UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________________
FORM 10-K
______________________________
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 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 or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
12377 Merit Drive
Suite 1700, LB 82
Dallas, Texas
 
75251
(Address of principal executive offices)
 
(Zip Code)

Registrant’s telephone number, including area code: (214) 368-2084

Securities registered pursuant to Section 12(b) of the Act:

Title of each class
 
Name of each exchange on which registered
 
 
 
Common Shares, $0.001 par value
 
New York Stock Exchange
                                     

Securities registered pursuant to Section 12(g) of the Act:

None
(Title of class)
______________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. YES   o     NO   x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES   o     NO   x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form10-K or any amendment to this Form 10-K. x  

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

As of February 19, 2015, the registrant had 273,763,414 outstanding common shares, par value $0.001 per share, which is its only class of common shares. As of the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the registrant's common shares held by non-affiliates was approximately $897,416,000 .
______________________________

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's Definitive Proxy Statement on Schedule 14A to be furnished to shareholders in connection with its 2015 Annual Meeting of Shareholders are incorporated by reference in Part III, Items 10-14 of this Annual Report on Form 10-K.




EXCO RESOURCES, INC.
TABLE OF CONTENTS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


1


EXCO RESOURCES, INC.
PART I



Item  1.      Business

General

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

We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of selected oil and natural gas terms” beginning on page 26.

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.

As of December 31, 2014 , our Proved Reserves were approximately 1.3 Tcfe, of which 91% were natural gas and 47% were Proved Developed Reserves. As of December 31, 2014 , the PV-10 and Standardized Measure of our Proved Reserves were approximately $1.5 billion . This represents an increase in Proved Reserves of 12% and PV-10 and Standardized Measure of 23% compared to the prior year. For the year ended December 31, 2014 , we produced 135.7 Bcfe of oil, natural gas and natural gas liquids ("NGLs").

Our business strategy

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 maintaining financial flexibility. We believe this will allow us to create long-term value for our shareholders.

Exploit our shale resource plays

Our primary focus is the development of our core areas as we exploit our extensive inventory of drilling opportunities. This includes a diverse portfolio of both oil and natural gas assets that provide us the optionality to allocate capital to enhance our returns under various commodity price environments. We hold significant acreage positions in three prominent shale plays in the United States:

East Texas and North Louisiana - we currently hold approximately 85,300 net acres in the Haynesville and Bossier shales;
South Texas - we currently hold approximately 52,900 net acres in the Eagle Ford shale; and
Appalachia - we currently hold approximately 157,000 net acres prospective in the Marcellus shale.

We have extensive amounts of technical and operational expertise within the Haynesville and Bossier shales. We have accumulated significant amounts of contiguous acreage and are one of the largest operators within this region. Our economies of scale and operational expertise have allowed us to efficiently develop our assets and minimize our costs through greater utilization of multi-well pads and existing infrastructure and facilities.

We have applied our technical and operational expertise from other shale plays to the Eagle Ford shale since we acquired the assets on July 31, 2013. We have realized significant improvements in our drilling performance and the optimization of our well design has yielded strong results. We have a participation agreement with a joint venture partner ("Participation Agreement") to develop certain assets in the Eagle Ford shale which allows us to diversify the risks associated with this development while establishing a platform for growth through the acquisition of oil-focused proved developed producing properties at attractive prices based on the offer process within the Participation Agreement. Our position also includes producing properties and undeveloped locations in the Eagle Ford shale, Buda formation and other formations which are not included as part of the Participation Agreement.



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Our principal activities in the Marcellus shale are focused on technical evaluations of our acreage holdings and a disciplined appraisal drilling program. We will continue our appraisal program as we evaluate future development activities in 2015. A substantial portion of our shale resource play acreage is held-by-production, which gives us flexibility to control the timing of our development activities in the region.

Evaluate complementary acquisitions that meet our strategic and financial objectives

We continue to evaluate acreage opportunities and acquisitions of producing properties in our core areas. We believe we can leverage our technical expertise and economies of scale to maximize our returns in these areas. Our recent acquisition history has been focused on shale resource plays with an emphasis on the acquisition of undeveloped acreage. Our current business development focus is on evaluating acreage and producing property acquisition opportunities that are complementary to our current asset base.

Manage our liquidity and enhance financial flexibility

We actively manage our liquidity to ensure that we are able to execute our business strategies. We continuously review our portfolio and evaluate transactions that would enhance our liquidity and allow us to redeploy capital to other projects with higher rates of return. During 2014, we executed several key transactions that improved our liquidity and financial flexibility. We utilized the proceeds from these transactions to reduce indebtedness under our credit agreement ("EXCO Resources Credit Agreement"). These transactions included the following:

closed a rights offering and related private placement of our common shares ("Rights Offering") on January 17, 2014, which resulted in the issuance of 54,574,734 shares of our common shares for gross proceeds of $272.9 million;
sold our interest in certain non-operated assets in the Permian Basin, including producing wells and undeveloped acreage, for approximately $68.2 million ;
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; and
sold our entire interest in Compass Production Partners, L.P. ("Compass") for $118.8 million in cash.

Our board of directors approved a capital expenditure budget of up to $275.0 million for 2015 . Our budget was designed to allocate capital based on projects with the highest rate of return and other strategic initiatives which will unlock additional value in our assets. We believe the capital budget is appropriate for the current commodity price environment and is expected to result in a reduction in capital expenditures of approximately 35% compared to the prior year. We expect the capital expenditure program will be funded primarily by our operating cash flows as well as borrowings under the EXCO Resources Credit Agreement. Our capital expenditure budget will allow us to preserve our liquidity and capital resources in preparation for future growth. We amended the EXCO Resources Credit Agreement on February 6, 2015, which modified our financial covenants which provides us with the financial flexibility to selectively develop our asset base while deferring a significant amount of our drilling inventory until commodity prices improve. In connection with the amendment, our borrowing base was reduced to $725.0 million as a result of the recent declines in commodity prices compared to prices in effect at the prior borrowing base redetermination. This would have resulted in pro forma liquidity of $586.2 million as of December 31, 2014.

We are evaluating potential transactions which would further enhance our liquidity including additional divestitures of non-core assets and cost reduction initiatives. As a result of the current commodity price environment, we have negotiated reductions in service costs with several key vendors and will continue to pursue further reductions. Also, we have implemented initiatives to reduce our general and administrative costs, including a 15% reduction in our workforce during 2015. The cost reduction initiatives will allow us to maximize our cash flows in a low commodity price environment.

We use derivative financial instruments to enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investments and manage our capital structure. Our comprehensive derivative financial instrument program will help mitigate the impact of volatility in commodity prices and allow us to achieve more predictable cash flows.



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Our strengths

High quality asset base in attractive regions

We own a geographically diversified reserve base including significant acreage positions in some of the most prominent shale plays in the United States. Our principal operations are in Texas, Louisiana and the Appalachia region. In addition, a significant portion of our acreage is held-by-production which allows us to develop these properties within our optimum time frame. Our properties are generally characterized by:

multi-year inventory of development drilling and exploitation projects;
high drilling success rates;
significant unproved reserves and resources; and
long reserve lives.

Operational control

We operate a significant portion of our properties which allows us to manage our operating costs and better control capital expenditures as well as the timing of development and exploitation activities. Therefore, we are able to allocate our capital to the most attractive projects based on commodity prices, rates of return and industry trends. As of December 31, 2014 , we operated 6,559 of our 7,066 gross wells, or wells representing approximately 93% of our Proved Developed Reserves. We have continued to demonstrate improved drilling and completion results in our operated areas while maintaining low capital and operating costs.
  
Skilled technical personnel and experienced management team

We have developed a workforce that has a significant number of highly skilled technical and operational personnel who have been successful in developing our shale resources. We leverage our technical expertise to exploit our asset base in an efficient and cost-effective manner. We believe our technical expertise gives us a competitive advantage in our key operating areas.

Our management team has extensive industry experience in acquiring, exploring, exploiting and developing oil and natural gas properties. We believe that our management team will be instrumental in executing a disciplined approach to accomplish our business strategies. Our board of directors is currently conducting a search for a new chief executive officer who will bring additional leadership, experience and expertise to our current management team.

Plans for 2015

Our plans for 2015 primarily focus on the exploitation and development of our core areas and cost containment throughout our organization. In response to the low commodity price environment, we plan to reduce our drilling program compared to the prior year. We believe the capital projects included in our plans for 2015 still provide attractive returns in a low commodity price environment. We will continue to focus on operational initiatives to enhance our well designs, optimize our base production and maximize the recoveries from our properties. We plan to focus on fiscal discipline which includes initiatives implemented to reduce our operating and general and administrative costs. Although our focus is on the exploitation and development of our current asset base, we will evaluate complementary acquisitions that meet our strategic and financial objectives.



