 
 
Common Stock
 
Subscription Rights
 
Treasury Stock
 
Additional paid-in capital
 
Accumulated deficit
 
Total shareholders’ equity
(in thousands)
 
Shares
 
Amount
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
Balance at December 31, 2012
 
218,126

 
$
215

 

 
$

 
(539
)
 
$
(7,479
)
 
$
3,200,067

 
$
(3,043,410
)
 
$
149,393

Issuance of common stock
 
227

 

 

 

 

 

 
1,777

 

 
1,777

Share-based compensation
 

 

 

 

 

 

 
14,998

 

 
14,998

Restricted stock issued, net of cancellations
 
807

 
1

 

 

 

 

 

 

 
1

Common stock dividends
 

 

 

 

 

 

 

 
(32,586
)
 
(32,586
)
Net income
 

 

 

 

 

 

 

 
145,067

 
145,067

Balance at September 30, 2013
 
219,160

 
$
216

 

 
$

 
(539
)
 
$
(7,479
)
 
$
3,216,842

 
$
(2,930,929
)
 
$
278,650

Balance at December 31, 2013
 
218,783

 
$
215

 
54,575

 
$
55

 
(539
)
 
$
(7,479
)
 
$
3,219,748

 
$
(3,064,634
)
 
$
147,905

Issuance of common stock
 
54,582

 
55

 
(54,575
)
 
(55
)
 

 

 
271,945

 

 
271,945

Share-based compensation
 

 

 

 

 

 

 
8,795

 

 
8,795

Restricted stock issued, net of cancellations
 
959

 

 

 

 

 

 

 

 

Common stock dividends
 

 

 

 

 

 

 

 
(40,859
)
 
(40,859
)
Net income
 

 

 

 

 

 

 

 
39,256

 
39,256

Balance at September 30, 2014
 
274,324

 
$
270

 

 
$

 
(539
)
 
$
(7,479
)
 
$
3,500,488

 
$
(3,066,237
)
 
$
427,042

 
See accompanying notes.

6


EXCO RESOURCES, INC.
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,” “Company,” “we,” “us,” and “our” 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 and Compass Production Partners, LP.

East Texas/North Louisiana
The East Texas/North Louisiana region is primarily comprised of our Haynesville and Bossier shale assets. We have a joint venture with BG Group, plc ("BG Group") covering an undivided 50% interest in certain Haynesville/Bossier shale assets in East Texas and North Louisiana. BG Group’s right to participate in our acquisition of oil and natural gas properties within an area of mutual interest in the East Texas/North Louisiana region expired in August 2014. We serve as the operator for most of our properties in the East Texas/North Louisiana region.

South Texas
The South Texas region is primarily comprised of our Eagle Ford shale assets. We have a joint venture with affiliates of Kohlberg Kravis Roberts & Co. L.P. ("KKR") to develop certain assets in the Eagle Ford shale. The South Texas region also includes assets outside of the joint venture in the Eagle Ford shale and other formations. We serve as the operator for most of our properties in the South Texas region.

Appalachia
The Appalachia region is primarily comprised of Marcellus shale assets as well as shallow conventional assets in other formations. We have a joint venture with BG Group covering our shallow conventional assets and Marcellus shale assets in the Appalachia region ("Appalachia JV"). EXCO and BG Group each own 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 a jointly owned operating entity ("OPCO") that operates the Appalachia JV's properties. We own a 50% interest in OPCO.

Compass Production Partners, LP
We have a joint venture with Harbinger Group Inc. ("HGI") in which we own a 25.5% economic interest in shallow conventional assets in East Texas and North Louisiana and shallow Canyon Sand and other assets in the Permian Basin ("Compass Production Partners" or "Compass"). We report our interest in Compass using proportional consolidation. On October 6, 2014, we entered into an agreement to sell our 25.5% economic interest in Compass to HGI. For further discussion of this transaction, see "Note 15. Subsequent event".
The accompanying Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013, Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the nine months ended September 30, 2014 and 2013 are for EXCO and its subsidiaries. The 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") and in the opinion of management, such financial statements reflect all adjustments necessary to fairly present the consolidated financial position of EXCO at September 30, 2014 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes

7


included in EXCO's Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on February 26, 2014 ("2013 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.

2.Significant accounting policies
We consider significant accounting policies to be those related to our estimates of proved reserves, accounting for oil and natural gas properties, derivatives, business combinations, share-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 the 2013 Form 10-K.
Recent accounting pronouncements
In April 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity ("ASU 2014-08"). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity's operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. ASU 2014-08 also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. ASU 2014-08 retained the scope exception for oil and natural gas properties accounted for under the full-cost method and therefore we do not believe the update will have a significant impact on our consolidated financial condition and results of operations. ASU 2014-08 is effective prospectively to all periods beginning after December 15, 2014. We will apply the guidance prospectively to disposal activity, when applicable, occurring after the effective date of ASU 2014-08.
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 ("IASB") 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. In doing so, companies will need to use more judgment and make more estimates than under currently applicable guidance, including identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method. We are currently assessing the potential impact of ASU 2014-09 on our consolidated financial condition and results of operations.
In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern ("ASU 2014-15"). ASU 2014-15 provides guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and sets rules for how this information should be disclosed in the financial statements. ASU 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods thereafter. Early adoption is permitted. We do not expect our adoption of ASU 2014-15 to have an impact on our consolidated financial condition and results of operations.

3.Acquisitions, divestitures and other significant events

Permian Basin transaction
On March 24, 2014, we closed a purchase and sale agreement with a private party for the sale of our interest in certain non-operated assets in the Permian Basin including producing wells and undeveloped acreage for approximately $68.2 million, after final purchase price adjustments. The effective date of the transaction was January 1, 2014. Proceeds from the sale were used to reduce indebtedness under our credit agreement ("EXCO Resources Credit Agreement").

8



4.Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the nine months ended September 30, 2014:
(in thousands)
 
 
Asset retirement obligations at beginning of period
 
$
42,954

Activity during the period:
 
 
Liabilities incurred during the period
 
433

Liabilities settled during the period
 
(30
)
Adjustment to liability due to acquisitions
 
107

Adjustment to liability due to divestitures
 
(14
)
Accretion of discount
 
2,085

Asset retirement obligations at end of period
 
45,535

Less current portion
 
216

Long-term portion
 
$
45,319

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

The accounting for, and disclosure of, oil and natural gas producing activities requires that we choose between two GAAP alternatives: the full cost method or the successful efforts method. 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. Our unproved property costs, which include unproved oil and natural gas properties, properties under development, and major development projects, collectively totaled $354.2 million and $425.3 million as of September 30, 2014 and December 31, 2013, respectively, and are not subject to depletion. 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. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. There were no impairments of unproved properties during the nine months ended September 30, 2014 and 2013.
We capitalize interest on the costs related to the acquisition of undeveloped acreage in accordance with FASB ASC 835-20, Capitalization of Interest. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest related to these properties. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities.
We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs less estimated salvage value are divided by the total estimated quantities of proved reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded.
Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and proved reserves.
Pursuant to Rule 4-10(c)(4) of Regulation S-X, 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 limitation is less than the full cost pool, we are required to record a ceiling test impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of

9


estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC Release No. 33-8995, 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.
The ceiling test is computed using the simple average spot price for the trailing 12 month period using the first day of each month. For the 12 months ended September 30, 2014, the trailing 12 month reference prices were $4.24 per Mmbtu for natural gas at Henry Hub ("HH") and $99.08 per Bbl of oil for West Texas Intermediate ("WTI") at Cushing, Oklahoma. The price used for NGLs was $42.45 per Bbl and was based on the trailing 12 month average of realized prices. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full cost accounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedging instruments, we are not allowed to use the impact of the derivative financial instruments in our ceiling test computations.
The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of 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.
We did not recognize an impairment to our proved oil and natural gas properties for the three and nine months ended September 30, 2014. We did not recognize an impairment to our proved oil and natural gas properties for the three months ended September 30, 2013 and recognized an impairment of $10.7 million for the nine months ended September 30, 2013 primarily due to low natural gas prices for the trailing twelve month period at the end of the first quarter of 2013.

6.Earnings per share

The following table presents the basic and diluted earnings (loss) per share computations for the three and nine months ended September 30, 2014 and 2013
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands, except per share data)
 
2014
 
2013
 
2014
 
2013
Basic net income (loss) per common share:
 
 
 
 
 
 
 
 
    Net income (loss)
 
$
41,569

 
$
(98,651
)
 
$
39,256

 
$
145,067

    Weighted average common shares outstanding
 
270,631

 
215,056

 
267,316

 
214,877

    Net income (loss) per basic common share
 
$
0.15

 
$
(0.46
)
 
$
0.15

 
$
0.68

Diluted net income (loss) per common share:
 
 
 
 
 
 
 
 
   Net income (loss)
 
$
41,569

 
$
(98,651
)
 
$
39,256

 
$
145,067

Weighted average common shares outstanding
 
270,631

 
215,056

 
267,316

 
214,877

Dilutive effect of:
 
 
 
 
 
 
 
 
Stock options
 

 

 

 
8

Restricted shares
 
1,435

 

 
374

 
310

Weighted average common shares and common share equivalents outstanding
 
272,066

 
215,056

 
267,690

 
215,195

    Net income (loss) per diluted common share
 
$
0.15

 
$
(0.46
)
 
$
0.15

 
$
0.67

Diluted earnings per share for the three and nine months ended September 30, 2014 and 2013 is computed in the same manner as basic earnings per share after assuming the issuance of common stock for all potentially dilutive common stock equivalents, which include both stock options and restricted stock awards, whether exercisable or not. The computation of diluted earnings per share excluded 13,122,425 and 17,478,476 antidilutive share equivalents for the three months ended September 30, 2014 and 2013, respectively, and 13,668,594 and 16,884,896 antidilutive share equivalents for the nine months ended September 30, 2014 and 2013, respectively. The antidilutive share equivalents primarily consisted of out-of-the-money stock options for the three months ended September 30, 2014 and the nine months ended September 30, 2014 and 2013.


10


7.Derivative financial instruments

Our primary objective in entering into derivative financial instruments is 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. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instruments. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value in earnings.
The table below outlines the classification of our derivative financial instruments on our Condensed Consolidated Balance Sheets and their financial impact on our Condensed Consolidated Statements of Operations.    
Fair Value of Derivative Financial Instruments
(in thousands)
 
September 30, 2014
 
December 31, 2013
Derivative financial instruments - Current assets
 
$
19,230

 
$
8,226

Derivative financial instruments - Long-term assets
 
8,813

 
6,829

Derivative financial instruments - Current liabilities
 
(9,297
)
 
(11,919
)
Derivative financial instruments - Long-term liabilities
 
(7,987
)
 
(9,671
)
Net derivative financial instruments
 
$
10,759

 
$
(6,535
)
Effect of Derivative Financial Instruments
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
 
2014
 
2013
 
2014
 
2013
Gain (loss) on derivative financial instruments
 
$
42,844

 
$
7,443

 
$
(14,896
)
 
$
19,175

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 includes 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.
Our oil and natural gas derivative instruments are comprised of the following instruments:
Swaps: These contracts allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity.
Basis swaps: These contracts allow us to receive a fixed price differential between market indices for oil prices based on the delivery point. Our oil basis swaps typically have a positive differential to NYMEX WTI oil prices.
Call options: These contracts give our trading counterparties the right, but not the obligation, to buy an agreed quantity of oil or natural gas from us at a certain time and price in the future. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. In exchange for selling this option, we received upfront proceeds which we used to obtain a higher fixed price on our swaps.  These transactions were conducted contemporaneously with a single counterparty and resulted in a net cashless transaction.
Three-way collars: A three-way collar is a combination of options including a sold call, a purchased put and a sold put. These contracts allow us to participate in the upside of commodity prices to the ceiling of the call option and provide us with partial downside protection through the combination of the put options. If the market price is below the strike price of the purchased put at the time of settlement then the counterparty pays us the excess, unless the market price falls below the strike price of the sold put at which point the counterparty pays us the difference between the strike prices of the purchased put and sold put. If the market price is above the strike price of the sold call at the time of settlement, we pay the counterparty the excess. These transactions were conducted contemporaneously with a single counterparty and resulted in a net cashless transaction.

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We place our derivative financial instruments with the financial institutions that are lenders under our respective credit agreements that we believe have high quality credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty. We proportionately consolidate the derivative financial instruments entered into by Compass; however, the contracts of Compass involve separate master netting agreements with its counterparties.
The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments (including our 25.5% proportionate interest in Compass's derivative financial instruments) as of September 30, 2014:
(in thousands, except prices)
 
Volume Mmbtu/Bbl
 
Weighted average strike price per Mmbtu/Bbl
 
Fair value at September 30, 2014
Natural gas:
 
 
 
 
 
 
Swaps:
 
 
 
 
 
 
Remainder of 2014
 
21,185

 
$
4.22

 
$
2,674

2015
 
40,167

 
4.22

 
8,628

Call options:
 
 
 
 
 
 
Remainder of 2014
 
5,060

 
4.29

 
(537
)
2015
 
20,075

 
4.29

 
(5,217
)
Three-way collars:
 
 
 
 
 
 
2015
 
16,425

 
 
 
(738
)
Sold call
 
 
 
4.45

 
 
Purchased put
 
 
 
3.81

 
 
Sold put
 
 
 
3.31

 
 
2016
 
10,980

 
 
 
(259
)
Sold call
 
 
 
4.80

 
 
Purchased put
 
 
 
3.90

 
 
Sold put
 
 
 
3.40

 
 
Total natural gas
 
 
 
 
 
$
4,551

Oil:
 
 
 
 
 
 
Swaps:
 
 
 
 
 
 
Remainder of 2014
 
414

 
$
95.03

 
$
1,863

2015
 
976

 
93.19

 
4,460

Basis swaps:
 


 

 


Remainder of 2014
 
46

 
6.03

 
140

2015
 
91

 
6.10

 
284

Call options:
 
 
 
 
 
 
Remainder of 2014
 
92

 
100.00

 
(28
)
2015
 
365

 
100.00

 
(511
)
Total oil
 
 
 
 
 
$
6,208

Total oil and natural gas derivative financial instruments
 
 
 
 
 
$
10,759

At December 31, 2013, we had outstanding swap and call option contracts covering 112,348 Mmmbtu and 40,150 Mmmbtu, respectively, of natural gas and we had outstanding swap, basis swap and call option contracts covering 2,192 Mbbls, 274 Mbbls and 730 Mbbls, respectively, of oil.
At September 30, 2014, the average forward NYMEX WTI oil prices per Bbl for the remainder of 2014 and calendar year 2015 were $90.72, and $88.08, respectively, the average forward NYMEX Louisiana Light Sweet ("LLS") oil prices per Bbl for the remainder of 2014 and calendar year 2015 were $93.76, and $91.04, respectively, and the average forward NYMEX HH natural gas prices per Mmbtu for the remainder of 2014 and calendar years 2015 and 2016 were $4.16, $4.00 and $4.08, respectively.