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Summary of geographic areas of operations

The following tables set forth summary operating information attributable to our principal geographic areas of operation as of December 31, 2014 :
Areas
 
Total Proved Reserves (Bcfe) (1)
 
PV-10 (in millions) (1) (2)
 
Average daily net production (Mmcfe) (3)
East Texas/North Louisiana
 
881.2

 
$
813.8

 
238

South Texas (4)
 
113.1

 
561.5

 
39

Appalachia and other
 
269.5

 
167.3

 
55

Total
 
1,263.8

 
$
1,542.6

 
332


Areas
 
Estimated drilling locations (5)
 
Total gross acreage
 
Total net acreage
East Texas/North Louisiana
 
1,988

 
230,600

 
99,300

South Texas (6)
 
212

 
101,400

 
52,900

Appalachia and other
 
4,194

 
659,400

 
297,100

Total
 
6,394

 
991,400

 
449,300


(1)
The total Proved Reserves and PV-10 as of December 31, 2014 were prepared in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC"). The estimated future plugging and abandonment costs necessary to compute PV-10 were computed internally.
(2)
The PV-10 data used in this table was based on reference prices using the simple average of the spot prices for the trailing 12 month period using the first day of each month beginning on January 1, 2014 and ending on December 1, 2014 , of $4.35 per Mmbtu for natural gas and $94.99 per Bbl for oil, in each case adjusted for geographical and historical differentials. The price for NGLs was $33.03 per barrel and was computed on the trailing 12 month average of realized prices. Market prices for oil, natural gas and NGLs are volatile (see “Item 1A. Risk Factors-Risks Relating to Our Business”). We believe that PV-10, while not a financial measure in accordance with generally accepted accounting principles in the United States ("GAAP"), is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions due to tax characteristics which can differ significantly among comparable companies. The total Standardized Measure, a measure recognized under GAAP, as of December 31, 2014 was $1.5 billion . The Standardized Measure represents the PV-10 after giving effect to income taxes, and is calculated in accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 932, Extractive Activities, Oil and Gas ("ASC 932"). Our existing net operating loss carryforwards eliminated estimated future income taxes for the year ended December 31, 2014 . The amount of estimated future plugging and abandonment costs, the PV-10 of these costs and the Standardized Measure were determined by us. We do not designate our derivative financial instruments as hedges and accordingly, do not include the impact of derivative financial instruments when computing the Standardized Measure.
(3)
The average daily net production rate was calculated based on the average daily rate during the final month of the year ended December 31, 2014 .
(4)
We are developing certain undeveloped acreage in the Eagle Ford shale pursuant to the Participation Agreement. Under this agreement, we assign half of our working interest in a well to the joint venture partner upon commencement of development. Therefore, we have only included half of our current working interest in the undeveloped locations subject to this agreement within our Proved Reserves. We have not incorporated the impact of future acquisitions under the Participation Agreement within our Proved Reserves.
(5)
Identified drilling locations represent total gross drilling locations identified and scheduled by our management as an estimate of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors (see “Item 1A. Risk Factors-Risks Relating To Our Business”).
(6)
The acreage in this region includes 41,600 net acres outside of our core area in Zavala County that are subject to our joint venture partner's right to participate in each proposed well. The acreage outside of our core area is not subject to the Participation Agreement.




5


Our development and exploitation project areas
 

East Texas/North Louisiana
    
The East Texas/North Louisiana area is our largest producing region with operations focused on the Haynesville and Bossier shales. Our Haynesville shale acreage is primarily located in DeSoto and Caddo Parishes in Louisiana and in Harrison, Panola, Shelby, San Augustine and Nacogdoches Counties in Texas. Our acreage in this region is predominantly held-by-production. The Haynesville shale is located at depths of 12,000 to 14,500 feet and is being developed with horizontal wells that typically have 4,000 to 6,000 foot laterals in the Holly area of North Louisiana and 6,000 to 8,000 foot laterals in the Shelby area of East Texas. The Bossier shale lies just above certain portions of the Haynesville shale and also contains rich deposits of natural gas.     
    
Our development drilling program in the Haynesville shale is concentrated in the Holly area in DeSoto Parish, Louisiana and the Shelby area in East Texas. At December 31, 2014 , we operated three drilling rigs focused on the Haynesville shale. During 2015 , we plan to operate an average of three drilling rigs to drill approximately 25 gross ( 11.9 net) wells and complete approximately 32 gross ( 17.6 net) wells. The 2015 program will be focused on the development of the Shelby area of East Texas based on the recent success of our drilling program in the area which has resulted in strong well performance. As of December 31, 2014 , our average operated shale natural gas production was approximately 589 gross ( 224.4 net) Mmcfe per day. Including non-operated volumes, our total net production from the Haynesville and Bossier shales was 241.1 Mmcfe per day as of December 31, 2014 .

Shelby area
    
Our position in the Shelby area primarily consists of 31,600 net acres in San Augustine, Sabine, Nacogdoches, and Shelby Counties. This includes approximately 14,400 net acres that were included as part of an acquisition focused on producing properties during 2014 and primarily consists of small undivided interests including a portion that is subject to continuous drilling obligations to hold the acreage. Excluding this recently acquired acreage, approximately 95% of our net acres are held-by-production in the Shelby area. As of December 31, 2014 , we had a total of 84 gross (37.1 net) operated horizontal wells flowing to sales. Prior to 2014, our activity in this area consisted of delineating the acreage, establishing infrastructure, performing technical evaluations, testing completion designs and evaluating flowback methodologies. Our


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drilling program during 2014 was designed to include enhanced completion methods, longer laterals and a more restricted flowback program. As part of our restricted flowback program, we have been managing the choke size to limit the production of the wells to 10 Mmcf or less per day. The restricted flowback program limits the initial production of the wells; however, we anticipate it will increase the estimated ultimate recoveries. The more conservative flowback, along with the other design changes, are yielding strong well performance as evidenced by a minimal reduction in flowing pressures over time. We drilled 8 gross (3.9 net) wells in the area during 2014, which includes 5 gross (2.4 net) operated wells in the Haynesville shale and 3 gross (1.5 net) operated wells in the Bossier shale. We are experiencing strong results from both the Haynesville and Bossier shale wells which resulted in significant upward revisions to our Proved Reserves during 2014, due to improved well performance.

We plan to build on our recent success in the region by drilling 22 gross (9.4 net) wells in the Shelby area during 2015. The drilling program in this region provides attractive rates of return even in a low commodity price environment. We have approximately 250 operated undeveloped locations in this area which provide a platform for future growth.

Holly area
    
Our position in the Holly area consists of 29,400 net acres in DeSoto Parish and 9,000 net acres in Caddo Parish, which are all held-by-production. At December 31, 2014 , we had three drilling rigs running in the area and a total of 397 gross (193.1 net) operated horizontal wells flowing to sales. Our drilling program in the area during 2014 consisted of 39 gross (21.0 net) operated wells drilled in the Haynesville shale based on spacing of four to six wells per section. As of December 31, 2014 , we had 48 developed units and 29 undeveloped units. We have also utilized a more restricted flowback program on recent wells turned-to-sales in the area similar to the restricted flowback program that was successful in the Shelby area. We completed 5 gross ( 2.8 net) refracs on operated wells during 2014 and the wells exhibited strong performance as evidenced by the minimal reduction in production and pressure since the refrac stimulation. The refracs consist of a second fracture stimulation treatment in an existing well to re-stimulate the shale reservoir. This will enhance the connection from the reservoir to the wellbore to increase productivity and more effectively produce the resources. We estimate the cost of the refracs to range from $1.0 million to $2.5 million and we are currently analyzing the results of the tests performed-to-date in order to assess the impact on the recoveries from the wells. We drilled a test well in the Bossier shale in DeSoto Parish in the fourth quarter 2014 to further assess the potential of the formation. We utilized similar enhanced completion methods that have proven to be successful in our recent Haynesville shale development. The well was completed and turned-to-sales in early 2015 and we are currently evaluating the results of the test. The results of our evaluation of the Bossier shale within the Holly area could result in over 300 additional drilling locations.

Our plans for 2015 include drilling 3 gross ( 2.5 net) wells and completing our inventory of 15 gross ( 9.2 net) operated wells that have been drilled. We plan to continue to utilize our enhanced completion techniques including more proppant and a restricted flowback program. In addition, we plan to perform 1 gross ( 0.6 net) refracs on operated wells during 2015.

East Texas/North Louisiana operating effectiveness
    
We have focused on improving the efficiency of our drilling and completion operations which has resulted in reductions to our well costs. In DeSoto Parish, our average drilling and completion costs per well were $7.1 million during 2014 , $7.0 million during 2013 and $8.3 million during 2012 . We were able to achieve these reductions in costs while improving our well design through enhanced drilling and completion techniques including more proppant per lateral foot. We continue to achieve improved drilling times per well and are currently averaging 32 days from spud to rig release for a typical 16,500 foot Haynesville well in DeSoto Parish.

In the Shelby area, our average drilling and completion costs per well were $12.1 million during 2014. The average lateral length for these wells was 6,500 feet and represents some of our longest laterals drilled-to-date in the region. During 2015, we expect the average cost per well to decrease as a result of economies of scale in connection with our increased development program and multi-well pad design.

In addition, we believe the current commodity price environment will likely result in the reduction of service costs throughout the industry. We will remain focused on reducing our well costs attributable to drilling while continuing to optimize our completions. We have continued to improve our well design by increasing the amount of proppant used in the hydraulic fracturing process on recent completions. These changes in our well design have improved our well performance and estimated ultimate recoveries. We have implemented several initiatives to enhance and manage our base production in the region. This includes a compression program, foamer injection program and the installation of artificial lift. Our compression program included the installation of two interim lateral compressor units during the year. We recently secured a contract with our midstream service provider for additional compression services in the Holly area which are expected to begin in the third


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quarter of 2015. We have seen sustained performance improvement from these initiatives as evidenced by a flattening of our base production decline.

Our production operations team is focused on lowering our direct operating costs including water management, efficient utilization of our personnel, equipment rentals and chemicals. We are in the process of negotiating reductions in service costs with certain vendors as a result of the current commodity price environment. Through the use of automation at the well sites, we can better utilize company personnel time to perform maintenance work and reduce the use of third party services. We also have an operations tracking database system in place that enables us to be proactive in maintenance and repairs which results in cost efficiencies. We plan to continue to efficiently manage our chemical programs which will allow us to reduce costs by minimizing well intervention work.
    