12


As of September 30, 2014, our proportionate share of Compass's derivative swap contracts covered 1,405 Mmmbtu of natural gas for the remainder of 2014 and 929 Mmmbtu of natural gas during 2015 at an average price of $4.15 and $3.98, respectively. As of September 30, 2014 our proportionate share of Compass's derivative swap contracts covered 23 Mbbls of oil for the remainder of 2014 and 64 Mbbls of oil during 2015 at an average price of $91.87 and $94.98, respectively.
Our derivative financial instruments covered approximately 72% and 60% of production volumes for the three months ended September 30, 2014 and 2013, respectively, and 68% and 55% for the nine months ended September 30, 2014 and 2013, respectively.

8.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.
Fair value of derivative financial instruments
The fair value of our derivative financial instruments may be different from the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers. During the nine months ended September 30, 2014 and 2013 there were no changes in the fair value level classifications. The following table presents a summary of the estimated fair value of our derivative financial instruments as of September 30, 2014 and December 31, 2013.
 
 
September 30, 2014
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total
Oil and natural gas derivative financial instruments
 
$

 
$
10,759

 
$

 
$
10,759

 
 
December 31, 2013
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total
Oil and natural gas derivative financial instruments
 
$

 
$
(6,535
)
 
$

 
$
(6,535
)
We evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis on our Condensed Consolidated Balance Sheets. Net derivative asset values are determined primarily by quoted futures prices and utilization of the counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve or the credit-adjusted risk-free rate curve of Compass. 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 London Interbank Offered Rate ("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. In addition, the credit-adjusted risk-free rate for Compass is based on the cost of debt plus the LIBOR curve as of the end of the reporting period.
The valuation of our commodity price derivatives, represented by oil and natural gas swaps, basis swaps, call option and three-way collar contracts, is discussed below.
Oil derivatives. Our oil derivatives are swap, basis swap and call option contracts for notional Bbls of oil at fixed (in the case of swap and basis swap contracts) or interval (in the case of call option contracts) NYMEX oil index prices. The asset and

13


liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for oil index prices, (iii) the applicable credit-adjusted risk-free rate curve, as described above, and (iv) the implied rate of volatility inherent in the call option contracts. The implied rates of volatility were determined based on average NYMEX oil index prices.
Natural gas derivatives. Our natural gas derivatives are swap, three-way collar and call option contracts for notional Mmbtus of natural gas at posted price indexes, including NYMEX HH swap and option contracts. The asset and liability values attributable to our natural gas derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH for natural gas swaps, (iii) the applicable credit-adjusted risk-free rate curve, as described above and (iv) the implied rate of volatility inherent in the option contracts. The implied rates of volatility were determined based on average HH natural gas prices.
See further details on the fair value of our derivative financial instruments in “Note 7. Derivative financial instruments”.
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 revolving commitment of the EXCO Resources Credit Agreement and Compass's credit agreement ("Compass Production Partners 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 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes"), our 8.5% senior unsecured notes due April 15, 2022 ("2022 Notes") and the term loan under the EXCO Resources Credit Agreement ("Term Loan") are presented below.  The estimated fair values of the 2018 Notes, 2022 Notes and Term Loan have been calculated based on market quotes.
 
 
September 30, 2014
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total
2018 Notes
 
$
730,500

 
$

 
$

 
$
730,500

2022 Notes
 
479,375

 

 

 
479,375

 
 
December 31, 2013
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total
2018 Notes
 
$
714,000

 
$

 
$

 
$
714,000

Term Loan
 
298,500

 

 

 
298,500


9.Debt

Our total debt is summarized as follows:
(in thousands)
 
September 30, 2014
 
December 31, 2013
Revolving commitment under EXCO Resources Credit Agreement
 
$
222,492

 
$
763,866

Term Loan under EXCO Resources Credit Agreement
 

 
298,500

Unamortized discount on Term Loan
 

 
(2,780
)
2018 Notes
 
750,000

 
750,000

Unamortized discount on 2018 Notes
 
(6,299
)
 
(7,293
)
2022 Notes
 
500,000

 

Total debt excluding Compass Production Partners
 
1,466,193

 
1,802,293

Compass Production Partners Credit Agreement
 
83,246

 
88,485

Total debt
 
1,549,439

 
1,890,778

Less amounts due within one year
 

 
31,866

Total debt after one year
 
$
1,549,439

 
$
1,858,912

Terms and conditions of our debt obligations as of September 30, 2014 are discussed below.

14


EXCO Resources Credit Agreement
As of September 30, 2014, the EXCO Resources Credit Agreement had $222.5 million of outstanding indebtedness, $875.0 million of available borrowing base and $645.9 million of unused borrowing base, net of letters of credit. The maturity date of the EXCO Resources Credit Agreement is July 31, 2018.
We closed a rights offering and related private placement of our common stock on January 17, 2014 ("Rights Offering") and received gross proceeds of $272.9 million which we used to reduce the outstanding indebtedness under the EXCO Resources Credit Agreement, including the remainder of the asset sale requirement as well as a portion of the revolving commitment. See further discussion in "Note 13. Rights offering and other equity transactions". Upon repayment of the asset sale requirement, the interest rate on the revolving commitment decreased by 100 basis points.
On April 16, 2014, we closed an offering of $500.0 million in aggregate principal amount of senior unsecured notes and utilized the proceeds to fully repay the Term Loan and the remaining proceeds were used to reduce outstanding indebtedness under the revolving commitment of the EXCO Resources Credit Agreement. See further discussion of the 2022 Notes below.
As of September 30, 2014, our borrowing base under the revolving commitment of the EXCO Resources Credit Agreement was $875.0 million. On October 21, 2014, we amended the EXCO Resources Credit Agreement which increased our borrowing base to $900.0 million. Subsequent redeterminations will occur semi-annually with us and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. The interest rate grid for the revolving commitment under the EXCO Resources Credit Agreement ranges from LIBOR plus 175 bps to 275 bps (or alternate base rate ("ABR") plus 75 bps to 175 bps), depending on our borrowing base usage. On September 30, 2014, the one month LIBOR was 0.2%, which resulted in an interest rate of approximately 2.2% on the revolving commitment.
The EXCO Resources Credit Agreement sets forth the terms and conditions under which we are permitted to pay a cash dividend on our common stock. In July 2014, we amended the EXCO Resources Credit Agreement to provide that we may declare and pay cash dividends on our common stock in an amount not to exceed a cumulative total of $75.0 million in any four consecutive fiscal quarters, provided that, as of each payment date and after giving effect to the dividend payment date, (i) no default has occurred and is continuing, (ii) we have at least 10% of our revolving commitment, as defined in the EXCO Resources Credit Agreement, available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under the indenture governing the 2018 Notes and 2022 Notes.
As of September 30, 2014, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:
maintain a consolidated current ratio (as defined in the EXCO Resources Credit Agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter; and
not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) to be greater than 4.5 to 1.0 at the end of any fiscal quarter.
While we believe our existing capital resources, including our cash flow from operations and borrowing capacity under the EXCO Resources Credit Agreement are sufficient to conduct our operations through 2014 and 2015, there are certain risks arising from depressed oil and natural gas prices and declines in production volumes that could impact our ability to meet debt covenants in future periods. Our ability to maintain compliance with these covenants may be negatively impacted if oil and/or natural gas prices remain depressed for an extended period of time.
2018 Notes
The 2018 Notes are guaranteed on a senior unsecured basis by a majority of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly-held equity investments with BG Group. Our equity investments with BG Group, other than OPCO, have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.
As of September 30, 2014, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at September 30, 2014 was $6.3 million. Interest accrues at 7.5% per annum and is payable semi-annually in arrears on March 15 and September 15 of each year.
The indenture governing the 2018 Notes contains covenants, which may limit our ability and the ability of our restricted subsidiaries to:
incur or guarantee additional debt and issue certain types of preferred stock;
pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
make certain investments;

15


create liens on our assets;
enter into sale/leaseback transactions;
create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
engage in transactions with our affiliates;
transfer or issue shares of stock of subsidiaries;
transfer or sell assets; and
consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.
2022 Notes
On April 16, 2014, we completed a public offering of $500.0 million in aggregate principal amount of senior unsecured notes due April 15, 2022. We received net proceeds of approximately $490.0 million after offering fees and expenses. The 2022 Notes were issued at 100.0% of the principal amount and bear interest at a rate of 8.5% per annum, payable in arrears on April 15 and October 15 of each year. We used a portion of the net proceeds from the 2022 Notes offering to repay the $297.8 million outstanding principal balance on the Term Loan and the remaining proceeds were used to reduce outstanding indebtedness under the revolving commitment of the EXCO Resources Credit Agreement.
The 2022 Notes rank equally in right of payment to any existing and future senior unsecured indebtedness of the Company (including the 2018 Notes) and are guaranteed on a senior unsecured basis by EXCO’s consolidated subsidiaries that are guarantors of the indebtedness under the EXCO Resources Credit Agreement. The 2022 Notes were issued under the same base indenture governing the 2018 Notes and the supplemental indenture governing the 2022 Notes contains similar covenants to those in the supplemental indenture governing the 2018 Notes.
Compass Production Partners Credit Agreement
As of September 30, 2014, the Compass Production Partners Credit Agreement had a borrowing base of $400.0 million. The borrowing base is redetermined semi-annually, with Compass and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. In October 2014, the borrowing base of $400.0 million was reaffirmed as a result of the semi-annual redetermination. The Compass Production Partners Credit Agreement matures on February 14, 2018.
Borrowings under the Compass Production Partners Credit Agreement are secured by properties owned by Compass and we do not guarantee Compass's debt. Compass is not a guarantor of the EXCO Resources Credit Agreement, the 2018 Notes or the 2022 Notes. As of September 30, 2014, $327.0 million was drawn under the Compass Production Partners Credit Agreement, and our proportionate share of the obligation was $83.2 million. The interest rate grid ranges from LIBOR plus 175 bps to 275 bps (or ABR plus 75 bps to 175 bps), depending on the percentages of drawn balances to the borrowing base as defined in the agreement. On September 30, 2014, the interest rate on the outstanding borrowings was approximately 2.7%.
As of September 30, 2014, Compass was in compliance with the financial covenants contained in the Compass Production Partners Credit Agreement, which require that it:
maintain a consolidated current ratio (as defined in the Compass Production Partners Credit Agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter; and
not permit the ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the Compass Production Partners Credit Agreement) to be greater than 4.5 to 1.0 at the end of any fiscal quarter.
The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit Agreement, the indentures governing the 2018 Notes and 2022 Notes, and the Compass Production Partners Credit Agreement.

10.Dividends

On September 11, 2014, our board of directors approved a cash dividend of $0.05 per share for the third quarter of 2014. The total cash dividend was $13.7 million, of which $13.5 million was paid on September 30, 2014 to holders of record as of September 22, 2014 and the remainder was accrued to be paid to holders of restricted shares upon vesting. Total dividends paid to our shareholders for the nine months ended September 30, 2014 were $40.6 million.
The declaration of any future dividends, as well as the establishment of record and payment dates, is subject to the review and approval of our board of directors. Furthermore, any future declaration of dividends is subject to limitations under the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and the indenture governing the 2022 Notes.


16


11.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. We have accumulated financial 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 decreased $16.8 million for the nine months ended September 30, 2014. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $874.8 million which have fully offset our deferred tax assets as of September 30, 2014. 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.

12.Related party transactions

OPCO serves as the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis. OPCO may distribute any excess cash equally between us and BG Group when its operating cash flows are sufficient to meet its capital requirements. There are service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. For the three and nine months ended September 30, 2014 and 2013, these transactions included the following:

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
 
2014
 
2013
 
2014
 
2013
Advances to OPCO
 
$

 
$
3,980

 
$

 
$
25,890

Amounts received from OPCO
 
24,660

 
12,006

 
45,631

 
31,981


As of September 30, 2014 and December 31, 2013, the amounts owed were as follows:
(in thousands)
 
September 30, 2014
 
December 31, 2013
Amounts due to EXCO (1)
 
$
3,020

 
$
2,283

Amounts due from EXCO (1)
 
1,591

 


(1)
OPCO is the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis, which are recorded in "Other current assets" on our Condensed Consolidated Balance Sheets. Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" on our Condensed Consolidated Balance Sheets.
Other related party transactions
Investment accounts managed by Invesco Advisers, Inc. were lenders under the Term Loan of the EXCO Resources Credit Agreement. Invesco Advisers, Inc. is an indirect owner of WL Ross & Co. LLC ("WL Ross"). Wilbur L. Ross, Jr., the Chairman and Chief Executive Officer at WL Ross, serves on EXCO’s board of directors. Invesco Advisers, Inc. held approximately 10% of total borrowings under the Term Loan until the Term Loan was repaid in April 2014 with proceeds received from the issuance of 2022 Notes.
As discussed in "Note 13. Rights offering and other equity transactions", we entered into investment agreements and closed a related private placement of our common stock with certain affiliates of WL Ross and Hamblin Watsa Investment Counsel Ltd. ("Hamblin Watsa"). Wilbur L. Ross, Jr., the Chairman and Chief Executive Officer of WL Ross, and Samuel A. Mitchell, Managing Director of Hamblin Watsa, both serve on EXCO's board of directors.

13.Rights offering and other equity transactions
Rights offering
We closed a rights offering and related private placement of our common stock on January 17, 2014 which resulted in the issuance of 54,574,734 shares of common stock for gross proceeds of $272.9 million. In connection with the Rights Offering, we entered into investment agreements ("Investment Agreements") with certain affiliates of WL Ross and Hamblin Watsa pursuant to which, subject to the terms and conditions thereof, each of them severally agreed to subscribe for and purchase, in a

17


private placement, its respective pro rata portion of shares under the basic subscription right and all unsubscribed shares under the over-subscription privilege subject to the pro rata allocation among the subscription rights holders who elected to exercise their over-subscription privilege. In connection with the Rights Offering and related transactions under the Investment Agreements, WL Ross and Hamblin Watsa purchased 19,599,973 and 6,726,712 shares, respectively, pursuant to their basic subscription rights and the over-subscription privilege. After giving effect to the Rights Offering, WL Ross and Hamblin Watsa owned 18.7% and 6.4%, respectively, of the Company's outstanding common shares as of January 17, 2014.
Preferred Stock
We canceled all classes of our preferred stock in 2014. As of the date of cancellation and December 31, 2013, we had 10,000,000 shares of preferred stock authorized with no shares of preferred stock issued and outstanding. Our issued and outstanding shares of capital stock consist solely of shares of common stock.

14.Condensed consolidating financial statements

As of September 30, 2014, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement and the indentures governing the 2018 Notes and 2022 Notes. All of our non-guarantor subsidiaries were considered unrestricted subsidiaries under the indentures governing the 2018 Notes and 2022 Notes, with the exception of our equity investment in OPCO. As of and for the nine months ended September 30, 2014, our equity method investment in OPCO represented $10.6 million of equity method investments and contributed $2.3 million of equity method losses.
Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The 2018 Notes and 2022 Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by some 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.
    
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.