We have a Dallas-based operations control center that is staffed 24 hours a day that monitors our Haynesville, Bossier, Eagle Ford and Marcellus shale wells. This control system gives us the ability to monitor and control natural gas flow over a large portion of our fields, which allows us to optimize the daily natural gas flow from our assets and minimize downtime.

South Texas

We acquired assets in the South Texas region in July 2013 focused on the Eagle Ford shale that included 120 producing wells and undeveloped acreage. Our position in this region includes 52,900 net acres covering portions of Zavala, Dimmit and Frio Counties, Texas. Our acreage in the Eagle Ford shale is in the oil window and averages 375 feet in gross thickness at true vertical depths ranging from 5,400 to 6,800 feet. Our lateral lengths average 7,100 feet and range from 5,000 to 9,000 feet and the total measured depth averages 14,600 feet. Our acreage in the area is primarily held-by-production and also includes additional upside in formations such as the Austin Chalk, Buda and Pearsall formations.

We drilled 63 gross ( 10.9 net) wells in the core area of Zavala County during the year ended December 31, 2014 . Our drilling utilized a multi-well pad design followed by fracture stimulating the group of wells simultaneously. These well development groups range from 4 to 12 wells and allow us to maximize reserves recovery while reducing costs. We turned-to-sales 53 gross ( 9.2 net) wells during the year ended December 31, 2014 within our core area. We drilled 11 gross (5.3 net) wells and turned-to-sales 10 gross (4.2 net) wells outside of our core area during the year ended December 31, 2014. The acreage for the wells drilled outside of our core area was primarily earned through a farmout agreement and additional leasing which has allowed us to expand our position in the region. The wells drilled outside of the core area are not included as part of the acquisition program under the Participation Agreement with our joint venture partner and typically have a higher working interest compared to new wells drilled in our core area. The most recent wells turned-to-sales both inside and outside our core area featured enhanced completion methods and have provided our best results to date in the region. As of December 31, 2014 , our average operated shale oil production was approximately 23,100 gross (6,200 net) barrels of oil per day from 209 gross (107.7 net) wells.

We have reduced our drilling activity in South Texas in response to lower crude oil prices and plan to average one rig throughout 2015. Our 2015 capital program is designed to preserve leasehold commitments, fulfill continuous drilling obligations and drill key test wells in the Buda formation. We plan to spend a total of $66.0 million in this region during 2015, of which $59.0 million will be spent to spud 23 gross (7.1 net) horizontal wells and turn to sales 44 gross (10.7 net) horizontal wells. We plan to turn-to-sales 33 gross (5.7 net) Eagle Ford shale horizontal wells in our core area acreage, and 11 gross (5.0 net) horizontal well outside of our core area. Our plans for 2015 include 1 gross (0.5 net) operated well and 3 gross (0.5 net) non-operated wells drilled in the Buda formation. The Buda formation has the potential to add drilling locations to our inventory characterized by low capital intensity with high rates of return. The average cost per well in the Buda formation as part of our 2015 capital program range from $2.5 million to $3.5 million and do not require hydraulic fracturing since the formation contains natural fractures. Our capital program during 2015 also includes $7.0 million to fund pumping units to optimize our production and infrastructure development to reduce future operating costs.

South Texas operational effectiveness

We have utilized our expertise from other shale developments and have realized significant operational efficiencies in our Eagle Ford assets. This includes improved drilling times per well which are currently averaging 12 days from spud to rig release and the current average drilling and completion costs per well are approximately $7.1 million . Additionally, we recently secured a completion contract that will further reduce our fracture stimulation costs. We continue to implement initiatives to optimize and increase the efficiency of our production including the installation of artificial lift. We installed 87 additional pumping units during 2014 and plan to install 57 units during 2015. The pumping units installed to-date have been successful in flattening our base production decline.



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We engaged a third party to construct central production facilities in our core area to increase the efficiency of our production. These facilities will also reduce our costs during the completion phase of certain properties since multiple wells on a pad will utilize the same connections to the central facilities. The first and second central production facilities became operational in the fourth quarter of 2014 and we began production from wells connected to this system. As of December 31, 2014, these central facilities have allowed us to produce 27 gross (5.5 net) wells into the system. The third central production facility became operational in the first quarter of 2015. A pipeline is currently being constructed from the central facilities to an oil pipeline in Dilley, Texas and is expected to be operational in the second quarter or third quarter of 2015. We are evaluating the design of an electrical distribution network over the core development area that will provide a more efficient cost structure to operate the field. We were also able to significantly reduce our operating costs in the region during 2014 through the execution of several initiatives including decreased saltwater disposal costs and reduced reliance on third-party contractors. We plan to implement additional cost reduction initiatives during 2015 and expect a reduction in our service costs as a result of the current commodity price environment. We have already negotiated reductions in service costs with certain key vendors including rental equipment and chemical treating programs.

Appalachia
    
Our operations in the Appalachia region have primarily included testing and selectively developing the Marcellus shale with horizontal drilling while maintaining our existing conventional production from shallow vertical wells. We currently hold approximately 290,000 net acres in the Appalachian basin, with approximately 157,000 of these net acres prospective for the Marcellus shale. A significant amount of this acreage is held-by-production. Of the Marcellus shale acreage that is not held-by-production, 29,900 net acres are scheduled to expire prior to 2018. As of December 31, 2014 , we operated a total of 5,736 gross (2,708.1 net) vertical shallow wells flowing to sales with an average gross production rate of approximately 29 gross (11.9 net) Mmcfe per day. As of December 31, 2014 we operated a total of 126 gross (45.7 net) horizontal wells in the Marcellus shale with an average gross production rate of approximately 141 gross (38.6 net) Mmcfe per day. Including non-operated volumes, our net production in the Appalachia region was 52.5 Mmcfe per day as of December 31, 2014 .

Our Pennsylvania acreage encompasses 23 counties. Drilling, completion and production activities target the Marcellus shale as well as the Upper Devonian, Venanago, Bradford and Elk sandstone groups at depths ranging from 1,800 to more than 9,000 feet. Our West Virginia area includes 27 counties and stretches from the northern to the southern areas of the state. Drilling, completion and production activities target the Marcellus shale and multiple reservoirs of the Mississippian and Devonian formations found at depths ranging from 1,500 to 8,100 feet.

Marcellus shale

We previously suspended our drilling program in this region in response to lower realized natural gas prices from the widening of regional price differentials in order to focus on projects with higher rates of return. A significant amount of our acreage is held-by-production, which allows us to control the timing of the development of this region. We are encouraged by the recent results of our wells turned-to-sales in this region and will be resuming our appraisal drilling program in 2015. Our plans for 2015 include the drilling of 2 gross (0.7 net) operated appraisal wells in Sullivan County targeting the Marcellus shale near recent successful results. These successful results include our most recent well turned-to-sales in October 2013 which had cumulative production of 2.7 Bcfe as of December 31, 2014. We have an extensive inventory of undeveloped locations prospective for the Marcellus shale that would provide attractive rates of return in an improved commodity price environment. We have the ability to wait for the optimal time to develop these locations since most of the prospective acreage is held-by-production.

Marcellus shale operational effectiveness

We have effectively managed our base production declines as a result of increased automation and surveillance equipment to reduce downtime as well as artificial lift installations. We recently restructured our field organization to better align the operations personnel with the asset base and reduce our operating costs.

Our hydraulic fracturing activities

Oil and natural gas may be recovered from our properties through the use of sophisticated drilling and hydraulic fracturing techniques. Hydraulic fracturing involves the injection of water, sand, gel and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Our hydraulic fracturing activities are primarily focused in the Eagle Ford shale in South Texas, Haynesville and Bossier shales in East Texas/North Louisiana and Marcellus shale in the Appalachia region. Predominantly all of our Proved Reserves are associated with shale assets in these areas.



9


Although the cost of each well will vary, the costs associated with hydraulic fracturing activities on average represent the following portions of the total costs of drilling and completing a well: 15-25% in the Haynesville and Bossier shale formation; 30-40% in the Eagle Ford shale formation; and 25-35% in the Marcellus shale formation.

We review best practices and industry standards to comply with regulatory requirements in the protection of potable water sources when drilling and completing our wells. Protective practices include, but are not limited to, setting multiple strings of protection pipe across potable water sources and cementing these pipe strings to surface, continuously monitoring the hydraulic fracturing process in real time and disposing of non-recycled produced fluids in authorized disposal wells at depths below the potable water sources. In addition, we actively seek methods to minimize the environmental impact of our hydraulic fracturing operations in all of our operating areas. For example, we use discharge water from a local paper plant as a key water source for our fracture stimulation operations in North Louisiana. We recycle flowback fluids when economically feasible.
    
For more information on the risks of hydraulic fracturing, see “Item 1A. Risk Factors-Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures” and “Item 1A. Risk Factors-Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”

Our oil and natural gas reserves
    
Our Proved Reserves as of December 31, 2014 were approximately 1.3 Tcfe, of which approximately 96% were related to our shale properties. Of our Proved Reserves attributed to shale properties, approximately 69% were located in the Haynesville/Bossier shale, 18% in the Marcellus shale and 9% in the Eagle Ford shale. Our non-shale Proved Reserves represented approximately 4% of total Proved Reserves as of December 31, 2014 , which consisted primarily of conventional assets in the Appalachia region.

The following table summarizes Proved Reserves as of December 31, 2014 , 2013 and 2012 . This information was prepared in accordance with the rules and regulations of the SEC. The comparability of our reserves is impacted by purchases and sales of reserves in place, production, revisions of previous estimates and discoveries and extensions.  See "Management's discussion and analysis of oil and natural gas reserves" for a summary of the changes in our Proved Reserves.