18


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING BALANCE SHEET
(Unaudited)
September 30, 2014
 (in thousands)
 
 Resources
 
 Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
 Eliminations
 
 Consolidated
 Assets
 
 
 
 
 
 
 
 
 
 
 Current assets:
 
 
 
 
 
 
 
 
 
 
 Cash and cash equivalents
 
$
66,500

 
$
(23,316
)
 
$
4,766

 
$

 
$
47,950

 Restricted cash
 

 
21,959

 

 

 
21,959

 Other current assets
 
27,865

 
143,128

 
7,975

 

 
178,968

         Total current assets
 
94,365

 
141,771

 
12,741

 

 
248,877

 Equity investments
 

 

 
56,361

 

 
56,361

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

 
351,812

 
2,413

 

 
354,225

Proved developed and undeveloped oil and natural gas properties
 
334,295

 
3,413,304

 
122,887

 

 
3,870,486

     Accumulated depletion
 
(330,665
)
 
(2,024,125
)
 
(25,750
)
 

 
(2,380,540
)
     Oil and natural gas properties, net
 
3,630

 
1,740,991

 
99,550

 

 
1,844,171

 Gathering, office, field and other equipment, net
 
1,841

 
24,969

 
20,992

 

 
47,802

 Investments in and advances to affiliates, net
 
1,799,881

 

 

 
(1,799,881
)
 

 Deferred financing costs, net
 
32,322

 

 
844

 

 
33,166

 Derivative financial instruments
 
8,682

 

 
131

 

 
8,813

 Goodwill
 
13,293

 
149,862

 

 

 
163,155

 Other assets
 
2

 
24

 
1

 

 
27

         Total assets
 
$
1,954,016

 
$
2,057,617

 
$
190,620

 
$
(1,799,881
)
 
$
2,402,372

 Liabilities and shareholders' equity
 
 
 
 
 
 
 
 
 
 
 Current liabilities
 
$
52,543

 
$
309,127

 
$
10,915

 
$

 
$
372,585

 Long-term debt
 
1,466,193

 

 
83,246

 

 
1,549,439

 Deferred income taxes
 

 

 

 

 

 Other long-term liabilities
 
8,238

 
35,934

 
9,134

 

 
53,306

 Payable to parent
 

 
2,083,697

 
29,921

 
(2,113,618
)
 

         Total shareholders' equity
 
427,042

 
(371,141
)
 
57,404

 
313,737

 
427,042

         Total liabilities and shareholders' equity
 
$
1,954,016

 
$
2,057,617

 
$
190,620

 
$
(1,799,881
)
 
$
2,402,372


19


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2013
 (in thousands)
 
 Resources
 
 Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
 Eliminations
 
 Consolidated
 Assets
 
 
 
 
 
 
 
 
 
 
 Current assets:
 
 
 
 
 
 
 
 
 
 
 Cash and cash equivalents
 
$
81,840

 
$
(35,892
)
 
$
4,535

 
$

 
$
50,483

 Restricted cash
 

 
20,570

 

 

 
20,570

 Other current assets
 
22,533

 
206,708

 
5,560

 

 
234,801

         Total current assets
 
104,373

 
191,386

 
10,095

 

 
305,854

 Equity investments
 

 

 
57,562

 

 
57,562

 Oil and natural gas properties (full cost accounting method):
 
 
 
 
 
 
 
 
 
 
Unproved oil and natural gas properties and development costs not being amortized
 
6,758

 
415,290

 
3,259

 

 
425,307

Proved developed and undeveloped oil and natural gas properties
 
337,972

 
3,097,335

 
118,903

 

 
3,554,210

     Accumulated depletion
 
(330,086
)
 
(1,840,332
)
 
(13,046
)
 

 
(2,183,464
)
     Oil and natural gas properties, net
 
14,644

 
1,672,293

 
109,116

 

 
1,796,053

 Gathering, office, field and other equipment, net
 
3,479

 
24,612

 
22,248

 

 
50,339

 Investments in and advances to affiliates, net
 
1,834,197

 

 

 
(1,834,197
)
 

 Deferred financing costs, net
 
27,771

 

 
1,036

 

 
28,807

 Derivative financial instruments
 
6,829

 

 

 

 
6,829

 Goodwill
 
13,293

 
149,862

 

 

 
163,155

 Other assets
 
2

 
27

 

 

 
29

         Total assets
 
$
2,004,588

 
$
2,038,180

 
$
200,057

 
$
(1,834,197
)
 
$
2,408,628

 Liabilities and shareholders' equity
 
 
 
 
 
 
 
 
 
 
 Current liabilities
 
$
76,174

 
$
264,485

 
$
8,511

 
$

 
$
349,170

 Long-term debt
 
1,770,427

 

 
88,485

 

 
1,858,912

 Deferred income taxes
 

 

 

 

 

 Other long-term liabilities
 
10,082

 
33,831

 
8,728

 

 
52,641

 Payable to parent
 

 
2,230,108

 
35,777

 
(2,265,885
)
 

         Total shareholders' equity
 
147,905

 
(490,244
)
 
58,556

 
431,688

 
147,905

         Total liabilities and shareholders' equity
 
$
2,004,588

 
$
2,038,180

 
$
200,057

 
$
(1,834,197
)
 
$
2,408,628

 
 
 
 
 
 
 
 
 
 
 

20


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the three months ended September 30, 2014


(in thousands)
 
Resources
 
Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
173

 
$
138,983

 
$
11,886

 
$

 
$
151,042

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 
(31
)
 
16,823

 
5,285

 

 
22,077

Gathering and transportation
 
1

 
24,697

 
1,124

 

 
25,822

Depletion, depreciation and amortization
 
658

 
59,392

 
4,863

 

 
64,913

Accretion of discount on asset retirement obligations
 
4

 
532

 
173

 

 
709

General and administrative
 
(3,059
)
 
16,211

 
907

 

 
14,059

Other operating items
 
(103
)
 
779

 
(13
)
 

 
663

    Total costs and expenses
 
(2,530
)
 
118,434

 
12,339

 

 
128,243

Operating income (loss)
 
2,703

 
20,549

 
(453
)
 

 
22,799

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(23,300
)
 

 
(674
)
 

 
(23,974
)
Gain on derivative financial instruments
 
40,835

 

 
2,009

 

 
42,844

Other income
 
31

 
16

 
6

 

 
53

Equity loss
 

 

 
(153
)
 

 
(153
)
Net income from consolidated subsidiaries
 
21,300

 

 

 
(21,300
)
 

    Total other income
 
38,866

 
16

 
1,188

 
(21,300
)
 
18,770

Income before income taxes
 
41,569

 
20,565

 
735

 
(21,300
)
 
41,569

Income tax expense
 

 

 

 

 

Net income
 
$
41,569

 
$
20,565

 
$
735

 
$
(21,300
)
 
$
41,569



21


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the three months ended September 30, 2013
(in thousands)
 
Resources
 
Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
138

 
$
152,949

 
$
12,227

 
$

 
$
165,314

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 
80

 
18,329

 
4,852

 

 
23,261

Gathering and transportation
 

 
25,644

 
1,021

 

 
26,665

Depletion, depreciation and amortization
 
1,054

 
68,757

 
4,688

 

 
74,499

Accretion of discount on asset retirement obligations
 
4

 
455

 
160

 

 
619

General and administrative
 
4,277

 
16,935

 
725

 

 
21,937

Other operating items
 
(446
)
 
3,185

 

 

 
2,739

    Total costs and expenses
 
4,969

 
133,305

 
11,446

 

 
149,720

Operating income (loss)
 
(4,831
)
 
19,644

 
781

 

 
15,594

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(35,714
)
 

 
(760
)
 

 
(36,474
)
Gain (loss) on derivative financial instruments
 
8,089

 
59

 
(705
)
 

 
7,443

Other income
 
53

 
37

 
4

 

 
94

Equity loss
 

 

 
(85,308
)
 

 
(85,308
)
Net loss from consolidated subsidiaries
 
(66,248
)
 

 

 
66,248

 

    Total other income (expense)
 
(93,820
)
 
96

 
(86,769
)
 
66,248

 
(114,245
)
Income (loss) before income taxes
 
(98,651
)
 
19,740

 
(85,988
)
 
66,248

 
(98,651
)
Income tax expense
 

 

 

 

 

Net income (loss)
 
$
(98,651
)
 
$
19,740

 
$
(85,988
)
 
$
66,248

 
$
(98,651
)



22


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the nine months ended September 30, 2014
(in thousands)
 
Resources
 
Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
3,469

 
$
490,839

 
$
38,172

 
$

 
$
532,480

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 
344

 
56,440

 
14,880

 

 
71,664

Gathering and transportation
 
1

 
73,045

 
3,427

 

 
76,473

Depletion, depreciation and amortization
 
2,542

 
184,899

 
14,000

 

 
201,441

Accretion of discount on asset retirement obligations
 
13

 
1,564

 
508

 

 
2,085

General and administrative
 
(2,332
)
 
51,006

 
2,227

 

 
50,901

Other operating items
 
(119
)
 
6,510

 
(9
)
 

 
6,382

    Total costs and expenses
 
449

 
373,464

 
35,033

 

 
408,946

Operating income
 
3,020

 
117,375

 
3,139

 

 
123,534

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(68,096
)
 

 
(2,010
)
 

 
(70,106
)
Loss on derivative financial instruments
 
(13,802
)
 

 
(1,094
)
 

 
(14,896
)
Other income (loss)
 
183

 
(21
)
 
14

 

 
176

Equity income
 

 

 
548

 

 
548

Net income from consolidated subsidiaries
 
117,951

 

 

 
(117,951
)
 

    Total other income (expense)
 
36,236

 
(21
)
 
(2,542
)
 
(117,951
)
 
(84,278
)
Income before income taxes
 
39,256

 
117,354

 
597

 
(117,951
)
 
39,256

Income tax expense
 

 

 

 

 

Net income
 
$
39,256

 
$
117,354

 
$
597

 
$
(117,951
)
 
$
39,256



23


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the nine months ended September 30, 2013
(in thousands)
 
Resources
 
Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
8,258

 
$
414,741

 
$
30,870

 
$

 
$
453,869

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 
2,363

 
42,993

 
12,653

 

 
58,009

Gathering and transportation
 

 
72,151

 
2,398

 

 
74,549

Depletion, depreciation and amortization
 
4,853

 
149,046

 
9,296

 

 
163,195

Impairment of oil and natural gas properties
 

 
10,707

 

 

 
10,707

Accretion of discount on asset retirement obligations
 
58

 
1,400

 
407

 

 
1,865

General and administrative
 
14,570

 
50,319

 
1,606

 

 
66,495

Gain on divestitures and other operating items
 
(25,675
)
 
(153,815
)
 
(13
)
 

 
(179,503
)
    Total costs and expenses
 
(3,831
)
 
172,801

 
26,347

 

 
195,317

Operating income
 
12,089

 
241,940

 
4,523

 

 
258,552

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(69,889
)
 

 
(1,882
)
 

 
(71,771
)
Gain (loss) on derivative financial instruments
 
19,782

 
(176
)
 
(431
)
 

 
19,175

Other income
 
182

 
150

 
8

 

 
340

Equity loss
 

 

 
(61,229
)
 

 
(61,229
)
Net income from consolidated subsidiaries
 
182,903

 

 

 
(182,903
)
 

    Total other income (expense)
 
132,978

 
(26
)
 
(63,534
)
 
(182,903
)
 
(113,485
)
Income (loss) before income taxes
 
145,067

 
241,914

 
(59,011
)
 
(182,903
)
 
145,067

Income tax expense
 

 

 

 

 

Net income (loss)
 
$
145,067

 
$
241,914

 
$
(59,011
)
 
$
(182,903
)
 
$
145,067



24


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Unaudited)
For the nine months ended September 30, 2014
 (in thousands)
 
 Resources
 
 Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
 Eliminations
 
 Consolidated
Operating Activities:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
(68,876
)
 
$
412,618

 
$
14,623

 
$

 
$
358,365

Investing Activities:
 
 
 
 
 
 
 
 
 
 
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
 
(1,996
)
 
(305,206
)
 
(3,521
)
 

 
(310,723
)
Proceeds from disposition of property and equipment
 
68,242

 
8,213

 
81

 

 
76,536

Restricted cash
 

 
(1,389
)
 

 

 
(1,389
)
Net changes in advances to joint ventures
 

 
(3,181
)
 

 

 
(3,181
)
Equity method investments
 

 
1,749

 

 

 
1,749

Distributions received from Compass
 
5,856

 

 

 
(5,856
)
 

Advances/investments with affiliates
 
100,228

 
(100,228
)
 

 

 

Net cash provided by (used in) investing activities
 
172,330

 
(400,042
)
 
(3,440
)
 
(5,856
)
 
(237,008
)
Financing Activities:
 
 
 
 
 
 
 
 
 
 
Borrowings under credit agreements
 
40,000

 

 

 

 
40,000

Repayments under credit agreements
 
(879,874
)
 

 
(5,096
)
 

 
(884,970
)
Proceeds received from issuance of 2022 Notes
 
500,000

 

 

 

 
500,000

Proceeds from issuance of common stock, net
 
271,760

 

 

 

 
271,760

Payment of common stock dividends
 
(40,604
)
 

 

 

 
(40,604
)
Compass cash distribution
 

 

 
(5,856
)
 
5,856

 

Deferred financing costs and other
 
(10,076
)
 

 

 

 
(10,076
)
Net cash provided by (used in) financing activities
 
(118,794
)
 

 
(10,952
)
 
5,856

 
(123,890
)
Net increase (decrease) in cash
 
(15,340
)
 
12,576

 
231

 

 
(2,533
)
Cash at beginning of period
 
81,840

 
(35,892
)
 
4,535

 

 
50,483

Cash at end of period
 
$
66,500

 
$
(23,316
)
 
$
4,766

 
$

 
$
47,950


25


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Unaudited)
For the nine months ended September 30, 2013
 (in thousands)
 
 Resources
 
 Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
 Eliminations
 
 Consolidated
Operating Activities:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
(25,317
)
 
$
234,460

 
$
14,228

 
$

 
$
223,371

Investing Activities:
 
 
 
 
 
 
 
 
 
 
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
 
(9,683
)
 
(1,140,212
)
 
(38,070
)
 

 
(1,187,965
)
Restricted cash
 

 
33,948

 

 

 
33,948

Equity method investments
 

 
(363
)
 

 

 
(363
)
Proceeds from disposition of property and equipment
 
244,500

 
501,233

 

 

 
745,733

Distributions received from Compass
 
3,825

 

 

 
(3,825
)
 

Net changes in advances to joint ventures
 

 
10,055

 

 

 
10,055

Advances/investments with affiliates
 
(368,920
)
 
368,920

 

 

 

Net cash used in investing activities
 
(130,278
)
 
(226,419
)
 
(38,070
)
 
(3,825
)
 
(398,592
)
Financing Activities:
 
 
 
 
 
 
 
 
 
 
Borrowings under credit agreements
 
967,766

 

 
36,757

 

 
1,004,523

Repayments under credit agreements
 
(774,920
)
 

 
(2,550
)
 

 
(777,470
)
Proceeds from issuance of common stock
 
1,712

 

 

 

 
1,712

Payment of common stock dividends
 
(32,237
)
 

 

 

 
(32,237
)
Compass cash distribution
 

 

 
(3,825
)
 
3,825

 

Deferred financing costs and other
 
(33,222
)
 

 
(236
)
 

 
(33,458
)
Net cash provided by financing activities
 
129,099

 

 
30,146

 
3,825

 
163,070

Net increase (decrease) in cash
 
(26,496
)
 
8,041

 
6,304

 

 
(12,151
)
Cash at beginning of period
 
65,791

 
(20,147
)
 

 

 
45,644

Cash at end of period
 
$
39,295

 
$
(12,106
)
 
$
6,304

 
$

 
$
33,493


26


15.Subsequent event

On October 6, 2014, we entered into an agreement to sell our 25.5% economic interest in Compass to HGI for $118.8 million in cash. We intend to use the proceeds from this transaction to reduce indebtedness under the revolving commitment of the EXCO Resources Credit Agreement. In addition, our consolidated indebtedness will be further reduced by our proportionate share of the Compass's indebtedness upon closing of the sale. As of September 30, 2014, we proportionally consolidated $83.2 million of indebtedness related to Compass Production Partners Credit Agreement. Our borrowing base under the EXCO Resources Credit Agreement will not be affected by this sale since Compass is not a guarantor subsidiary. This transaction is expected to close during the fourth quarter of 2014. We do not expect the sale of our interest in Compass to significantly alter the relationship between our capitalized costs and proved reserves and would therefore be accounted for as an adjustment of capitalized costs with no gain or loss recognized in accordance with Rule 4-10(c)(6)(i) of Regulation S-X.