10


 
 
As of December 31,
 
 
2014
 
2013
 
2012
Oil (Mbbls)
 
 
 
 
 
 
Developed
 
14,429

 
11,274

 
4,371

Undeveloped
 
3,258

 
4,104

 
1,199

Total
 
17,687

 
15,378

 
5,570

 
 
 
 
 
 
 
Natural gas (Mmcf)
 
 
 
 
 
 
Developed
 
502,314

 
657,116

 
917,326

Undeveloped
 
652,714

 
359,363

 
18,806

Total
 
1,155,028

 
1,016,479

 
936,132

 
 
 
 
 
 
 
Natural gas liquids (Mbbls)
 
 
 
 
 
 
Developed
 
387

 
2,088

 
4,784

Undeveloped
 
54

 
495

 
1,855

Total
 
441

 
2,583

 
6,639

 
 
 
 
 
 
 
Equivalent reserves (Mmcfe)
 
 
 
 
 
 
Developed
 
591,210

 
737,291

 
972,256

Undeveloped
 
672,586

 
386,954

 
37,130

Total
 
1,263,796

 
1,124,245

 
1,009,386

 
 
 
 
 
 
 
PV-10 (in millions) (1)
 
 
 
 
 
 
Developed
 
$
1,117.6

 
$
1,153.5

 
$
666.0

Undeveloped
 
425.0

 
98.8

 
30.1

Total
 
$
1,542.6

 
$
1,252.3

 
$
696.1

 
 
 
 
 
 
 
Standardized Measure (in millions) (2)
 
$
1,542.6

 
$
1,252.3

 
$
696.1


(1)
The PV-10 is based on the following average spot prices, in each case adjusted for historical differentials. Prices presented on the table below are the trailing 12 month simple average spot price at the first of the month for natural gas at Henry Hub and West Texas Intermediate crude oil at Cushing, Oklahoma. Our NGL price was computed using the trailing 12 month average of realized prices.

 
 
Average spot prices

 
Oil (per Bbl)
 
Natural gas (per Mmbtu)
 
Natural gas liquids (per Bbl)
December 31, 2014
 
$
94.99

 
$
4.35

 
$
33.03

December 31, 2013
 
96.78

 
3.67

 
39.92

December 31, 2012
 
94.71

 
2.76

 
46.57


(2)
There is no difference in Standardized Measure and PV-10 for all years presented as the impacts of net operating loss carry-forwards eliminated future income taxes.
    
We believe that PV-10, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions due to tax characteristics, which can differ significantly among comparable companies. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is calculated in accordance with ASC 932.
    


11


Management has established, and is responsible for, internal controls designed to provide reasonable assurance that the estimates of Proved Reserves are computed and reported in accordance with rules and regulations promulgated by the SEC as well as established industry practices used by independent engineering firms and our peers. These internal controls include documented process workflows, qualified professional engineering and geological personnel with specific reservoir experience and investment in on-going education with emphasis on emerging technologies. These emerging technologies are of particular importance as they relate to our shale plays. Our internal audit function routinely tests our processes and controls. We also retain outside independent engineering firms to prepare or audit estimates of our Proved Reserves. Senior management reviews and approves our reserve estimates, whether prepared internally or by third parties. Our Vice President of Engineering oversees our outside independent engineering firms, Lee Keeling and Associates, Inc. ("Lee Keeling"), Netherland, Sewell & Associates, Inc. ("NSAI"), and Ryder Scott Company, L.P. ("Ryder Scott") in connection with the preparation of their estimates of our Proved Reserves or their audit of the Proved Reserves prepared by EXCO's internal engineers. Our Vice President of Engineering is a registered Professional Engineer with over 36 years of experience in the oil and natural gas industry and has served in various leadership roles with the Gas Research Institute, the Society of Petroleum Engineers and the Society of Women Engineers. She is a graduate of Pennsylvania State University with a degree in Petroleum and Natural Gas Engineering. During her career, our Vice President of Engineering has been involved in oil and natural gas reserves analysis and estimation for both major oil companies and independents. Our Chief Operating Officer and our Vice President of Engineering, with input from other members of senior management, are responsible for the selection of our third-party engineering firms and receive the reports generated by such firms. The third-party engineering reports are provided to our audit committee, which meets annually with the engineering firms to review and discuss the procedures for determining the estimates or auditing of our oil and natural gas reserves.

The estimates of Proved Reserves and future net cash flows for our non-shale properties as of December 31, 2014 , 2013 and 2012 have been prepared by Lee Keeling. Our estimated Proved Reserves and future net cash flows for our shale properties in the South Texas region were prepared by Ryder Scott as of December 31, 2014 and 2013. Our estimated Proved Reserves and future net cash flows for our shale properties in all regions except South Texas were prepared by NSAI as of December 31, 2014 and 2012, and were prepared by our internal engineers and audited by NSAI as of December 31, 2013. Lee Keeling, NSAI and Ryder Scott are independent petroleum engineering firms that perform a variety of reserve engineering and valuation assessments for public and private companies, financial institutions and institutional investors. Lee Keeling, NSAI and Ryder Scott have performed these services for over 50 years. Our internal technical employees responsible for reserve estimates and interaction with our independent engineers include corporate officers with petroleum and other engineering degrees, professional certifications and industry experience similar to those of our independent engineering firms.

Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm's extensive visits, collection of any and all required geological, geophysical, engineering and economic data, and such firm's complete external preparation of all required estimates and are forward-looking in nature. These reports rely on various assumptions, including definitions and economic assumptions required by the SEC, including the use of constant oil and natural gas pricing, use of current and constant operating costs and capital costs. We also make assumptions relating to availability of funds and timing of capital expenditures for development of our Proved Undeveloped Reserves. These reports should not be construed as the current market value of our Proved Reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the Proved Reserves will ultimately be realized. Our actual results could differ materially. See “Note 18. Supplemental information relating to oil and natural gas producing activities (unaudited)” of the Notes to our Consolidated Financial Statements for additional information regarding our oil and natural gas reserves and the Standardized Measure.

Lee Keeling, NSAI and Ryder Scott also examined our estimates with respect to reserve categorization, using the definitions for Proved Reserves set forth in SEC Regulation S-X Rule 4-10(a) and SEC staff interpretations and guidance. In preparing an estimate or performing an audit of our Proved Reserves and future net cash flows attributable to our interests, Lee Keeling, NSAI and Ryder Scott did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of the examination anything came to the attention of Lee Keeling, NSAI or Ryder Scott which brought into question the validity or sufficiency of any such information or data, Lee Keeling, NSAI or Ryder Scott did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data. Lee Keeling, NSAI and Ryder Scott determined that their estimates of Proved Reserves or our audited estimates of Proved Reserves conform to the guidelines of the SEC, including the criteria of Reasonable Certainty, as it pertains to expectations about the recoverability of Proved Reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of SEC Regulation S-X.


12



Management's discussion and analysis of oil and natural gas reserves
    
The following discussion and analysis of our proved oil and natural gas reserves and changes in our Proved Reserves is intended to provide additional guidance on the operational activities, transactions, economic and other factors which significantly impacted our estimate of Proved Reserves as of December 31, 2014 and changes in our Proved Reserves during 2014 . This discussion and analysis should be read in conjunction with “Note 18. Supplemental information relating to oil and natural gas producing activities (unaudited)” and in “Item 1A. Risk Factors” addressing the uncertainties inherent in the estimation of oil and natural gas reserves elsewhere in this Annual Report on Form 10-K. The following table summarizes the changes in our Proved Reserves from January 1, 2014 to December 31, 2014 .
 
 
Oil (Mbbls)
 
Natural gas (Mmcf)
 
Natural gas liquids (Mbbls)
 
Equivalent natural gas (Mmcfe)
Proved Developed Reserves
 
14,429

 
502,314

 
387

 
591,210

Proved Undeveloped Reserves
 
3,258

 
652,714

 
54

 
672,586

Total Proved Reserves (1)
 
17,687

 
1,155,028

 
441

 
1,263,796

The changes in reserves for the year are as follows:
 
 
 
 
 
 
 
 
January 1, 2014
 
15,378

 
1,016,479

 
2,583

 
1,124,245

Purchases of reserves in place
 

 
7,316

 

 
7,316

Discoveries and extensions
 
4,164

 
69,902

 
107

 
95,528

Revisions of previous estimates (2):
 
 
 
 
 
 
 
 
Changes in price
 
45

 
167,302

 
127

 
168,334

Other factors
 
1,737

 
120,850

 
(8
)
 
131,224

Sales of reserves in place
 
(1,401
)
 
(105,841
)
 
(2,144
)
 
(127,111
)
Production
 
(2,236
)
 
(120,980
)
 
(224
)
 
(135,740
)
December 31, 2014
 
17,687

 
1,155,028

 
441

 
1,263,796


(1)
Total Proved Reserves quantities on a per Mcfe basis are comprised of 91% natural gas, 8% oil, and 1% NGLs. Our future cash inflows from our total Proved Reserves as of December 31, 2014 were comprised of 74% natural gas and 26% oil.
(2)
Revisions of previous estimates include both reserves in place at the beginning of the year, acquisitions and divestitures during the year. There were no reclassifications of Proved Undeveloped Reserves to unproved reserves during 2014 pursuant to the five year development rule established by the SEC.
Purchases of reserves in place

Purchases of reserves in place consisted primarily of our acquisition of certain proved developed producing properties in the Shelby area of East Texas. The reserve quantities attributable to purchases of reserves in place were calculated based on our estimates and assumptions as of the respective acquisition dates.

Discoveries and extensions

Proved Reserves additions from discoveries and extensions in 2014 were 95.5 Bcfe which were primarily due to 48.7 Bcfe, 26.2 Bcfe and 19.7 Bcfe of discoveries and extensions from our Haynesville shale, Eagle Ford shale and Bossier shale, respectively. The discoveries and extensions in the Haynesville and Bossier shales were primarily due to our development of the Shelby area of East Texas. The discoveries and extensions in the Eagle Ford shale were due to continued development of our core area as well as the development of properties as part of a farm-out agreement outside of our core area.

Revisions of previous estimates

Our revisions of previous estimates included upward revisions to our Proved Reserve quantities of 168.3 Bcfe as a result of an increase in price, which extended the economic life of certain producing properties and resulted in the reclassification of unproved locations to Proved Undeveloped properties that became economical when using prices prescribed by the SEC. This change in price was primarily driven by the increase in the trailing 12 month average of natural gas prices from $3.67 per Mmbtu for the year-ended December 31, 2013 to $4.35 per Mmbtu for the year ended December 31, 2014. As


13


a result of the recent decline in oil and natural gas prices, we expect downward revisions to our Proved Reserve quantities in 2015 if prices do not increase. The decrease in price could shorten the economic life of our properties or result in the reclassification of Proved Undeveloped properties to unproved properties if they are not economical when using prices prescribed by the SEC.

Our revisions of previous estimates also included 131.2 Bcfe upward revisions due to performance and other factors. This included 67.1 Bcfe of upward revisions in the Shelby area based on improved well performance as a result of enhanced completion methods including more proppant, longer laterals and a more restricted flowback. The upward revisions also included 45.9 Bcfe from our Appalachia region based on additional historical results incorporated to our reserve estimates which indicated a shallower decline than previously forecasted and improvements to our well design including longer laterals which improved our recoveries.

Sales of reserves in place

Sales of reserves in place primarily consisted of our proportionate share of conventional properties held by Compass which closed on October 31, 2014. The reserve quantities attributable to sales of reserves in place were calculated based on our estimates and assumptions as of the respective divestiture dates.
Oil and natural gas production

Total oil and natural gas production in 2014 was 135.7 Bcfe, which included approximately 3.3 Bcfe in production from extensions and discoveries that were not reflected in our Proved Reserves at January 1, 2014 .

Proved Undeveloped Reserves

The following table summarizes the changes in our Proved Undeveloped Reserves, all of which are expected to be developed within five years, for the year ended December 31, 2014 :
 
 
Mmcfe
Proved Undeveloped Reserves at January 1, 2014
386,954

Purchases of Proved Undeveloped Reserves in place

Sales of Proved Undeveloped Reserves
(4,526
)
New discoveries and extensions (1)
63,018

Proved Undeveloped Reserves transferred to developed (2)
(71,776
)
Proved Undeveloped Reserves transferred to unproved (3)

Other revisions of previous estimates of Proved Undeveloped Reserves (4)
298,916

Proved Undeveloped Reserves at December 31, 2014
672,586


(1)
Approximately 64% , 18% and 18% of the discoveries and extensions of Proved Undeveloped Reserves in 2014 occurred in the Haynesville shale, Bossier shale and Eagle Ford shale, respectively. The discoveries and extensions in the Haynesville and Bossier shales were primarily due to our development of the Shelby area of East Texas.
(2)
Approximately 91% and 9% of the Proved Undeveloped Reserves transferred to Proved Developed Reserves were in the Haynesville shale and Eagle Ford shale, respectively. Capital costs incurred to convert Proved Undeveloped Reserves to Proved Developed Reserves were $132.9 million .
(3)
Represents Proved Undeveloped Reserves that were reclassified to unproved pursuant to the five year development rule established by the SEC. We did not reclassify any Proved Undeveloped Reserves to unproved reserves during 2014.
(4)
The other revisions of previous estimates included upward revisions due to price of 159.8 Bcfe and upward revisions due to performance and other factors of 118.9 Bcfe. The revisions due to price primarily related to increased natural gas prices which resulted in the reclassification of unproved locations to Proved Undeveloped properties that became economical when using the prices prescribed by the SEC. The revisions due to performance and other factors primarily consisted of improved well performance in Haynesville and Bossier shale wells in the Shelby area of East Texas and Marcellus shale wells in the Appalachia region.


14



Impacts of changes in reserves on depletion rate and statements of operations in 2014

Our depletion rate increased to $1.90 per Mcfe in 2014 from $1.47 per Mcfe in 2013 . The increase was primarily due to the acquisition of assets in the Haynesville and Eagle Ford shales during the third quarter of 2013 which increased our depletable base. The oil producing assets in the Eagle Ford shale result in a higher depletion rate when calculated on a per Mcfe basis compared to the rest of our properties.

Our production, prices and expenses

The following table summarizes revenues, net production, average sales price per unit and costs and expenses associated with the production of oil, natural gas and NGLs.
 
 
Year Ended December 31,
(in thousands, except production and per unit amounts)
 
2014
 
2013
 
2012
Revenues, production and prices:
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
Revenue
 
$
196,316

 
$
111,440

 
$
62,119

Production sold (Mbbls)
 
2,236

 
1,188

 
704

Average sales price per Bbl
 
$
87.80

 
$
93.80

 
$
88.24

Natural gas:
 
 
 
 
 
 
Revenue
 
$
457,946

 
$
514,309

 
$
462,422

Production sold (Mmcf)
 
120,980

 
153,321

 
182,644

Average sales price per Mcf
 
$
3.79

 
$
3.35

 
$
2.53

Natural gas liquids:
 
 
 
 
 
 
Revenue
 
$
6,007

 
$
8,560

 
$
22,068

Production sold (Mbbls)
 
224

 
243

 
510

Average sales price per Bbl
 
$
26.82

 
$
35.23

 
$
43.27

Costs and Expenses:
 
 
 
 
 
 
Oil and natural gas operating costs per Mcfe
 
$
0.47

 
$
0.38

 
$
0.41

    
We had two fields that exceeded 15% of our total Proved Reserves as of December 31, 2014 . The Holly field and Shelby field represented approximately 53% and 16% of our total Proved Reserves, respectively. The following table provides additional information related to our Holly and Shelby fields:
 
Year Ended December 31,
 
2014
 
2013
 
2012
Holly field:
 
 
 
 
 
Natural gas production sold (Mmcf)
82,299

 
107,746

 
111,629

Average price per Mcf
$
4.02

 
$
3.39

 
$
2.47

Oil and natural gas operating costs per Mcf
0.22

 
0.13

 
0.11

Shelby field:
 
 
 
 
 
Natural gas production sold (Mmcf)
10,314

 
12,020

 
24,764

Average price per Mcf
$
3.90

 
$
3.32

 
$
2.48

Oil and natural gas operating costs per Mcf
0.33

 
0.28

 
0.17


Our interest in productive wells

The following table quantifies information regarding productive wells (wells that are currently producing oil or natural gas or are capable of production), including temporarily shut-in wells. The number of total gross oil and natural gas wells excludes any multiple completions. Gross wells refer to the total number of physical wells in which we hold a working interest, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects the actual total


15


working interests we hold in all wells. We compute the number of net wells by totaling the percentage interests we hold in all our gross wells.
 
 
At December 31, 2014
 
 
Gross wells (1)
 
Net wells
 
 
Oil
 
Natural gas
 
Total
 
Oil
 
Natural gas
 
Total
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
East Texas/North Louisiana
 

 
691

 
691

 

 
246.6

 
246.6

South Texas
 
220

 
5

 
225

 
108.0

 
2.2

 
110.2

Appalachia and other
 
338

 
5,812

 
6,150

 
165.2

 
2,629.9

 
2,795.1

Total
 
558

 
6,508

 
7,066

 
273.2

 
2,878.7

 
3,151.9

(1)
As of December 31, 2014 , we held interests in 1 gross well with multiple completions.
    
As of December 31, 2014 , we operated 6,559 gross ( 3,095.4 net) wells, which represented approximately 93% of our proved developed producing reserves.

Our drilling activities

Our drilling activities are primarily focused on horizontal drilling in shale plays, particularly in the Haynesville, Bossier, Eagle Ford and Marcellus shales. During 2013, we began drilling activities on the properties acquired in the Eagle Ford shale in South Texas. The following tables summarize our approximate gross and net interests in the operated wells we drilled during the periods indicated and refer to the number of wells completed during the period, regardless of when drilling was initiated. At December 31, 2014 , we had 8 gross ( 3.3 net) wells being drilled and 40 gross ( 14.7 net) wells being completed or awaiting completion.
 
 
 
Development wells
 
 
Gross
 
Net
 
 
Productive
 
Dry
 
Total
 
Productive
 
Dry
 
Total
Year ended December 31, 2014 (1)
 
98

 

 
98

 
29.6

 

 
29.6

Year ended December 31, 2013
 
105

 
2

 
107

 
48.7

 
0.5

 
49.2

Year ended December 31, 2012
 
169

 
2

 
171

 
73.8

 
1.9

 
75.7

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exploratory wells
 
 
Gross
 
Net
 
 
Productive
 
Dry
 
Total
 
Productive
 
Dry
 
Total
Year ended December 31, 2014 (1)
 

 

 

 

 

 

Year ended December 31, 2013 (2)
 
15

 

 
15

 
7.7

 

 
7.7

Year ended December 31, 2012 (3)
 
6

 

 
6

 
2.2

 

 
2.2

(1)
We did not complete any exploratory wells in 2014, but did initiate the drilling of one exploratory well in the Bossier shale in North Louisiana late in 2014. Our development wells in 2014 included the Haynesville and Bossier shales in DeSoto Parish, Louisiana, and the Shelby area of East Texas. Our development wells also included the Eagle Ford shale in our core area in Zavala County, Texas and certain wells outside our core area as part of a farmout agreement. The wells outside of our core area are considered development wells as a result of a successful drilling program in this area in 2014.
(2)
Exploratory wells in 2013 included certain wells drilled in the Eagle Ford shale under the farmout agreement outside of our core area in Zavala County, Texas and certain wells in the Marcellus shale in Jefferson, Clarion and Sullivan Counties, Pennsylvania.
(3)
Exploratory wells in 2012 include certain wells drilled in the Marcellus shale formation in Jefferson and Sullivan Counties, Pennsylvania.