At the closing, EXCO and HGI will terminate the existing operating and administrative services agreements and enter into a customary transition services agreement pursuant to which EXCO will provide certain transition services to Compass for up to nine months following the closing date. In addition, following the closing, EXCO will no longer be required to offer acquisition opportunities to Compass or any of its affiliates.

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,” “us,” and “our” 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 ("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 derivative financial instruments; 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 results of operations or our 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, including, but not limited to:

fluctuations in the prices of oil, natural gas and natural gas liquids;
the availability of oil, natural gas and natural gas liquids;
future capital requirements and availability of financing;
our ability to meet our current and future debt service obligations;
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;
cash flow and liquidity;
timing and amount of future production of oil and natural gas;
availability of drilling and production equipment;

27


availability of water 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;
litigation;
competition;
our ability to attract and retain key personnel, including our search for a chief executive officer;
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 and counterparties to our derivative financial instruments;
decisions whether or not to enter into 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; and
our ability to effectively integrate companies and properties that we acquire.
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 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, 2013, filed with the Securities and Exchange Commission ("SEC") on February 26, 2014.
Our revenues, operating results and financial condition depend substantially on prevailing prices for oil and natural gas and the availability of capital. 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.
Our primary strategy focuses on the exploitation and development of our shale resource plays, while continuing to evaluate complementary acquisitions that meet our strategic and financial objectives. We plan to carry out this strategy by leveraging our management and technical team’s experience, exploiting our multi-year inventory of development drilling locations in our shale plays, actively seeking acquisition opportunities, managing our liquidity and enhancing financial flexibility. We believe this will allow us to create long-term value for our shareholders.
Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. We attempt to offset the impact of this natural decline by implementing drilling and exploitation projects to identify and develop additional reserves and adding reserves through complementary acquisitions.
Recent developments
Rights Offering
We closed a rights offering and related private placement of our common stock ("Rights Offering") on January 17, 2014 which resulted in the issuance of 54,574,734 shares of common stock for gross proceeds of $272.9 million. In connection with the Rights Offering, we entered into investment agreements ("Investment Agreements") with certain affiliates of WL Ross & Co. LLC ("WL Ross") and Hamblin Watsa Investment Counsel Ltd. ("Hamblin Watsa") pursuant to which, subject to the terms and conditions thereof, each of them severally agreed to subscribe for and purchase, in a private placement, its respective pro rata portion of shares under the basic subscription right and all unsubscribed shares under the over-subscription privilege

28


subject to the pro rata allocation among the subscription rights holders who elected to exercise their over-subscription privilege. In connection with the Rights Offering and related transactions under the Investment Agreements, WL Ross and Hamblin Watsa purchased 19,599,973 and 6,726,712 shares, respectively, pursuant to their basic subscription rights and the over-subscription privilege. After giving effect to the Rights Offering, WL Ross and Hamblin Watsa owned 18.7% and 6.4%, respectively of the Company's outstanding common shares as of January 17, 2014. We used the proceeds to reduce outstanding indebtedness under our credit agreement ("EXCO Resources Credit Agreement"), including the remainder of the asset sale requirement as well as a portion of the indebtedness outstanding under the revolving commitment.
Permian Basin transaction
On March 24, 2014, we closed a purchase and sale agreement with a private party for the sale of our interest in certain non-operated assets in the Permian Basin including producing wells and undeveloped acreage for approximately $68.2 million, after final purchase price adjustments. The effective date of the transaction was January 1, 2014. Proceeds from the sale were used to reduce outstanding indebtedness under the EXCO Resources Credit Agreement.
2022 Notes
On April 16, 2014, we completed a public offering of $500.0 million in aggregate principal amount of senior unsecured notes due April 15, 2022 ("2022 Notes"). We received net proceeds of approximately $490.0 million after offering fees and expenses. The 2022 Notes bear interest at a rate of 8.5% per annum, payable in arrears on April 15 and October 15 of each year. We used the net proceeds from the 2022 Notes to repay indebtedness under the EXCO Resources Credit Agreement, including the $297.8 million outstanding principal balance on the term loan ("Term Loan") and the remaining proceeds were used to reduce outstanding indebtedness under the revolving commitment of the EXCO Resources Credit Agreement.
Compass Production Partners sale
On October 6, 2014, we entered into an agreement to sell our 25.5% economic interest in Compass Production Partners, LP ("Compass") to an affiliate of Harbinger Group, Inc. ("HGI") for $118.8 million in cash. We intend to use the proceeds from this transaction to reduce indebtedness under the revolving commitment of the EXCO Resources Credit Agreement. In addition, our consolidated indebtedness will be reduced by our proportionate share of Compass's indebtedness upon closing of the sale. As of September 30, 2014, we proportionally consolidated $83.2 million of indebtedness related to Compass's credit agreement ("Compass Production Partners Credit Agreement"). Our borrowing base under the EXCO Resources Credit Agreement will not be affected by this sale since Compass is not a guarantor subsidiary. This transaction is expected to close during the fourth quarter of 2014.

Critical accounting policies

We consider accounting policies related to our estimates of proved reserves, accounting for oil and natural gas properties, derivatives, business combinations, share-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 time the estimates were made. However, these estimates could change materially if different information or assumptions are used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in EXCO's Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on February 26, 2014.

29


Our results of operations

A summary of key financial data for the three and nine months ended September 30, 2014 and 2013 related to our results of operations is presented below:
 
 
Three Months Ended September 30,
 
Quarter to quarter change
 
Nine Months Ended September 30,
 
Period to period change
(dollars in thousands, except per unit prices)
 
2014
 
2013
 
 
2014
 
2013
 
Production:
 
 
 
 
 
 
 
 
 
 
 
 
Oil (Mbbls)
 
537

 
383

 
154

 
1,709

 
535

 
1,174

Natural gas (Mmcf)
 
29,359

 
39,268

 
(9,909
)
 
93,087

 
116,556

 
(23,469
)
Natural gas liquids (Mbbls)
 
62

 
53

 
9

 
186

 
178

 
8

Total production (Mmcfe) (1)
 
32,953

 
41,884

 
(8,931
)
 
104,457

 
120,834

 
(16,377
)
Average daily production (Mmcfe)
 
358

 
455

 
(97
)
 
383

 
443

 
(60
)
Revenues before derivative financial instrument activities:
Oil
 
$
50,746

 
$
39,297

 
$
11,449

 
$
159,131

 
$
52,155

 
$
106,976

Natural gas
 
98,595

 
124,319

 
(25,724
)
 
367,747

 
395,462

 
(27,715
)
Natural gas liquids
 
1,701

 
1,698

 
3

 
5,602

 
6,252

 
(650
)
Total revenues
 
$
151,042

 
$
165,314

 
$
(14,272
)
 
$
532,480

 
$
453,869

 
$
78,611

Oil and natural gas derivative financial instruments:
Gain (loss) on derivative financial instruments
 
$
42,844

 
$
7,443

 
$
35,401

 
$
(14,896
)
 
$
19,175

 
$
(34,071
)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)
 
$
94.50

 
$
102.60

 
$
(8.10
)
 
$
93.11

 
$
97.49

 
$
(4.38
)
Natural gas (per Mcf)
 
3.36

 
3.17

 
0.19

 
3.95

 
3.39

 
0.56

Natural gas liquids (per Bbl)
 
27.44

 
32.04

 
(4.60
)
 
30.12

 
35.12

 
(5.00
)
Natural gas equivalent (per Mcfe)
 
4.58

 
3.95

 
0.63

 
5.10

 
3.76

 
1.34

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas operating costs
 
$
14,099

 
$
17,187

 
$
(3,088
)
 
$
48,713

 
$
42,706

 
$
6,007

Production and ad valorem taxes
 
7,978

 
6,074

 
1,904

 
22,951

 
15,303

 
7,648

Gathering and transportation
 
25,822

 
26,665

 
(843
)
 
76,473

 
74,549

 
1,924

Depletion
 
63,566

 
72,673

 
(9,107
)
 
197,102

 
157,030

 
40,072

Depreciation and amortization
 
1,347

 
1,826

 
(479
)
 
4,339

 
6,165

 
(1,826
)
General and administrative (2)
 
14,059

 
21,937

 
(7,878
)
 
50,901

 
66,495

 
(15,594
)
Interest expense, net
 
23,974

 
36,474

 
(12,500
)
 
70,106

 
71,771

 
(1,665
)
Costs and expenses (per Mcfe):
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas operating costs
 
$
0.43

 
$
0.41

 
$
0.02

 
$
0.47

 
$
0.35

 
$
0.12

Production and ad valorem taxes
 
0.24

 
0.15

 
0.09

 
0.22

 
0.13

 
0.09

Gathering and transportation
 
0.78

 
0.64

 
0.14

 
0.73

 
0.62

 
0.11

Depletion
 
1.93

 
1.74

 
0.19

 
1.89

 
1.30

 
0.59

Depreciation and amortization
 
0.04

 
0.04

 

 
0.04

 
0.05

 
(0.01
)
General and administrative
 
0.43

 
0.52

 
(0.09
)
 
0.49

 
0.55

 
(0.06
)
Net income (loss)
 
$
41,569

 
$
(98,651
)
 
$
140,220

 
$
39,256

 
$
145,067

 
$
(105,811
)

(1)
Mmcfe is calculated by converting one barrel of oil or natural gas liquids ("NGLs") into six Mcf of natural gas.
(2)
Share-based compensation expense included in general and administrative expense was $1.1 million and $3.2 million for the three months ended September 30, 2014 and 2013, respectively, and $4.4 million and $9.5 million for the nine months ended September 30, 2014 and 2013, respectively.
The following is a discussion of our financial condition and results of operations for the three and nine months ended September 30, 2014 and 2013.
The comparability of our results of operations for September 30, 2014 and 2013 was affected by:

30



the acquisitions of Haynesville and Eagle Ford assets during the third quarter of 2013;
the formation of Compass during the first quarter of 2013;
the sale of our equity interest in TGGT Holdings, LLC ("TGGT") during the fourth quarter of 2013;
fluctuations in oil, natural gas and NGL prices, which impact our oil and natural gas reserves, revenues, cash flows and net income or loss;
impairments of our oil and natural gas properties during 2013;
mark-to-market gains and losses from our derivative financial instruments;
changes in proved reserves and production volumes and their impact on depletion;
the impact of declining natural gas production volumes from our reduced horizontal drilling activities in certain shale formations; and
significant changes in our capital structure as a result of the Rights Offering and debt financing transactions.
General
The availability of a ready market and the prices for oil, natural gas and NGLs are dependent upon a number of factors that are beyond our control. These factors include, among other things:

the level of domestic and global production and economic activity;
the domestic supply of natural gas;
the inability to export domestic oil and natural gas;
the level of domestic and industrial demand for natural gas for utilities and manufacturing operations;
the available capacity at natural gas storage facilities and quantities of inventories in storage;
the availability of imported oil and natural gas;
actions taken by foreign oil producing nations;
the cost and availability of natural gas pipelines with adequate capacity and other transportation facilities;
the cost and availability of other competitive fuels;
fluctuating and seasonal demand for oil, natural gas and refined products;
the extent of governmental regulation and taxation (under both present and future legislation) of the exploration, production, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and substitute fuels; and
trends in fuel use and government regulations that encourage less fuel use and encourage or mandate alternative fuel use.
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.

Presentation of results of operations
Our discussion of production, revenues and direct operating expenses is based on our producing regions and Compass. Compass includes conventional non-shale assets in East Texas, North Louisiana and the Permian Basin. Prior to the formation of Compass on February 14, 2013, the operating results of the properties contributed by EXCO were included within the East Texas/North Louisiana and Other regions in our discussion of production, revenues and direct operating expenses. The operating results of Compass represent our proportionate interest subsequent to its formation on February 14, 2013. The anticipated sale of our interest in Compass during the fourth quarter of 2014 will have an impact on our results of operations in future periods. We closed the acquisition of assets in the Eagle Ford shale and formed our South Texas region on July 31, 2013.
Oil and natural gas production, revenues and prices
The following tables present our production, revenue and average sales prices for the three and nine months ended September 30, 2014 and 2013:

31


 
 
Three Months Ended September 30,
 
 
 
 
 
 
 
 
2014
 
2013
 
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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
East Texas/North Louisiana
 
22,245

 
$
79,874

 
$
3.59

 
31,284

 
$
101,375

 
$
3.24

 
(9,039
)
 
$
(21,501
)
 
$
0.35

South Texas
 
3,241

 
45,829

 
14.14

 
2,263

 
33,750

 
14.91

 
978

 
12,079

 
(0.77
)
Appalachia
 
5,148

 
13,279

 
2.58

 
5,846

 
17,825

 
3.05

 
(698
)
 
(4,546
)
 
(0.47
)
Other
 
48

 
174

 
3.63

 
30

 
138

 
4.60

 
18

 
36

 
(0.97
)
Compass
 
2,271

 
11,886

 
5.23

 
2,461

 
12,226

 
4.97

 
(190
)
 
(340
)
 
0.26

        Total
 
32,953

 
$
151,042

 
$
4.58

 
41,884

 
$
165,314

 
$
3.95

 
(8,931
)
 
$
(14,272
)
 
$
0.63

 
 
Nine Months Ended September 30,
 
 
 
 
 
 
 
 
2014
 
2013
 
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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
East Texas/North Louisiana
 
70,843

 
$
294,352

 
$
4.15

 
94,583

 
$
320,960

 
$
3.39

 
(23,740
)
 
$
(26,608
)
 
$
0.76

South Texas
 
10,320

 
141,537

 
13.71

 
2,263

 
33,750

 
14.91

 
8,057

 
107,787

 
(1.20
)
Appalachia
 
16,273

 
54,952

 
3.38

 
16,752

 
60,032

 
3.58

 
(479
)
 
(5,080
)
 
(0.20
)
Other
 
309

 
3,468

 
11.22

 
1,057

 
8,258

 
7.81

 
(748
)
 
(4,790
)
 