16



Our developed and undeveloped acreage

Developed acreage includes those acres spaced or assignable to producing wells. Undeveloped acreage represents those acres that do not currently have completed wells capable of producing commercial quantities of oil or natural gas, regardless of whether the acreage contains Proved Reserves. The definitions of gross acres and net acres conform to how we determine gross wells and net wells. The following table sets forth our developed and undeveloped acreage:
 
 
At December 31, 2014
 
 
Developed
 
Undeveloped
Area
 
Gross
 
Net
 
Gross
 
Net
East Texas/North Louisiana
 
149,700

 
71,700

 
80,900

 
27,600

South Texas
 
93,500

 
48,100

 
7,900

 
4,800

Appalachia
 
397,300

 
181,000

 
253,500

 
109,000

Other
 
4,400

 
3,200

 
4,200

 
3,900

Total
 
644,900

 
304,000

 
346,500

 
145,300


The primary term of our oil and natural gas leases expire at various dates. Most of our undeveloped acreage is held-by-production, which means that these leases are active as long as we produce oil or natural gas from the acreage or comply with certain lease terms. Upon ceasing production, these leases will expire. We have 22,100, 9,600 and 5,000 net acres with leases expiring in 2015 , 2016 and 2017 , respectively. In addition, we have 11,500 net acres that are subject to continuous drilling obligations which are primarily located in the Shelby area of East Texas. Predominantly all of our expiring acreage is located within our shale resource plays. We are currently evaluating plans to drill on this acreage or extend the term of the leases.
    
The held-by-production acreage in many cases represents potential additional drilling opportunities through down-spacing and drilling of proved undeveloped and unproved locations in the same formation(s) already producing, as well as other non-producing formations, in a given oil or natural gas field without the necessity of purchasing additional leases or producing properties.

Our significant customers

In 2014 , sales to BG Energy Merchants LLC and Chesapeake Energy Marketing Inc. accounted for approximately 34% and 31% , respectively, of our total consolidated revenues. BG Energy Merchants LLC is a subsidiary of BG Group, plc ("BG Group") and Chesapeake Energy Marketing Inc. is a subsidiary of Chesapeake Energy Corporation ("Chesapeake"). The loss of any significant customer may cause a temporary interruption in sales of, or lower price for, our oil and natural gas production. However, we believe that the loss of any one customer would not have a material adverse effect on our results of operations or financial condition.

Competition

The oil and natural gas industry is highly competitive, particularly with respect to acquiring prospective oil and natural gas properties and oil and natural gas reserves. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have substantially greater financial, managerial, technological and other resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas, but also have refining operations, market refined products and their own drilling rigs and oilfield services.
 

The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases and operational delays. Depending on the region, we may experience difficulties in obtaining drilling rigs and other services in certain areas as well as an increase in the cost for these services and related material and equipment. We are unable to predict when, or if, supply or demand imbalances occur or how these market-driven factors impact prices, which affects our development and exploitation programs. Competition also exists for hiring experienced personnel, particularly in petroleum engineering, geoscience, accounting and financial reporting, tax and land professions. In addition, the market for oil and natural gas producing properties is competitive. We are often outbid by competitors in our attempts to acquire properties. The oil and natural gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal. Competitive


17


conditions may be affected by future legislation and regulations as the U.S. develops new energy and climate-related policies. All of these challenges could make it more difficult to execute our growth strategy and increase our costs.

Applicable laws and regulations

General

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Laws and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and financial sanctions for noncompliance. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, we believe these burdens do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

The following is a summary of the more significant existing environmental, safety and other laws and regulations to which our business operations are subject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position.

Production regulation

Our operations are subject to a number of regulations at the federal, state and local levels. These regulations require, among other things, permits for the drilling of wells, drilling bonds and reports concerning operations. Many states, counties and municipalities in which we operate also regulate one or more of the following:

the location of wells;
the method of drilling, completion and operating wells;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells;
notice to surface owners and other third parties; and
produced water and waste disposal.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states, including Louisiana and Texas, allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells and generally prohibit the venting or flaring of natural gas and require that oil and natural gas be produced in a prorated, equitable system. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, most states generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction. Many local authorities also impose an ad valorem tax on the minerals in place. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

Our operations are subject to numerous stringent federal and state statutes and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transportation of oil and natural gas, govern the sourcing, storage and disposal of water used or produced in the drilling and completion process, restrict or prohibit drilling activities in certain areas and on certain lands lying within wetlands and other protected areas, require closing earthen impoundments and impose liabilities for pollution resulting from operations or failure to comply with regulatory filings.

Statutes, rules and regulations that apply to the exploration and production of oil and natural gas are often reviewed, amended, expanded and reinterpreted, making the prediction of future costs or the impact of regulatory compliance to new laws and statutes difficult. The regulatory burden on the oil and natural gas industry increases its cost of doing business and, consequently, adversely affects its (and our) profitability.



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FERC and CFTC matters

The availability, terms and cost of downstream transportation significantly affect sales of natural gas, oil and NGLs. The interstate transportation of natural gas, including regulation of the terms, conditions and rates for interstate transportation and storage of natural gas, is subject to federal regulation by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”). Transportation rates under the NGA must be just and reasonable. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by requiring that interstate natural gas transportation be made available on an open-access, not unduly discriminatory basis. FERC’s jurisdiction under the NGA excludes gathering and distribution of natural gas, so gathering and distribution of natural gas are subject to regulation by individual state laws. State regulations also govern the rates and terms for access to, and transportation of natural gas on, intrastate pipeline facilities (while intrastate pipelines may from time to time provide specific services that are subject to limited regulation by FERC). The interstate transportation of oil and NGLs, including regulation of the rates, terms and conditions of service, is subject to federal regulation by FERC under the Interstate Commerce Act. Rates for such oil and NGLs transportation must be just and reasonable and not unduly discriminatory. Oil and NGLs transportation that is not federally regulated is left to state regulation.

Wholesale prices for natural gas, oil and NGLs are not currently regulated and are determined by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

Under the Energy Policy Act of 2005, FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of natural gas market participants other than intrastate pipelines. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor markets and enforce anti-market manipulation regulations with respect to the physical and financial (futures, options and swaps) energy commodities market pursuant to the Commodity Exchange Act and the Dodd Frank Wall Street Reform and Consumer Protection Act of 2010 (“Dodd Frank Act”). With regard to our physical sales of natural gas, oil and NGLs, our gathering of any of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

Federal, state or Indian oil and natural gas leases

In the event we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement or other appropriate federal, state or tribal agencies.

Surface Damage Acts

In addition, a number of states and some tribal nations have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and specific expenses for exploration and surface activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

Other regulatory matters relating to our pipeline and gathering system assets and rail transportation

The pipelines we use to gather and transport our oil and natural gas are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (“HLPSA”) with respect to oil, and the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”) with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and hazardous liquids pipeline facilities, including pipelines transporting crude oil. Where applicable, the HLPSA and NGPSA also require us and other pipeline operators to comply with regulations issued pursuant to these acts that are designed to permit access to and allow copying of records and to make certain reports available and provide information as required by the Secretary of Transportation.


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 The Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”) mandates requirements in the way that the energy industry ensures the safety and integrity of its pipelines. The law applies to natural gas and hazardous liquids pipelines, including some gathering pipelines. Central to the law are the requirements it places on each pipeline operator to prepare and implement an “integrity management program.” The Pipeline Safety Act mandates a number of other requirements, including increased penalties for violations of safety standards and qualification programs for employees who perform sensitive tasks. The DOT has established a number of rules carrying out the provisions of this act. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a new risk-based approach to determine which gathering pipelines are subject to regulation, and what safety standards regulated pipelines must meet. We could incur significant expenses as a result of these laws and regulations.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law on January 3, 2012. This law includes a number of provisions affecting pipeline owners and operators that became effective upon approval, including increased civil penalties for violators of pipeline regulations and additional reporting requirements. Most of the changes do not impact gathering lines. The legislation requires the PHMSA to issue or revise certain regulations and to conduct various reviews, studies and evaluations. In addition, the PHMSA in August 2011 issued an Advance Notice of Proposed Rulemaking (“ANPR”) regarding pipeline safety. As described in the ANPR, PHMSA is considering regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. If revisions to gathering line regulations are enacted by PHMSA as a result of such ANPR, we could incur significant expenses.

Any transportation of the Company’s crude oil or natural gas liquids by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

In September 2013, the PHMSA issued a final rule updating its regulations to increase the maximum civil penalty from $100,000 to $200,000 for each violation for each day the violation continues, and to increase from $1,000,000 to $2,000,000 the limitation that the maximum administrative civil penalty may not exceed for any related series of violations.

U.S. federal taxation

Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, our share of the domestic “intangible drilling and development costs” and to claim depletion on a portion of our domestic oil and natural gas properties (up to an aggregate of 1,000 Bbls per day of domestic crude oil and/or equivalent units of domestic natural gas). Further, the federal government may adopt tax laws and/or regulations that will possibly materially adversely affect us. Some possible measures that have been proposed in the past include the repeal or elimination of percentage depletion and the immediate deduction or write-offs of intangible drilling costs. Because of the speculative nature of such measures at this time, we are unable to determine what effect, if any, future proposals would have on product demand or our results of operations.

U.S. environmental regulations

The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Federal environmental statutes to which our domestic activities are subject include, but are not limited to:

the Oil Pollution Act of 1990 (“OPA”);
the Clean Water Act of 1972 (“CWA”);
the Rivers and Harbors Act of 1899;
the Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”);
the Resource Conservation and Recovery Act (“RCRA”);
the Clean Air Act (“CAA”); and
the Safe Drinking Water Act (“SDWA”).

In general, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. For example, the United States Environmental Protection Agency (“EPA”) has identified environmental compliance by the energy extraction section as one of its enforcement initiatives for 2014-2016.


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Our domestic activities are subject to regulations promulgated under federal statutes and comparable state statutes. We also are subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Administrative, civil and criminal penalties, as well as injunctive relief, may be imposed for non-compliance with environmental laws and regulations. Additionally, these laws and regulations may require the acquisition of permits or other governmental authorizations before we undertake certain activities, limit or prohibit other activities because of protected areas or species, restrict the types of substances used in our drilling operations, impose certain substantial liabilities for the clean-up of pollution, impose certain reporting requirements, regulate remedial plugging operations to prevent future contamination, and require substantial expenditures for compliance. We cannot predict what effect future regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

Under the CWA, which was amended and augmented by OPA, our release or threatened release of oil or hazardous substances into or upon waters of the United States, adjoining shorelines and wetlands and offshore areas could result in our being held responsible for: (1) the costs of removing or remediating a release; (2) administrative, civil or criminal fines or penalties; or (3) specified damages, such as loss of use, property damage and natural resource damages. The scope of our liability could be extensive depending upon the circumstances of the release. Liability can be joint and several and without regard to fault. The CWA also may impose permitting requirements for discharges of pollutants as well as certain discharges of dredged or fill material into waters of the United States, including certain wetlands, which may apply to various of our construction activities, as well as requirements to develop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines. State laws governing discharges to water also may require permitting provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters.

CERCLA, often referred to as Superfund, and comparable state statutes, impose liability that is generally joint and several and that is retroactive for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a “hazardous substance” or under state law, other specified substances, into the environment. So-called potentially responsible parties (“PRPs”) include the current and certain past owners and operators of a facility where there has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the cost of such action. Liability can arise from conditions on properties where operations are conducted, even under circumstances where such operations were performed by third parties not under our control, and/or from conditions at third party disposal facilities where wastes from operations were sent. Although CERCLA currently exempts petroleum (including oil, natural gas and NGLs) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. We cannot ensure that this exemption will be preserved in any future amendments of the act. Such amendments could have a material impact on our costs or operations. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA or regulated under similar state statutes. We may also be the owner or operator of sites on which hazardous substances have been released.

Oil and natural gas exploration and production, and possibly other activities, have been conducted at a majority of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in certain instances may require remediation. In some instances, we have agreed to indemnify the sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with the properties. We do not believe the costs to be incurred by us for compliance and remediating previously or currently owned or operated properties will be material, but we cannot guarantee that result.

RCRA and comparable state and local programs impose requirements on the management, generation, treatment, storage, disposal and remediation of both hazardous and nonhazardous solid wastes. Although we believe we utilize operating and waste disposal practices that are standard in the industry, hydrocarbons or other solid wastes may have been disposed or released on or under the properties we own or lease, in addition to the locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. We have not had control over such parties' treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We also generate hazardous and non-hazardous solid waste in our routine operations. It is possible that certain wastes generated by our operations, which are currently exempt from “hazardous waste” regulations under RCRA, may in the future be designated as “hazardous waste” under RCRA or other applicable state statutes and become subject to more rigorous and costly management and disposal requirements; these wastes may not be exempt under current applicable state statutes. Non-exempt waste is subject to more rigorous and costly disposal requirements.



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Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. The CAA and analogous state laws require certain new and modified sources of air pollutants to obtain permits prior to commencing construction. Smaller sources may qualify for exemption from permit requirements or for more streamlined permitting, for example, through qualifications for permits by rule, standard permits or general permits. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional operating permits. Federal and state laws designed to control hazardous (i.e., toxic) air pollutants may require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to suspend or forgo construction, modification or operation of certain air emission sources.

On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards (“NSPS”), and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”), programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce volatile organic compound (“VOC”) emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, which became effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We continuously evaluate the effect these rules and amendments will have on our business.

More stringent laws and regulations protecting the environment may be adopted in the future and we may be required to incur material expenses to comply with them. For example, although federal legislation regarding the control of emissions of greenhouse gases (“GHGs”) for the present, appears unlikely, the EPA has been implementing regulatory measures under existing CAA authority and some of those regulations may affect our operations. GHGs are certain gases, including carbon dioxide, a product of the combustion of natural gas, and methane, a primary component of natural gas, that may be contributing to warming of the Earth's atmosphere resulting in climatic changes. These GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce.

There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed in 1972 to preserve and, where possible, restore the natural resources of the coastal zone of the United States. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development. Many states, including Texas, also have coastal management programs, which provide for, among other things, the coordination among local and state authorities to protect coastal resources through regulating land use, water, and coastal development. Coastal management programs also may provide for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the state coastal management plan. In the event our activities trigger these programs, this review of agency rules and actions may impact other agency permitting and review activities, resulting in possible delays or restrictions of our activities and adding an additional layer of review to certain activities undertaken by us.

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If we were to have a portion of our leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

Hydraulic fracturing activities

Over the past few years, there has been an increased focus on environmental aspects of hydraulic fracturing activities in the United States. While hydraulic fracturing is typically regulated by state oil and natural gas commissions in the United States, there have recently been a number of regulatory initiatives at the federal and local levels as well as by other state agencies.



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Nearly all of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Our hydraulic fracturing activities are focused in our shale plays in South Texas, East Texas, North Louisiana and Appalachia. Predominantly all of our undeveloped properties would not be economical without the use of hydraulic fracturing to stimulate production from the well.

The SDWA currently exempts from regulation the injection of fluids or propping agents (other than diesel fuels) for hydraulic fracturing operations. Congress has periodically considered legislation to amend the federal SDWA to remove the exemption from regulation and permitting that is applicable to hydraulic fracturing operations and to require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Sponsors of bills previously introduced before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Many states have considered or adopted legislation regulating hydraulic fracturing, including the disclosure of chemicals used in the process. These bills, or similar legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance.

In addition, the EPA has recently been taking action to assert federal regulatory authority over hydraulic fracturing using diesel under the SDWA's Underground Injection Control Program and has issued guidance regarding its authority over the permitting of these activities. Further, in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. In December 2012, the EPA issued a progress report on its hydraulic fracturing study; a final draft has not been released. The agency also announced that one of its enforcement initiatives for 2014 to 2016 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny or further legislative or regulatory action regarding hydraulic fracturing or similar production operations that could make it difficult to perform hydraulic fracturing and increase our costs of compliance or significantly impact our business, results of operations, cash flows, financial position and future growth.

Additionally, the Bureau of Land Management has proposed regulations on hydraulic fracturing activities on Federal land. The EPA has also announced an initiative under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals, and is working on regulations governing wastewater generated by hydraulic fracturing. In addition, state, local and river basin conservancy districts have all previously exercised their various regulatory powers to curtail and, in some cases, place moratoriums on hydraulic fracturing. Regulations include express inclusion of hydraulic fracturing into existing regulations covering other aspects of exploration and production and specifically may include, but not be limited to, the following:

requirement that logs and pressure test results are included in disclosures to state authorities;
disclosure of hydraulic fracturing fluids, chemicals, proppants and the ratios of same used in operations;
specific disposal regimens for hydraulic fracturing fluid;
replacement/remediation of contaminated water assets; and
minimum depth of hydraulic fracturing.

Local regulations, which may be preempted by state and federal regulations, have included the following which may extend to all operations including those beyond hydraulic fracturing:

noise control ordinances;
traffic control ordinances;
limitations on the hours of operations; and
mandatory reporting of accidents, spills and pressure test failures.

If in the course of our routine oil and natural gas operations, surface spills and leaks occur, including casing leaks of oil or other materials, we may incur penalties and costs for waste handling, remediation and third party actions for damages. Moreover, we are only able to directly control the operations of the wells that we operate. Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may be attributable to us and may impose legal liabilities upon us.

If substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are not fully insured against all of these risks, either because insurance is not available or because of high premiums. Accordingly, we may be subject to liability or may lose substantial


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portions of properties due to hazards that cannot be insured against or have not been insured against due to prohibitive premiums or for other reasons. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

We do not anticipate that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program complying with current environmental laws and regulations. As these laws and regulations are frequently changed and are subject to interpretation, our assessment regarding the cost of compliance or the extent of liability risks may change in the future.

OSHA and other regulations

To the extent not preempted by other applicable laws, we are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, where applicable. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes, where applicable, require that we maintain and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable state requirements.

Title to our properties

When we acquire developed properties we conduct a title investigation, which will most often include either reviewing or obtaining a title opinion. However, when we acquire undeveloped properties, as is common industry practice, we usually conduct little or no investigation of title other than a preliminary review of local real property and/or mineral records. We will conduct title investigations and, in most cases, obtain a title opinion of local counsel for the drill site before we begin drilling operations. We believe that the methods we utilize for investigating title prior to acquiring any property are consistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire marketable title to properties. However, some title risks cannot be avoided, despite the use of customary industry practices.
    
Our properties are generally burdened by:

customary royalty and overriding royalty interests;
liens incident to operating agreements; and
liens for current taxes and other burdens and minor encumbrances, easements and restrictions.