3.41

Compass
 
6,712

 
38,171

 
5.69

 
6,179

 
30,869

 
5.00

 
533

 
7,302

 
0.69

        Total
 
104,457

 
$
532,480

 
$
5.10

 
120,834

 
$
453,869

 
$
3.76

 
(16,377
)
 
$
78,611

 
$
1.34

Production for the three months ended September 30, 2014 decreased by 8.9 Bcfe, or 21%, as compared with the same period in 2013. The decrease in production in the East Texas/North Louisiana region was primarily due to production declines from changes in our drilling program. The production declines were primarily the result of reduced development activities within this region compared to periods prior to 2013. Our drilling activities in the Haynesville shale resulted in seven wells turned-to-sales for the three months ended September 30, 2014 (including two wells turned-to-sales on the last day of the quarter) compared to five wells turned-to-sales for the three months ended September 30, 2013. As of September 30, 2014, we had 16 wells in the East Texas/North Louisiana region that were drilled and waiting on completion, most of which will be turned-to-sales during the fourth quarter of 2014. The increase in production in the South Texas region was primarily the result of more days of production in the current period as the acquisition of these properties occurred on July 31, 2013. Our drilling activities in the Eagle Ford shale resulted in 14 wells turned-to-sales for the three months ended September 30, 2014 compared to 13 wells turned-to-sales for the three months ended September 30, 2013. As of September 30, 2014, we had 31 wells in the South Texas region that were drilled and waiting on completion, most of which will be turned-to-sales during the fourth quarter of 2014. The wells turned-to-sales for the three months ended September 30, 2013 were in various stages of development as of the acquisition date of the Eagle Ford assets. The decrease in production of 0.7 Bcfe in the Appalachia region was a result of production declines following the suspension of our drilling program during the second half of 2013.
Oil and natural gas revenues for the three months ended September 30, 2014 decreased by $14.3 million, or 9%, as compared with the same period in 2013. The decrease in revenues was primarily the result of a decrease in natural gas production partially offset by increases in natural gas prices and oil production. Our average natural gas sales price increased 6% to $3.36 per Mcf for the three months ended September 30, 2014 from $3.17 per Mcf for the three months ended September 30, 2013. Our average sales price for natural gas during 2014 was positively impacted by higher market prices and was partially offset by the widening of differentials in Appalachia as a result of an oversupply of natural gas in the Northeast region. Our average sales price of oil per Bbl decreased 8% to $94.50 per Bbl for the three months ended September 30, 2014 from $102.60 per Bbl for the three months ended September 30, 2013. Our average sales price for oil in the South Texas region is most closely correlated to the Louisiana Light Sweet ("LLS") price index and is presented net of marketing, gathering and transportation costs. Our average sales price of natural gas liquids per Bbl decreased 14% to $27.44 per Bbl for the three months ended September 30, 2014 from $32.04 per Bbl for the three months ended September 30, 2013.
Production for the nine months ended September 30, 2014 decreased by 16.4 Bcfe, or 14%, as compared with the same period in 2013. The decrease in production in the East Texas/North Louisiana region was primarily due to production declines

32


resulting from changes in our drilling program and the contribution of properties to Compass. The production declines were primarily the result of reduced development activities within this region compared to periods prior to 2013. Our drilling activities in the Haynesville shale resulted in 21 wells turned-to-sales for the nine months ended September 30, 2014 compared to 39 wells turned-to-sales for the nine months ended September 30, 2013. The wells turned-to-sales for the nine months ended September 30, 2013 primarily consisted of wells drilled during 2012. The increase in production in the South Texas region was primarily the result of more days of production in the current period as the acquisition of these properties occurred on July 31, 2013. Our drilling activities in the Eagle Ford shale resulted in 40 wells turned-to-sales for the nine months ended September 30, 2014 compared to 13 wells turned-to-sales for the nine months ended September 30, 2013. The decrease in production of 0.5 Bcfe in the Appalachia region was a result of natural production declines. The decrease in production in the Other region was primarily the result of the contribution of properties in the Permian Basin to Compass. The increase in our proportionate share of Compass's production was primarily due to fewer days of production in the prior year as a result of its formation on February 14, 2013.
Oil and natural gas revenues for the nine months ended September 30, 2014 increased by $78.6 million, or 17%, as compared with the same period in 2013. The increase in revenues was primarily the result of the acquisition of Haynesville and Eagle Ford assets and an increase in natural gas prices. Our average natural gas sales price increased 17% to $3.95 per Mcf for the nine months ended September 30, 2014 from $3.39 per Mcf for the nine months ended September 30, 2013. Our average sales price for natural gas during the nine months ended September 30, 2014 was positively impacted by higher market prices and was partially offset by the widening of differentials in Appalachia as a result of an oversupply of natural gas in the Northeast region. Our average sales price of oil per Bbl decreased 4% to $93.11 per Bbl for the nine months ended September 30, 2014 from $97.49 per Bbl for the nine months ended September 30, 2013. Our average sales price of natural gas liquids per Bbl decreased 14% to $30.12 per Bbl for the nine months ended September 30, 2014 from $35.12 per Bbl for the nine months ended September 30, 2013.
Oil and natural gas operating costs
The following tables present our operating costs for the three and nine months ended September 30, 2014 and 2013:
 
 
Three Months Ended September 30,
 
 
 
 
 
 
 
 
2014
 
2013
 
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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
East Texas/North Louisiana
 
$
4,377

 
$
968

 
$
5,345

 
$
4,125

 
$
509

 
$
4,634

 
$
252

 
$
459

 
$
711

South Texas
 
825

 
49

 
874

 
5,139

 

 
5,139

 
(4,314
)
 
49

 
(4,265
)
Appalachia
 
3,698

 
52

 
3,750

 
3,832

 

 
3,832

 
(134
)
 
52

 
(82
)
Other
 
47

 

 
47

 
69

 

 
69

 
(22
)
 

 
(22
)
Compass
 
3,590

 
493

 
4,083

 
3,281

 
232

 
3,513

 
309

 
261

 
570

Total
 
$
12,537

 
$
1,562

 
$
14,099

 
$
16,446

 
$
741

 
$
17,187

 
$
(3,909
)
 
$
821

 
$
(3,088
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30,
 
 
 
 
 
 
 
 
2014
 
2013
 
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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
East Texas/North Louisiana
 
$
0.20

 
$
0.04

 
$
0.24

 
$
0.13

 
$
0.02

 
$
0.15

 
$
0.07

 
$
0.02

 
$
0.09

South Texas
 
0.25

 
0.02

 
0.27

 
2.27

 

 
2.27

 
(2.02
)
 
0.02

 
(2.00
)
Appalachia
 
0.72

 
0.01

 
0.73

 
0.66

 

 
0.66

 
0.06

 
0.01

 
0.07

Other
 
0.98

 

 
0.98

 
2.30

 

 
2.30

 
(1.32
)
 

 
(1.32
)
Compass
 
1.58

 
0.22

 
1.80

 
1.33

 
0.09

 
1.42

 
0.25

 
0.13

 
0.38

Operating costs per Mcfe
 
$
0.38

 
$
0.05

 
$
0.43

 
$
0.39

 
$
0.02

 
$
0.41

 
$
(0.01
)
 
$
0.03

 
$
0.02


33


 
 
Nine Months Ended September 30,
 
 
 
 
 
 
 
 
2014
 
2013
 
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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
East Texas/North Louisiana
 
$
13,339

 
$
3,409

 
$
16,748

 
$
13,047

 
$
3,397

 
$
16,444

 
$
292

 
$
12

 
$
304

South Texas
 
9,274

 
347

 
9,621

 
5,139

 

 
5,139

 
4,135

 
347

 
4,482

Appalachia
 
10,782

 
58

 
10,840

 
10,255

 

 
10,255

 
527

 
58

 
585

Other
 
266

 

 
266

 
1,591

 

 
1,591

 
(1,325
)
 

 
(1,325
)
Compass
 
9,662

 
1,576

 
11,238

 
8,263

 
1,014

 
9,277

 
1,399

 
562

 
1,961

Total
 
$
43,323

 
$
5,390

 
$
48,713

 
$
38,295

 
$
4,411

 
$
42,706

 
$
5,028

 
$
979

 
$
6,007

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
 
 
 
 
 
 
2014
 
2013
 
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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
East Texas/North Louisiana
 
$
0.19

 
$
0.05

 
$
0.24

 
$
0.14

 
$
0.04

 
$
0.18

 
$
0.05

 
$
0.01

 
$
0.06

South Texas
 
0.90

 
0.03

 
0.93

 
2.27

 

 
2.27

 
(1.37
)
 
0.03

 
(1.34
)
Appalachia
 
0.66

 

 
0.66

 
0.61

 

 
0.61

 
0.05

 

 
0.05

Other
 
0.86

 

 
0.86

 
1.51

 

 
1.51

 
(0.65
)
 

 
(0.65
)
Compass
 
1.44

 
0.23

 
1.67

 
1.34

 
0.16

 
1.50

 
0.10

 
0.07

 
0.17

Operating costs per Mcfe
 
$
0.41

 
$
0.06

 
$
0.47

 
$
0.32

 
$
0.03

 
$
0.35

 
$
0.09

 
$
0.03

 
$
0.12

Oil and natural gas operating costs for the three months ended September 30, 2014 decreased by $3.1 million, or 18%, as compared with the same period in 2013. The decrease in oil and natural gas operating costs was primarily due to cost reduction initiatives in our South Texas region including decreased saltwater disposal costs, improved efficiencies and reduced reliance on third-party contractors. Oil and natural gas operating costs for the nine months ended September 30, 2014 increased by $6.0 million, or 14%, as compared with the same period in 2013. The increase in oil and natural gas operating costs was primarily due to the acquisition of the Eagle Ford assets and partially offset by the contribution of properties to Compass.
Oil and natural gas operating costs for the three months ended September 30, 2014 were $0.43 per Mcfe compared to $0.41 per Mcfe for the three months ended September 30, 2013. The net increase in oil and natural gas operating costs per Mcfe is primarily attributable to lower production in relation to certain fixed lease operating expenses. Oil and natural gas operating costs for the nine months ended September 30, 2014 were $0.47 per Mcfe compared to $0.35 per Mcfe for the nine months ended September 30, 2013. The net increase in oil and natural gas operating costs per Mcfe is primarily attributable to lower production in relation to certain fixed lease operating expenses as well as higher costs associated with our oil production in the South Texas region. This increase was partially offset by the contribution of properties to Compass, which typically have a higher average cost per Mcfe compared to the average for the rest of our properties.
Gathering and transportation
Gathering and transportation expenses for the three months ended September 30, 2014 decreased by $0.8 million, or 3%, as compared with the same period in 2013. Gathering and transportation expenses were $0.78 per Mcfe for the three months ended September 30, 2014, as compared to $0.64 per Mcfe for the three months ended September 30, 2013. Gathering and transportation expenses for the nine months ended September 30, 2014 increased by $1.9 million, or 3%, as compared with the same period in 2013. Gathering and transportation expenses were $0.73 per Mcfe for the nine months ended September 30, 2014, as compared to $0.62 per Mcfe for the nine months ended September 30, 2013. The increase in gathering and transportation expenses on a per Mcfe basis was primarily due to lower volumes in relation to fixed costs under firm transportation contracts in the East Texas/North Louisiana region. In addition, a marketing arrangement with a significant purchaser of our Haynesville shale production volumes was revised in April 2014 resulting in higher gathering and transportation expenses.

34


In our South Texas region, we report our gathering and transportation charges as part of our realized price within revenues based on the net proceeds received from the purchaser. In our East Texas/North Louisiana and Appalachia regions, we either report our gathering and transportation charges as part of our realized prices within revenues or as gathering and transportation expense depending on the type of sales agreement.
Production and ad valorem taxes

The following tables present our production and ad valorem taxes on a percentage of revenue basis and per Mcfe basis for the three and nine months ended September 30, 2014 and 2013:
    
 
 
Three Months Ended September 30,
 
 
2014
 
2013
(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:
 
 
 
 
 
 
 
 
 
 
 
 
East Texas/North Louisiana
 
$
2,662

 
3.3
 %
 
$
0.12

 
$
2,038

 
2.0
%
 
$
0.07

South Texas
 
3,667

 
8.0

 
1.13

 
2,021

 
6.0

 
0.89

Appalachia
 
524

 
3.9

 
0.10

 
666

 
3.7

 
0.11

Other
 
(77
)
 
(44.3
)
 
(1.60
)
 
10

 
7.2

 
0.33

Compass
 
1,202

 
10.1

 
0.53

 
1,339

 
11.0

 
0.54

Total
 
$
7,978

 
5.3
 %
 
$
0.24

 
$
6,074

 
3.7
%
 
$
0.15

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
(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:
 
 
 
 
 
 
 
 
 
 
 
 
East Texas/North Louisiana
 
$
7,375

 
2.5
 %
 
$
0.10

 
$
7,071

 
2.2
%
 
$
0.07

South Texas
 
10,128

 
7.2

 
0.98

 
2,021

 
6.0

 
0.89

Appalachia
 
1,728

 
3.1

 
0.11

 
2,066

 
3.4

 
0.12

Other
 
79

 
2.3

 
0.26

 
768

 
9.3

 
0.73

Compass
 
3,641

 
9.5

 
0.54

 
3,377

 
10.9

 
0.55

Total
 
$
22,951

 
4.3
 %
 
$
0.22

 
$
15,303

 
3.4
%
 
$
0.13

Production and ad valorem taxes for the three months ended September 30, 2014 increased by $1.9 million, or 31%, as compared with the same period in 2013. Production and ad valorem taxes for the nine months ended September 30, 2014 increased by $7.6 million, or 50%, as compared with the same period in 2013. The increase was primarily attributable to higher production and ad valorem taxes associated with oil production in the South Texas region. Additionally, this increase was due to the expiration of severance tax holidays on certain Haynesville shale wells in the East Texas/North Louisiana region.
Production and ad valorem tax rates per Mcfe were $0.24 and $0.15 for the three months ended September 30, 2014 and 2013, respectively. Production and ad valorem tax rates per Mcfe were $0.22 and $0.13 for the nine months ended September 30, 2014 and 2013, respectively. The rate per Mcfe increased for each period due to higher production and ad valorem taxes per Mcfe associated with oil production in the South Texas region and the expiration of severance tax holidays on certain Haynesville shale wells in the East Texas/North Louisiana region. Also, the increase for the three months ended September 30, 2014 compared to the same period in 2013 was partially due to the higher severance tax rate for wells in the state of Louisiana that do not currently receive a severance tax exemption.
In our East Texas/North Louisiana region, we currently receive severance tax holidays on certain Haynesville shale wells which reduce the effective rate of these taxes. Our horizontal wells in the state of Louisiana are eligible for an exemption from severance taxes for the earlier of two years from the date of first production or until payout of qualified costs. In July 2013, the state of Louisiana decreased its severance tax rate to $0.118 per Mcf from $0.148 per Mcf. In July 2014, the state of Louisiana increased its severance tax rate to $0.163 per Mcf.

35


Depletion, depreciation and amortization
Depletion expense for the three months ended September 30, 2014 decreased by $9.1 million, or 13%, as compared with the same period in 2013 primarily due to a decrease in production. On a per Mcfe basis, the depletion rate for the three months ended September 30, 2014 was $1.93 per Mcfe, compared with $1.74 per Mcfe in the same period in 2013. The increase in the depletion rate was primarily due to an increase in our depletable base from developmental activities and higher future development costs associated with additional proved undeveloped reserves.
Depletion expense for the nine months ended September 30, 2014 increased by $40.1 million, or 26%, as compared with the same period in 2013 primarily due to the acquisition of assets in the Haynesville and Eagle Ford shale during the third quarter of 2013. On a per Mcfe basis, the depletion rate for the nine months ended September 30, 2014 was $1.89 per Mcfe, compared with $1.30 per Mcfe in the same period in 2013. The increase in the depletion rate was primarily due to the acquisition of assets in the Haynesville and Eagle Ford shale during the third quarter of 2013 which increased our depletable base and higher future development costs associated with additional proved undeveloped reserves. The oil producing assets in the Eagle Ford shale result in a higher depletion rate when calculated on per Mcfe basis compared to the rest of our properties.
Depreciation and amortization costs for the three months ended September 30, 2014 decreased by $0.5 million, or 26%, as compared with the same period in 2013. The decrease was primarily due to reduced spending on certain corporate assets. Depreciation and amortization costs for the nine months ended September 30, 2014 decreased by $1.8 million, or 30%, as compared with the same period in 2013. The decrease was due to the contribution of gathering assets to Compass in the first quarter of 2013 and reduced spending on certain corporate assets.
Accretion of discount on asset retirement obligations for the three months ended September 30, 2014 increased $0.1 million, or 15%, compared with the same period in 2013 primarily due to our development of Haynesville and Eagle Ford assets. Accretion of discount on asset retirement obligations for the nine months ended September 30, 2014 increased by $0.2 million, or 12%, compared with the same period in 2013. The increase was primarily due to additional accretion of discount on asset retirement obligations of Haynesville and Eagle Ford assets acquired during the third quarter of 2013, partially offset by the contribution of properties to Compass in the first quarter of 2013.
Impairment of oil and natural gas properties
For the three and nine months ended September 30, 2014, we did not record an impairment to our oil and natural gas properties. For the three months ended September 30, 2013, we did not record an impairment to our oil and natural gas properties. For the nine months ended September 30, 2013, we recorded an impairment of $10.7 million to our oil and natural gas properties primarily due to low natural gas prices for the trailing twelve month period at the end of the first quarter of 2013.
General and administrative    
The following table presents our general and administrative expenses for the three and nine months ended September 30, 2014 and 2013:
 
 
Three Months Ended September 30,
 
 
 
Nine Months Ended September 30,
 
 
(in thousands, except per unit rate)
 
2014
 
2013
 
Quarter to quarter change
 
2014
 
2013
 
Period to period change
General and administrative costs:
 
 
 
 
 
 
 
 
 
 
 
 
Gross general and administrative expense
 
$
28,031

 
$
37,047

 
$
(9,016
)
 
$
92,908

 
$
108,760

 
$
(15,852
)
Technical services and service agreement charges
 
(6,365
)
 
(7,718
)
 
1,353

 
(19,148
)
 
(20,603
)
 
1,455

Operator overhead reimbursements
 
(3,628
)
 
(2,433
)
 
(1,195
)
 
(10,461
)
 
(7,599
)
 
(2,862
)
Capitalized salaries and share-based compensation
 
(3,979
)
 
(4,959
)
 
980

 
(12,398
)
 
(14,063
)
 
1,665

General and administrative expense
 
$
14,059

 
$
21,937

 
$
(7,878
)
 
$
50,901

 
$
66,495

 
$
(15,594
)
General and administrative expense per Mcfe
 
$
0.43

 
$
0.52

 
$
(0.09
)
 
$
0.49

 
$
0.55

 
$
(0.06
)
General and administrative expenses for the three and nine months ended September 30, 2014 decreased by $7.9 million, or 36%, and $15.6 million, or 23%, respectively, compared with the same periods in the prior year. Significant components of the changes in general and administrative expenses were a result of:

36


decreased personnel and employee relocation costs of $2.3 million and $5.1 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in the prior year. These decreases are primarily the result of a reduction in our workforce and the centralization of certain functions from the Appalachia region. The decrease for the nine months ended September 30, 2014 was partially offset by $2.2 million in severance costs associated with the reduction in our workforce during the second quarter of 2014.
decreased share-based compensation of $3.1 million and $6.2 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in the prior year. These decreases are primarily due to a reduction in headcount and the modification of share-based payments in connection with the retirement of a former executive in the prior year.
decreased various other gross general and administrative expenses of $3.6 million and $4.6 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in the prior year. These decreases reflect our efforts to reduce our general and administrative costs such as office expenses, travel and software licenses. We also incurred additional costs for legal and transition services related to the Haynesville and Eagle Ford acquisitions in 2013.
decreased technical services and service agreement recoveries of $1.4 million and $1.5 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in the prior year. These decreases were primarily a result of reduced headcount and increased focus on the development of assets that are not included in joint venture arrangements in which we can recover technical services including our operations in the South Texas region.
increased operator overhead reimbursements of $1.2 million and $2.9 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in the prior year. These increases are primarily associated with the additional operated wells acquired and developed in the Haynesville and Eagle Ford shales.
(Gain) loss on divestitures and other operating items
(Gain) loss on divestitures and other operating items was a net loss of $0.7 million for the three months ended September 30, 2014 compared with a net loss of $2.7 million for the three months ended September 30, 2013. The net loss for the three months ended September 30, 2014 primarily consisted of legal expenses. The net loss for the three months ended September 30, 2013 primarily related to transaction costs associated with the acquisition of Eagle Ford and Haynesville properties and legal expenses. (Gain) loss on divestitures and other operating items was a net loss of $6.4 million for the nine months ended September 30, 2014 compared with a net gain of $179.5 million for the nine months ended September 30, 2013. The net loss for the nine months ended September 30, 2014 primarily consisted of legal expenses. The net gain for the nine months ended September 30, 2013 was primarily related to the gain of $186.4 million as a result of the contribution of certain oil and natural gas properties to Compass. Partially offsetting the gain were transaction costs associated with the acquisition of Eagle Ford and Haynesville properties and legal expenses.
Interest expense, net
The following table presents our interest expense, net for the three and nine months ended September 30, 2014 and 2013:
 
 
Three Months Ended September 30,
 
 
 
Nine Months Ended September 30,
 
 
(in thousands)
 
2014
 
2013
 
Quarter to quarter change
 
2014
 
2013
 
Period to period change
Interest expense, net:
 
 
 
 
 
 
 
 
 
 
 
 
2018 Notes
 
$
14,399

 
$
14,374

 
$
25

 
$
43,179

 
$
43,105

 
$
74

2022 Notes
 
10,625

 

 
10,625

 
19,479

 

 
19,479

EXCO Resources Credit Agreement
 
1,607

 
11,339

 
(9,732
)
 
14,628

 
20,612

 
(5,984
)
Compass Production Partners Credit Agreement
 
610

 
686

 
(76
)
 
1,820

 
1,699

 
121

Amortization of deferred financing costs
 
1,854

 
15,462

 
(13,608
)
 
6,117

 
21,453

 
(15,336
)
Capitalized interest
 
(5,155
)
 
(5,447
)
 
292

 
(15,410
)
 
(15,264
)
 
(146
)
Other
 
34

 
60

 
(26
)
 
293

 
166

 
127

Total interest expense, net
 
$
23,974

 
$
36,474

 
$
(12,500
)
 
$
70,106

 
$
71,771

 
$
(1,665
)
Interest expense, net for the three months ended September 30, 2014 decreased from the same period in 2013 primarily due to a decrease in the amortization of deferred financing costs including accelerated costs of $13.2 million in the prior year as

37


a result of the amendments to the EXCO Resources Credit Agreement as well as lower average outstanding indebtedness. This was partially offset by higher average interest rates as a result of the issuance of the 2022 Notes.
Interest expense, net for the nine months ended September 30, 2014 decreased from the same period in 2013 primarily due to a decrease in the amortization of deferred financing costs and lower average outstanding indebtedness. This was partially offset by an increase in interest expense due to higher average interest rates as a result of the issuance of the 2022 Notes.
Derivative financial instruments
Our oil and natural gas derivative financial instruments resulted in net gains of $42.8 million and $7.4 million for the three months ended September 30, 2014 and 2013, respectively. Our oil and natural gas derivative financial instruments resulted in a net loss of $14.9 million and a net gain of $19.2 million for the nine months ended September 30, 2014 and 2013, respectively. Based on the nature of our derivative contracts, increases in the related commodity price typically result in a decrease to the value of our derivatives contracts. The significant fluctuations demonstrate the high volatility in oil and natural gas prices between each of the periods. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.
The following table presents our natural gas prices, before and after the impact of the cash settlement of our derivative financial instruments:
 
 
Three Months Ended September 30,
 
 
 
Nine Months Ended September 30,
 
 
Average realized pricing:
 
2014
 
2013
 
Quarter to quarter change
 
2014
 
2013
 
Period to period change
Natural gas equivalent (Mcfe)
 
$
4.58

 
$
3.95

 
$
0.63

 
$
5.10

 
$
3.76

 
$
1.34

Cash (payments) settlements on derivative financial instruments, per Mcfe
 
0.07

 
0.26

 
(0.19
)
 
(0.31
)
 
0.24

 
(0.55
)
Net price per Mcfe, including derivative financial instruments
 
$
4.65

 
$
4.21

 
$
0.44

 
$
4.79

 
$
4.00

 
$
0.79

Our total cash receipts for the three months ended September 30, 2014 were $2.3 million, or $0.07 per Mcfe, compared to $10.9 million, or $0.26 per Mcfe, for the three months ended September 30, 2013. Our total cash payments for the nine months ended September 30, 2014 were $32.2 million, or $0.31 per Mcfe, compared to cash receipts of $28.4 million, or $0.24 per Mcfe, for the nine months ended September 30, 2013. As noted above, the significant fluctuations between settlements on our derivative financial instruments demonstrate the volatility in commodity prices.
Equity income (loss)
Equity income (loss) was a net loss of $0.2 million and $85.3 million for the three months ended September 30, 2014 and 2013, respectively. Equity income (loss) was net income $0.5 million and a net loss of $61.2 million for the nine months ended September 30, 2014 and 2013, respectively. The increase in equity income in both periods presented was primarily due to an impairment of our investment in TGGT during the three months ended September 30, 2013. This was partially offset by equity income from our investment in TGGT prior to the sale of our interest on November 15, 2013.
Income taxes
Our effective income tax rate for the three and nine months ended September 30, 2014 and 2013 was zero, primarily due to prior losses arising from impairments of oil and natural gas properties which created deferred tax assets. These deferred tax assets have been fully reserved with valuation allowances. Our accumulated valuation allowance as of September 30, 2014 was approximately $874.8 million and can be used against future deferred financial income. 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 32.1% and 42.9% for the three and nine months ended September 30, 2014, respectively, and 37.9% and 50.3% for the three and nine months ended September 30, 2013, 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.

Our liquidity, capital resources and capital commitments
Overview

38


Our primary sources of capital resources and liquidity are internally generated cash flows from operations, borrowing capacity under the EXCO Resources Credit Agreement, dispositions of non-strategic assets, joint ventures and capital markets when conditions are favorable. Factors that could impact our liquidity, capital resources and capital commitments include the following:

the level of planned drilling activities;
the results of our ongoing drilling programs;
our ability to fund, finance or repay financing incurred in connection with acquisitions of oil and natural gas properties;
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, including increased costs as a result of high demand for services and materials related to the oil and natural gas industry;
reduced oil and natural gas revenues resulting from, among other things, depressed oil and natural gas prices and lower production from reductions to our drilling and development activities;
our ability to mitigate commodity price volatility with derivative financial instruments;
our ability to meet minimum volume commitments under firm transportation agreements and other fixed commitments;
potential acquisitions and/or dispositions of oil and natural gas properties or other assets, including our ability to obtain financing in order to fund the acquisition of properties under a participation agreement with a joint venture partner in the Eagle Ford shale;
reductions to our borrowing base; and
our ability to maintain compliance with debt covenants.
Recent events affecting liquidity
During the nine months ended September 30, 2014, we utilized the proceeds from the Rights Offering and the sale of certain assets in the Permian Basin to reduce indebtedness under the EXCO Resources Credit Agreement by $341.1 million. On April 16, 2014, we completed a public offering of $500.0 million in aggregate principal amount of senior unsecured notes due April 15, 2022. We received net proceeds of approximately $490.0 million after offering fees and expenses. We used a portion of the net proceeds to repay the $297.8 million outstanding principal balance on the Term Loan and the remaining proceeds were used to reduce indebtedness under the revolving commitment of the EXCO Resources Credit Agreement. Our borrowing base under the revolving commitment of the EXCO Resources Credit Agreement was established at $875.0 million in connection with the semi-annual borrowing base redetermination and the issuance of the 2022 Notes. As a result of these transactions, our liquidity improved from $224.6 million as of December 31, 2013 to $711.1 million as of September 30, 2014.
On October 6, 2014, we entered into an agreement to sell our 25.5% economic interest in Compass for $118.8 million in cash. The transaction is expected to close in the fourth quarter of 2014 and we intend to use the proceeds to reduce indebtedness under the revolving commitment of the EXCO Resources Credit Agreement, which will further improve our liquidity. Our borrowing base under the EXCO Resources Credit Agreement will not be affected by this sale since Compass is not a guarantor subsidiary. On October 21, 2014, we amended the EXCO Resources Credit Agreement which increased our borrowing base to $900.0 million.
While we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities and available borrowing capacity under the EXCO Resources Credit Agreement will be adequate to execute our corporate strategies and to meet debt service obligations, there are certain risks and uncertainties that could negatively impact our results of operations and financial condition. Significant reductions in our borrowing capacity as a result of a redetermination of our borrowing base could have an impact on our capital resources and liquidity. Accordingly, our ability to effectively manage our capital budget is critical to our financial condition, liquidity and results of operations.

39


The following table presents our liquidity as of September 30, 2014 and our pro forma liquidity as if the sale of our interest in Compass and the increase to our borrowing base had both occurred on September 30, 2014:
(in thousands)
 
September 30, 2014
 
Pro forma
EXCO Resources Credit Agreement
 
$
222,492

 
$
103,742

2018 Notes (1)
 
750,000

 
750,000

2022 Notes
 
500,000

 
500,000

Total debt (2)
 
$
1,472,492

 
$
1,353,742

Net debt
 
$
1,407,349

 
$
1,288,599

Borrowing base
 
$
875,000

 
$
900,000

Unused borrowing base (3)
 
$
645,935

 
$
789,685

Cash (4) (5)
 
$
65,143

 
$
65,143

Unused borrowing base plus cash
 
$
711,078

 
$
854,828


(1)
Excludes unamortized discount of $6.3 million as of September 30, 2014.
(2)
Excludes our proportionate share of the debt related to Compass of $83.2 million as of September 30, 2014.
(3)
Net of $6.6 million in letters of credit as of September 30, 2014.
(4)
Includes restricted cash of $22.0 million as of September 30, 2014.
(5)
Excludes our proportionate share of cash related to Compass of $4.8 million as of September 30, 2014.
Credit agreements and long-term debt
As of September 30, 2014, our consolidated debt consisted of the EXCO Resources Credit Agreement, the 2018 Notes, the 2022 Notes and our 25.5% proportionate share of the Compass Production Partners Credit Agreement (see "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements for a further description of each agreement). While our proportionate share of Compass's debt is consolidated, we are not a guarantor of the debt.
As of September 30, 2014, both EXCO and Compass were in compliance with the financial covenants contained in their respective credit agreements, which are presented in the following table. Management believes the following table contains important information related to our liquidity and compliance with the financial covenants of each agreement. However, the information is not complete and is qualified in its entirety by the terms of the EXCO Resources Credit Agreement and the Compass Production Partners Credit Agreement.
 
 
September 30, 2014
(dollars in millions)
 
Borrowing base
 
Outstanding
 
Covenant type (1)
 
Required ratio (2)
 
Actual ratio
EXCO Resources:
 
 
 
 
 
 
 
 
 
 
EXCO Resources Credit Agreement
 
$
875.0

 
$
222.5

 
Current ratio
 
> 1.0
 
2.5
 
 
 
 
 
 
Leverage ratio (4)
 
< 4.5
 
3.7
Compass Production Partners:
 
 
 
 
 
 
 
 
 
 
Compass Production Partners Credit Agreement (3)
 
$
400.0

 
$
327.0

 
Current ratio
 
> 1.0
 
2.8
 
 
 
 
 
 
Leverage ratio
 
< 4.5
 
3.5
(1)
As defined in the respective credit agreements.
(2)
Maximum leverage permitted or minimum coverage required per the respective credit agreement.
(3)
Our proportionate share of Compass's outstanding indebtedness was $83.2 million as of September 30, 2014.
(4)
Our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) would have been 3.4 to 1.0 on a pro forma basis as if the sale of our interest in Compass had occurred and the proceeds received were used to reduce indebtedness under the EXCO Resources Credit Agreement on September 30, 2014.
The 2018 Notes mature in September 2018 and have a fixed interest rate of 7.5%. The 2022 Notes mature in April 2022 and have a fixed interest rate of 8.5%. The indentures governing the 2018 Notes and 2022 Notes contain incurrence covenants which restrict our ability to incur additional indebtedness or pledge assets.
There are certain risks arising from volatility in oil and/or natural gas prices that could impact our ability to meet debt covenants in future periods. In particular, our leverage ratio, as defined in the EXCO Resources Credit Agreement, is computed

40


using a trailing 12 month computation of EBITDAX and only includes operations from non-guarantor subsidiaries and unconsolidated joint ventures to the extent that cash is distributed to entities under the credit agreement. As a result, our ability to maintain compliance with this covenant is negatively impacted when oil and/or natural gas prices and/or production declines over an extended period of time.
Capital expenditures
For the nine months ended September 30, 2014, our capital expenditures totaled $302.7 million, of which $249.6 million was related to drilling and development activities. Our development program during the nine months ended September 30, 2014 primarily focused on our properties in the Haynesville and Eagle Ford shales. During the nine months ended September 30, 2014, we operated three to six operated drilling rigs in the Haynesville shale focused on our core area in DeSoto Parish, Louisiana. In addition, we completed our 2014 drilling program in the Shelby area of East Texas which consisted of two operated drilling rigs. Our development program in the Eagle Ford shale focused on our core area in Zavala County, Texas and ranged from two to five operated drilling rigs during the nine months ended September 30, 2014. Our development program in the Eagle Ford shale also included limited drilling outside our core area as part of a farmout agreement.
Our capital expenditure program for the fourth quarter of 2014 will primarily focus on our properties in East Texas/North Louisiana and South Texas. Our development activities in the East Texas/North Louisiana region will focus on drilling and completion activities in the Haynesville and Bossier shales within DeSoto Parish, Louisiana and completions in the Shelby area of East Texas. Also, we have plans to continue our re-fracture stimulation program on certain mature Haynesville shale wells. Our development activities in the South Texas region will primarily focus on drilling and completion activities in the Eagle Ford shale within our core area and limited drilling outside of our core area as part of a farmout agreement. Our first centralized production facility in the region became operational in the fourth quarter of 2014 which allows us to begin production from certain wells that were waiting on completion as of September 30, 2014. We remain focused on efficiently managing our capital expenditures as part of our development program and allocating capital to projects that maximize our returns or meet our strategic objectives including the evaluation of other formations.
The following table presents our capital expenditures for the nine months ended September 30, 2014 and our forecasted capital expenditures for the remainder of 2014. These capital expenditures exclude Compass, which funded its capital expenditures through internally generated cash flows and its credit agreement.
 
 
Nine Months Ended
 
October - December Forecast
 
Full Year Forecast
(in thousands)
 
September 30, 2014
 
2014
 
2014
Capital expenditures:
 
 
 
 
 
 
Development capital expenditures
 
$
249,647

 
$
91,353

 
$
341,000

Field operations, gathering and water pipelines
 
16,926

 
5,074

 
22,000

Lease purchases
 
6,907

 
7,093

 
14,000

Seismic
 
337

 
1,663

 
2,000

Corporate and other
 
28,851

 
13,149

 
42,000

    Total
 
$
302,668

 
$
118,332

 
$
421,000

Capital commitments
During 2013, we entered into a participation agreement ("Participation Agreement") with a joint venture partner in the Eagle Ford shale to mitigate the impact of development expenditures on our capital resources and liquidity. EXCO is required to offer to purchase our joint venture partner's working interest in wells drilled that have been on production for approximately one year. These offers will be made on a quarterly basis for groups of wells based on a price defined in the Participation Agreement, subject to specific well criteria and return hurdles. These acquisitions are expected to increase the borrowing base under the revolving commitment of the EXCO Resources Credit Agreement and are expected to be funded with borrowings under the EXCO Resources Credit Agreement, cash flows from operations, or other financing arrangements. Our joint venture partner has the right to participate in certain wells drilled in the Eagle Ford shale outside of the core area, as defined under the Participation Agreement, however these wells are not included as part of the acquisition program. If our joint venture partner elects to participate in certain wells outside of our core area, we will share equally in the working interest of the well.
As of September 30, 2014, we have spud 70 wells and turned-to-sales 41 wells since the inception of the Participation Agreement which are expected to be included within acquisitions in future periods. During the fourth quarter of 2014, we expect to spud 14 wells and turn-to-sales 19 wells which will be included in future acquisitions. The timing of these acquisitions is dependent upon the date these wells are turned-to-sales, downtime during the year preceding the offer process

41


and other factors. Prior to the acquisitions in future periods, our average working interest in wells developed under this agreement is approximately 17% and our joint venture partner's average working interest is approximately 50%. The remaining working interest is held by other third-party owners and is not part of the acquisition program.
Our average drilling and completion costs for wells that have been turned-to-sales in the joint venture area are $7.4 million per well, of which our joint venture partner's share of these costs is approximately $3.8 million per well and our share of these costs prior to the acquisition is $1.3 million per well. Our estimated average drilling and completion costs for wells that have been recently spud in the joint venture area are estimated to be $7.1 million per well, of which our joint venture partner's share of these costs is approximately $3.6 million per well and our share of these costs prior to the acquisition is $1.2 million per well. The first offer for wells drilled under the Participation Agreement is expected to occur in the first quarter of 2015 and we estimate that up to 7 wells will qualify for the offer process. We currently estimate that 35 to 40 wells will qualify to be included in offers during 2015; however, the extent and timing of these acquisitions in future periods will be dependent on the terms and conditions of the offer process.

Historical sources and uses of funds

Our primary sources of cash for the nine months ended September 30, 2014 were cash flows from operations and proceeds received from the Rights Offering, the issuance of the 2022 Notes and the sale of non-core assets. As a result of these sources of cash, we were able to significantly reduce our outstanding indebtedness under the EXCO Resources Credit Agreement.
Net increases (decreases) in cash are summarized as follows:
 
 
Nine Months Ended September 30,
(in thousands)
 
2014
 
2013
Net cash provided by operating activities
 
$
358,365

 
$
223,371

Net cash used in investing activities
 
(237,008
)
 
(398,592
)
Net cash provided by (used in) financing activities
 
(123,890
)
 
163,070

Net decrease in cash
 
$
(2,533
)
 
$
(12,151
)
Operating activities
The primary factors impacting our cash flows from operating activities generally include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from sales of oil, natural gas and natural gas liquids 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 nine months ended September 30, 2014, our net cash provided by operating activities was $358.4 million as compared to $223.4 million for the nine months ended September 30, 2013. The increase is primarily attributable to higher revenues from our recently acquired assets in the Haynesville and Eagle Ford shales as well as an increase in natural gas prices. In addition, the increase was due to changes in accounts receivable which provided cash of $60.2 million for the nine months ended September 30, 2014 as compared to $32.1 million of cash used for the nine months ended September 30, 2013. The decrease in accounts receivable was primarily due to timing of collections of our oil and natural gas sales. Also contributing to the increase were changes in accounts payable and other current liabilities which provided cash of $60.1 million and $13.8 million for the nine months ended September 30, 2014 and 2013, respectively. The increase in accounts payable and other current liabilities was primarily due to advance billings to other working interest owners for our drilling and completion activities in the Eagle Ford shale. These increases were partially offset by cash payments of $32.2 million on derivative contracts for the nine months ended September 30, 2014 compared to cash receipts of $28.4 million for the same period in the prior year.
Investing activities
Our investing activities consist primarily of drilling and development expenditures, acquisitions and divestitures. Future acquisitions are dependent on oil and natural gas prices, availability of producing properties and attractive acreage, acceptable rates of return, availability of borrowing capacity under the EXCO Resources Credit Agreement and availability of other sources of capital.

42


For the nine months ended September 30, 2014, our net cash used in investing activities was $237.0 million primarily due to drilling and development activities in the Haynesville and Eagle Ford shales. This was partially offset by approximately $68.2 million of proceeds received from the sale of our interest in certain non-operated assets in the Permian Basin. For the nine months ended September 30, 2013, our net cash used in investing activities was $398.6 million primarily due to the acquisition of Haynesville and Eagle Ford assets of $973.6 million and our proportionate share of Compass's acquisition of the shallow Cotton Valley assets. This was partially offset by $574.8 million in proceeds received as a result of the contribution of properties to Compass, the sale of undeveloped acreage to a joint venture partner for $130.9 million and the divestiture of certain properties for $37.9 million.
Financing activities
For the nine months ended September 30, 2014, our net cash used in financing activities was $123.9 million primarily due to $839.9 million in net payments of outstanding indebtedness under the EXCO Resources Credit Agreement, $40.6 million of dividend payments and $10.1 million of deferred financing costs primarily related to issuance of the 2022 Notes. This was offset by $500.0 million of gross proceeds received from issuance of the 2022 Notes and approximately $272.9 million of gross proceeds received from the Rights Offering. For the nine months ended September 30, 2013, our net cash provided by financing activities was $163.1 million primarily due to net borrowings under the EXCO Resources Credit Agreement to fund the acquisition of Haynesville and Eagle Ford assets and the additional borrowings of Compass to fund the acquisition of shallow Cotton Valley assets. In addition, we paid $33.5 million of deferred financing costs associated with amendments to the EXCO Resources Credit Agreement and $32.2 million in dividends on our common stock.
Derivative financial instruments
Our production is generally sold at prevailing market prices. However, we periodically enter into oil and natural gas derivative contracts for a portion of our production when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets. Our objective in entering into oil and natural gas derivative contracts is 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.                     
Our derivative financial instruments are comprised of oil and natural gas swaps, basis swaps, three-way collars and call option contracts. As of September 30, 2014, we had derivative financial instruments in place for the volumes and prices shown below:
(in thousands, except prices)
 
NYMEX gas volume - Mmbtu
 
Weighted average contract price per Mmbtu
 
 NYMEX oil volume - Bbls
 
Weighted average contract price per Bbl
Swaps:
 
 
 
 
 
 
 
 
Q4 2014
 
21,185

 
4.22

 
414

 
95.03

2015
 
40,167

 
4.22

 
976

 
93.19

Basis swaps:
 
 
 
 
 
 
 
 
Q4 2014
 

 

 
46

 
6.03

2015
 

 

 
91

 
6.10

Call options:
 
 
 
 
 
 
 
 
Q4 2014
 
5,060

 
4.29

 
92

 
100.00

2015
 
20,075

 
4.29

 
365

 
100.00

Three-way collars:
 
 
 
 
 
 
 
 
2015
 
16,425

 
 
 

 
 
Sold call
 
 
 
4.45

 
 
 

Purchased put
 
 
 
3.81

 
 
 

Sold put
 
 
 
3.31

 
 
 

2016
 
10,980

 
 
 

 
 
Sold call
 
 
 
4.80

 
 
 

Purchased put
 
 
 
3.90

 
 
 

Sold put
 
 
 
3.40

 
 
 


43


We proportionately consolidate the derivative financial instruments entered into by Compass; however the contracts of Compass involve separate master netting agreements with their counterparties. As of September 30, 2014, our proportionate share of Compass's derivative swap contracts covered 1,405 Mmmbtu of natural gas for the remainder of 2014 and 929 Mmmbtu of natural gas during 2015 at an average price of $4.15 and $3.98, respectively. As of September 30, 2014 our proportionate share of Compass's derivative swap contracts covered 23 Mbbls of oil for the remainder of 2014 and 64 Mbbls of oil during 2015 at an average price of $91.87 and $94.98, respectively.
Compass had derivative financial instruments that covered approximately 68% of production volumes for both the three and nine months ended September 30, 2014. Excluding our proportionate share of Compass's derivative financial instruments, we had derivative financial instruments that covered approximately 72% and 68% of production volumes during the three and nine months ended September 30, 2014, respectively.
See further details on our derivative financial instruments in "Note 7. Derivative financial instruments" and "Note 8. Fair value measurements" in the Notes to our Condensed Consolidated Financial Statements.
Off-balance sheet arrangements
As of September 30, 2014, we had no arrangements or any guarantees of off-balance sheet debt to third parties.
Contractual obligations and commercial commitments
There have been no material changes outside the ordinary course of business to our contractual obligations and commercial commitments since December 31, 2013.

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, interest rates charged on borrowings and earned on cash equivalent investments, and adverse changes in the market value of marketable securities. 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 instruments were entered into for hedging and investment purposes, not for trading purposes.
Commodity price risk
    
Our objective in entering into derivative financial instruments is 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. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration.
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.
Our use of derivative financial instruments could have the effect of reducing our revenues and the value of our securities. For the nine months ended September 30, 2014, a $1.00 increase in the average commodity price per Mcfe would have resulted in an increase in cash settlement payments (or a decrease in settlements received) of approximately $71.4 million for our oil and natural gas swap contracts. The ultimate settlement amount of our outstanding derivative financial instrument contracts is dependent on future commodity prices. We may incur significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts remain in place.
Interest rate risk
    
At September 30, 2014, our exposure to interest rate changes related primarily to borrowings under the EXCO Resources Credit Agreement and the Compass Production Partners Credit Agreement. The interest rate per annum on the 2018 Notes is fixed at 7.5% and the interest rate per annum on the 2022 Notes is fixed at 8.5%. Interest is payable on borrowings

44


under the EXCO Resources Credit Agreement and Compass Production Partners Credit Agreement based on a floating rate as more fully described in "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements. At September 30, 2014, we had approximately $222.5 million in outstanding borrowings under the EXCO Resources Credit Agreement and $83.2 million of our proportionate share of outstanding borrowings under the Compass Production Partners Credit Agreement. A 1% increase in interest rates (100 bps) based on the variable borrowings as of September 30, 2014 would result in an increase in our interest expense of approximately $3.1 million per year. After giving effect for the repayment of indebtedness under the revolving commitment of the EXCO Resources Credit Agreement with proceeds from the sale of our interest in Compass, a 1% increase in interest rates (100 bps) based on the variable borrowings would result in an increase in our interest expense of approximately $1.0 million per year. The interest we pay on these borrowings is set periodically based upon market 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 September 30, 2014 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 September 30, 2014 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, we are periodically a party to various litigation matters. We do not believe that any resulting liability from existing legal proceedings, individually or in the aggregate, will have a material adverse effect on our results of operations or financial condition.

Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
Issuer repurchases of common shares
The following table details our repurchase of common shares for the three months ended September 30, 2014:

Period
 
Total Number of Shares Purchased (1)
 
Average Price Paid Per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions) (1)
July 1, 2014 - July 31, 2014
 

 
$

 

 
$
192.5

August 1, 2014 - August 31, 2014
 

 

 

 
192.5

September 1, 2014 - September 30, 2014
 

 

 

 
192.5

       Total
 

 
$

 

 
 
 
(1)
On July 19, 2010, we announced a $200.0 million share repurchase program.

Item 6.
Exhibits

See “Index to Exhibits” for a description of our exhibits.


45


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:
October 29, 2014
 
/s/ Harold L. Hickey
 
 
 
Harold L. Hickey
 
 
 
President and Chief Operating Officer
 
 
 
 
 
 
 
/s/ Richard A. Burnett
 
 
 
Richard A. Burnett
 
 
 
Vice President, Chief Financial Officer
 
 
 
and Chief Accounting Officer
 
 
 
 

46


INDEX TO EXHIBITS

Exhibit
Number
Description of Exhibits

2.1
Haynesville Purchase and Sale Agreement, by and among Chesapeake Louisiana, L.P., Empress, L.L.C., Empress Louisiana Properties, L.P. and EXCO Operating Company, LP, dated July 2, 2013, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2013 filed on October 30, 2013 and incorporated by reference herein.

2.2
Eagle Ford Purchase and Sale Agreement, by and between Chesapeake Exploration, L.L.C. and EXCO Operating Company, LP, dated July 2, 2013, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2013 filed on October 30, 2013 and incorporated by reference herein.

2.3
Contribution Agreement, by and among BG US Gathering Company, LLC, EXCO Operating Company, LP and Azure Midstream Holdings LLC, dated as of October 16, 2013, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated October 16, 2013 and filed on October 22, 2013 and incorporated by reference herein.

2.4
Purchase Agreement, dated October 6, 2014, by and among EXCO Resources, Inc., a Texas corporation, EXCO Operating Company, LP, a Delaware limited partnership, EXCO Holding MLP, Inc., a Texas corporation, HGI Energy Holdings, LLC, a Delaware limited liability company, Compass Production Services, LLC, a Delaware limited liability company, and Compass Energy Operating, LLC, a Delaware limited liability company, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated October 6, 2014 and filed on October 10, 2014 and incorporated by reference herein.

3.1
Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated February 8, 2006 and filed on February 14, 2006 and incorporated by reference herein.

3.2
Articles of Amendment to the Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated August 30, 2007 and filed on September 5, 2007 and incorporated by reference herein.

3.3
Second Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 4, 2009 and filed on March 6, 2009 and incorporated by reference herein.

4.1
Indenture, dated September 15, 2010, by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.

4.2
First Supplemental Indenture, dated September 15, 2010, by and among EXCO Resources, Inc., certain of its subsidiaries and Wilmington Trust Company, as trustee, including the form of 7.500% Senior Notes due 2018, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.

4.3
Second Supplemental Indenture, dated as of February 12, 2013, by and among EXCO Resources, Inc., EXCO/HGI JV Assets, LLC, EXCO Holding MLP, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 12, 2013 and filed on February 19, 2013 and incorporated by reference herein.

4.4
Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Registration Statement on Form S-3 (File No. 333-192898), filed on December 17, 2013 and incorporated by reference herein.

4.5
First Amended and Restated Registration Rights Agreement dates as of December 30, 2005, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935), filed on January 6, 2006 and incorporated by reference herein.

47



4.6
Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the 7.0% Cumulative Convertible Perpetual Preferred Stock and the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

4.7
Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

4.8
Joinder Agreement to Registration Rights Agreement, dated January 17, 2014, by and among EXCO Resources, Inc. and WLR IV Exco AIV One, L.P., WLR IV Exco AIV Two, L.P., WLR IV Exco AIV Three, L.P., WLR IV Exco AIV Four, L.P., WLR IV Exco AIV Five, L.P., WLR IV Exco AIV Six, L.P., WLR Select Co-Investment XCO AIV, L.P., WLR/GS Master Co-Investment XCO AIV, L.P. and WLR IV Parallel ESC, L.P, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 21, 2014 and incorporated by reference herein.

4.9
Joinder Agreement to Registration Rights Agreement, dated January 17, 2014, by and among EXCO Resources, Inc. and Advent Syndicate 780, Clearwater Insurance Company, Northbridge General Insurance Company, Odyssey Reinsurance Company, Clearwater Select Insurance Company, Riverstone Insurance Limited, Zenith Insurance Company and Fairfax Master Trust Fund, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 21, 2014 and incorporated by reference herein.

4.10
Third Supplemental Indenture, dated April 16, 2014, by and among EXCO Resources, Inc., certain of its subsidiaries and Wilmington Trust Company, as trustee, including the form of 8.500% Senior Notes due 2022, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 11, 2014 and filed on April 16, 2014 and incorporated by reference herein.

4.11
Fourth Supplemental Indenture, dated May 12, 2014, by and among EXCO Resources, Inc., EXCO Land Company, LLC and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2014 and filed on July 30, 2014 and incorporated by reference herein.

10.1
Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.2
Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.3
Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.4
Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 4, 2011 and filed on August 10, 2011 and incorporated by reference herein.*

10.5
Form of Performance-Based Restricted Stock Unit Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 30, 2014 and filed on July 3, 2014 and incorporated by reference herein.*

10.6
Fourth Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 16, 2011 and filed on March 22, 2011 and incorporated by reference herein.*

10.7
Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*


48


10.8
Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2009 filed February 24, 2010 and incorporated by reference herein.*

10.9
Amendment Number Two to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., effective as of May 22, 2014, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 22, 2014 and filed on May 29, 2014 and incorporated by reference herein.*

10.10
Letter Agreement, dated March 28, 2007, with OCM Principal Opportunities Fund IV, L.P. and OCM EXCO Holdings, LLC, filed as an Exhibit to EXCO’s Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.11
Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated June 4, 2009 and filed on June 10, 2009 and incorporated by reference herein.*

10.12
Amendment Number Two to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of October 6, 2011, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated October 6, 2011 and filed on October 7, 2011 and incorporated by reference herein.*

10.13
Amendment Number Three to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of June 11, 2013, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 11, 2013 and filed on June 12, 2013 and incorporated by reference herein.*

10.14
Form of Restricted Stock Award Agreement, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2013 filed on August 7, 2013 and incorporated by reference herein.*

10.15
Joint Development Agreement, dated August 14, 2009, by and among BG US Production Company, LLC, EXCO Operating Company, LP and EXCO Production Company, LP, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.

10.16
Amendment to Joint Development Agreement, dated February 1, 2011, by and among BG US Production Company, LLC and EXCO Operating Company, LP, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.

10.17
Joint Development Agreement, dated as of June 1, 2010, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.18
Amendment to Joint Development Agreement, dated February 4, 2011, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.

10.19
Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.20
Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and Appalachia Midstream, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.21
Letter Agreement, dated June 1, 2010 and effective as of May 9, 2010, by and between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.


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10.22
Guaranty, dated May 9, 2010, by BG Energy Holdings Limited in favor of EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC and EXCO Production Company (WV), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.23
Performance Guaranty, dated May 9, 2010, by EXCO Resources, Inc. in favor of BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.24
Guaranty, dated June 1, 2010, by BG North America, LLC in favor of (i) EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and EXCO Holding (PA), Inc, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.25
Guaranty, dated June 1, 2010, by EXCO Resources, Inc., in favor of: (i) BG Production Company (PA), LLC, BG Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.26
Amended and Restated Agreement of Limited Partnership of EXCO/HGI Production Partners, LP, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.

10.27
Form of Amended and Restated Limited Liability Company Agreement of EXCO/HGI GP, LLC, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.

10.28
Letter Agreement, dated November 5, 2012, by and among EXCO Resources, Inc., EXCO Operating Company, LP, Harbinger Group Inc. and HGI Energy Holdings, LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 5, 2012 and filed on November 9, 2012 and incorporated by reference herein.

10.29
Transition Consulting Agreement, dated February 28, 2013, by and between EXCO Resources, Inc. and Stephen F. Smith, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 28, 2013 and filed on March 6, 2013 and incorporated by reference herein.*

10.30
Letter Agreement, dated March 1, 2013, by and between EXCO Resources, Inc. and Mark Mulhern, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 28, 2013 and filed on March 6, 2013 and incorporated by reference herein.*

10.31
EXCO Resources, Inc. 2013 Management Incentive Plan, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 28, 2013 and filed on March 6, 2013 and incorporated by reference herein.*

10.32
Credit Agreement, dated as of February 14, 2013, among EXCO/HGI JV Assets, LLC, as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.

10.33
First Amendment to Credit Agreement, dated as of March 5, 2013, by and among EXCO/HGI JV Assets, LLC, as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.

10.34
Amended and Restated Credit Agreement, dated as of July 31, 2013, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K, dated as of August 19, 2013 and filed on August 23, 2013 and incorporated by reference herein.

10.35
First Amendment to Amended and Restated Credit Agreement, dated as of August 28, 2013, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and

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JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K, dated as of August 28, 2013 and filed on September 4, 2013 and incorporated by reference herein.

10.36
Second Amendment to Amended and Restated Credit Agreement, dated as of July 14, 2014, by and among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K, dated as of July 14, 2014 and filed on July 18, 2014 and incorporated by reference herein.

10.37
Participation Agreement, dated July 31, 2013, among Admiral A Holding L.P., Admiral B Holding L.P. and EXCO Operating Company, LP, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2013 filed on August 7, 2013 and incorporated by reference herein.

10.38
Amendment No. 1 to Participation Agreement, dated April 17, 2014, among EXCO Operating Company, LP, Admiral A Holding L.P. and Admiral B Holding L.P., filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2014 and filed on July 30, 2014 and incorporated by reference herein.

10.39
Form of Director Indemnification Agreement, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 10, 2010 and filed on November 12, 2010 and incorporated by reference herein.

10.40
MVC Letter Agreement, dated November 15, 2013, among BG US Production Company, LLC, BG US Gathering Company, LLC, EXCO Operating Company, LP, Azure Midstream Energy LLC (formerly known as TGGT Holdings, LLC) and TGG Pipeline, Ltd, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 15, 2013 and filed on November 21, 2013 and incorporated by reference herein.

10.41
Exercise Commitment Letter, dated November 22, 2013, by and among EXCO Resources, Inc., WLR Recovery Fund IV XCO AIV I, L.P., WLR Recovery Fund IV XCO AIV II, L.P., WLR Recovery Fund IV XCO AIV III, L.P., WLR Select Co-Investment XCO AIV, L.P., WLR/GS Master Co-Investment XCO AIV, L.P. and WLR IV Parallel ESC, L.P, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 22, 2013 and filed on November 25, 2013 and incorporated by reference herein.

10.42
Exercise Commitment Letter, dated November 22, 2013, by and among EXCO Resources, Inc. and Hamblin Watsa Investment Counsel Ltd, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 22, 2013 and filed on November 25, 2013 and incorporated by reference herein.

10.43
Investment Agreement, dated December 17, 2013, by and among WLR Recovery Fund IV XCO AIV I, L.P., WLR Recovery Fund IV XCO AIV II, L.P., WLR Recovery Fund IV XCO AIV III, L.P., WLR Select Co-Investment XCO AIV, L.P., WLR/GS Master Co-Investment XCO AIV, L.P., WLR IV Parallel ESC, L.P. and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Registration Statement on Form S-3 dated December 17, 2013 and filed on December 17, 2013 and incorporated by reference herein.

10.44
Investment Agreement, dated December 17, 2013, by and between Hamblin Watsa Investment Counsel Ltd., as representative of several investors, and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Registration Statement on Form S-3 dated December 17, 2013 and filed on December 17, 2013 and incorporated by reference herein.

10.45
Settlement Agreement and Mutual Release and Waiver of Claims, dated November 20, 2013, by and between EXCO Resources, Inc. and Douglas H. Miller, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 20, 2013 and filed on November 25, 2013 and incorporated by reference herein.*

10.46
Bonus and Retention Agreement, dated January 17, 2014, by and between William L. Boeing and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 24, 2014 and incorporated by reference herein.*

10.47
Bonus and Retention Agreement, dated January 17, 2014, by and between Harold L. Hickey and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 24, 2014 and incorporated by reference herein.*


51


10.48
Bonus and Retention Agreement, dated January 17, 2014, by and between Mark F. Mulhern and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 24, 2014 and incorporated by reference herein.*

10.49
Letter Agreement, dated March 28, 2014, by and among EXCO Resources, Inc. and Ares Corporate Opportunities Fund, L.P., ACOF EXCO L.P, ACOF EXCO 892 Investors, L.P., Ares Corporate Opportunities Fund II, L.P., Ares EXCO, L.P. and Ares EXCO 892 Investors, L.P., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 27, 2014 and filed on April 1, 2014 and incorporated by reference herein.

10.50
EXCO Resources, Inc. 2014 Management Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2014 and filed on April 25, 2014 and incorporated by reference herein.*

10.51
Amendment Number One to the EXCO Resources, Inc. Management Incentive Plan, effective as of September 1, 2014, filed as an Exhibit to Amendment No. 1 to EXCO's Current Report on Form 8-K/A, dated August 6, 2014 and filed on September 5, 2014 and incorporated by reference herein.*

10.52
Retention Agreement, effective as of September 1, 2014, by and between Richard A. Burnett and EXCO Resources, Inc., filed as an Exhibit to Amendment No. 1 to EXCO's Current Report on Form 8-K/A, dated August 6, 2014 and filed on September 5, 2014 and incorporated by reference herein.*

10.53
Third Amendment to Amended and Restated Credit Agreement, dated as of October 21, 2014, by and among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated October 21, 2014 and filed on October 27, 2014 and incorporated by reference herein.

31.1 
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer of EXCO Resources, Inc., filed herewith.

31.2 
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Financial Officer of EXCO Resources, Inc., filed herewith.

32.1 
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer and Principal Financial Officer of EXCO Resources, Inc., filed herewith.

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.







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