We believe that none of these burdens materially detract from the value of our properties or materially interfere with property used in the operation of our business. In addition to the foregoing listed burdens, substantially all of our properties are pledged as collateral under the EXCO Resources Credit Agreement.

Operational factors and insurance

Oil and natural gas exploration and development involves a high degree of risk. In the event of explosions, environmental damage, or other accidents such as well fires, blowouts, equipment failure and human error, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in the loss of oil and natural gas properties. As is common in the oil and natural gas industry, we are not fully insured against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our operating results, financial position or cash flows. For further discussion on risks see “Item 1A. Risk Factors - We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flows.”  
  
We currently carry automobile liability, general liability insurance and excess liability insurance with a combined annual limit of $101 million per occurrence and in the aggregate. These insurance policies contain maximum policy limits and deductibles ranging from $1,000 to $50,000 that must be met prior to recovery, and are subject to customary exclusions and limitations. Our automobile and general liability insurance covers us and our subsidiaries for third-party claims and liabilities arising out of lease operations and related activities. The excess liability insurance is in addition to, and is triggered if; the automobile and general liability insurance per occurrence limit is reached. Further, we currently carry $65 million of pollution coverage and $30 million of cost of well control (blowout) coverage with deductibles ranging from $100,000 to $500,000.



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We require our third-party contractors to sign master service agreements in which they generally agree to indemnify us for the injury and death of the service provider's employees as well as contractors and subcontractors that are hired by the service provider. Similarly, we agree to indemnify our third-party contractors against claims made by our employees and our other contractors. Additionally, each party generally is responsible for damage to its own property.

Our third-party contractors that perform hydraulic fracturing operations for us sign master service agreements containing the indemnification provisions noted above. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. We believe that our general liability, excess liability and pollution insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. However, these policies generally will not cover fines and penalties. Further, these policies may not cover the costs and expenses related to government-mandated environmental clean-up responsibilities, or may do so on a limited basis.
    
Our employees

As of December 31, 2014, we employed 558 persons. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we consider our relations with our employees to be satisfactory. We also utilize the services of independent consultants and contractors.

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

our future financial and operating performance and results;
our business strategy;
market prices;
our future use of 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 publicly 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 prospectus and the documents incorporated herein by reference, 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, including our ability to maintain compliance with our debt covenants;
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;
availability of water and other materials for drilling and completion activities;
marketing of oil and natural gas;


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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 risk factors and other cautionary statements in this Annual Report on Form 10-K. The risk factors noted in this Annual Report on Form 10-K provide examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement. Please see “Risk Factors” for a discussion of certain risks related to our business, indebtedness and common shares.

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

Glossary of selected oil and natural gas terms
    
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this Annual Report on Form 10-K.
2-D seismic.  Geophysical data that depicts the subsurface strata in two dimensions.
3-D seismic.  Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.
Appraisal wells.  Wells drilled to convert an area or sub-region from the resource to the reserves category.
Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drive mechanism.
Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs or other liquid hydrocarbons.
Bcf.  One billion cubic feet of natural gas.
Bcfe.  One billion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf is commonly used in the oil and natural gas industry and represents the approximate energy equivalent of natural gas to oil or NGLs, and does not represent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales price of six Mcf of natural gas.
Boepd. Barrels of oil equivalent per day.


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Btu.  British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion.  The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry hole, the reporting to the appropriate authority that the well has been abandoned.
Deterministic method.  The method of estimating reserves or resources when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
Developed acreage.  The number of acres which are allocated or assignable to producing wells or wells capable of production.
 
Development well.  A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole; Dry well.  A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Economically producible.  As it relates to a resource, a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
Exploitation.  The continuing development of a known producing formation in a previously discovered field. To maximize the ultimate recovery of oil or natural gas from the field by development wells, secondary recovery equipment or other suitable processes and technology.
Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well.
Farmout.  An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.
Formation.  A succession of sedimentary beds that were deposited under the same general geologic conditions.
Fracture stimulation.  A stimulation treatment routinely performed involving the injection of water, sand and chemicals under pressure to stimulate hydrocarbon production.
Full cost pool.  The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.
Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.
Held-by-production. A provision in an oil, natural gas and mineral lease that perpetuates a company's right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or natural gas.
Horizontal wells.  Wells which are drilled at angles greater than 70 degrees from vertical.
Initial production rate.  Generally, the maximum 24 hour production volume from a well.
Mbbl.  One thousand stock tank barrels.
Mcf.  One thousand cubic feet of natural gas.
Mcfe.  One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.
Mmbbl.  One million stock tank barrels.
Mmbtu.  One million British thermal units.
Mmcf.  One million cubic feet of natural gas.
Mmcf/d.  One million cubic feet of natural gas per day.
Mmcfe.  One million cubic feet of natural gas equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf is commonly used in the oil and natural gas industry and represents the approximate energy equivalent of natural gas to oil or NGLs, and does not represent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales price of six Mcf of natural gas.  
Mmcfe/d.  One million cubic feet of natural gas equivalent per day calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.


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Mmmbtu.  One billion British thermal units.
Net acres or net wells.  Exists when t he sum of fractional ownership interests owned in gross acres or gross wells equals one. We compute the number of net wells by totaling the percentage interest we hold in all our gross wells.
NYMEX.  New York Mercantile Exchange.
NGLs.  The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
Overriding royalty interest.  An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of the costs of production.
Pad drilling.  The drilling of multiple wells from the same site.
Play.  A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and natural gas reserves.
Present value of estimated future net revenues or PV-10.  The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, without giving effect to derivative financial instrument activities, after deducting production and ad valorem taxes, future capital costs, abandonment costs and operating expenses, but before deducting future income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil and natural gas prices and operating and capital costs at the date indicated, at its acquisition date, or as otherwise indicated.
Probabilistic method.  The method of estimation of reserves or resources when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
Productive well.  A productive well is a well that is not a dry well.
Proved Developed Reserves.  These reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved Reserves.  Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with Reasonable Certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with Reasonable Certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with Reasonable Certainty. Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with Reasonable Certainty.
  Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the Reasonable Certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each


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month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved Undeveloped Reserves.  Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes Reasonable Certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing Reasonable Certainty.
Recompletion.  An operation within an existing well bore to make the well produce oil and/or natural gas from a different, separately producible zone other than the zone from which the well had been producing.
Reasonable Certainty.  If deterministic methods are used, Reasonable Certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery ("EUR") with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Resources.  Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
Royalty interest.  An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of the costs of production.
Shale.  Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
Shut-in well . A producing well that has been closed down temporarily for, among other things, economics, cleaning out, building up pressure, lack of a market or lack of equipment.  
Spud.  To start the well drilling process.
Standardized Measure of discounted future net cash flows or the Standardized Measure.  Under the Standardized Measure, future cash flows are estimated by applying the simple average spot prices for the trailing 12 month period using the first day of each month beginning on January 1 and ending on December 1 of each respective year, adjusted for price differentials, to the estimated future production of year-end Proved Reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end and future plugging and abandonment costs to determine pre-tax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.
Stock tank barrel.  42 U.S. gallons liquid volume.
Tcf.  One trillion cubic feet of natural gas.
Tcfe.  One trillion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf is commonly used in the oil and natural gas industry and represents the approximate energy equivalent of natural gas to oil or NGLs, and does not represent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales price for six Mcf of natural gas.
Undeveloped acreage.  Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains Proved Reserves.


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Working interest.  The operating interest that gives the owner the right to drill, produce and conduct activities on the property and a share of production.
Workovers.  Operations on a producing well to restore or increase production.
Available information
    
We make available, free of charge, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to these reports on our website at www.excoresources.com as soon as reasonably practicable after those reports and other information is electronically filed with, or furnished to, the SEC.
 
Item 1A.
Risk Factors

The risk factors noted in this section and other factors noted throughout this Annual Report on Form 10-K, including those risks identified in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” describe examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement.
    
If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this Annual Report on Form 10-K.

Risks Relating to Our Business

Fluctuations in oil and natural gas prices, which have been volatile at times, may adversely affect our revenues as well as our ability to maintain or increase our borrowing capacity, repay current or future indebtedness and obtain additional capital on attractive terms.

Our future financial condition, access to capital, cash flow and results of operations depend upon the prices we receive for our oil and natural gas. We are particularly dependent on prices for natural gas. As of December 31, 2014, approximately 91% of our Proved Reserves were natural gas and approximately 89% of our production was natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Factors that affect the prices we receive for our oil and natural gas include:

supply and demand for oil and natural gas and expectations regarding supply and demand;
the level of domestic production;
the availability of imported oil and natural gas;
federal regulations generally prohibiting the export of U.S. crude oil;
federal regulations applicable to the export of, and construction of export facilities for natural gas and NGLs.
political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
the cost and availability of transportation and pipeline systems with adequate capacity;
the cost and availability of other competitive fuels;
fluctuating and seasonal demand for oil, natural gas and refined products;
concerns about global warming or other conservation initiatives and the extent of governmental price controls and regulation of production;
regional price differentials and quality differentials of oil and natural gas;
the availability of refining capacity;
technological advances affecting oil and natural gas production and consumption;
weather conditions and natural disasters;
foreign and domestic government relations; and
overall economic conditions.
 
In the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. During 2014, the NYMEX price for natural gas fluctuated from a high of $6.15 per Mmbtu to a low of $2.89 per Mmbtu, while the NYMEX West Texas Intermediate crude oil price ranged from a high of $107.26 per Bbl to a low of $53.27 per Bbl. For the five years ended December 31, 2014, the NYMEX Henry Hub natural gas price ranged from a high of $6.15 per Mmbtu to a


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low of $1.91 per Mmbtu, while the NYMEX West Texas Intermediate crude oil price ranged from a high of $113.93 per Bbl to a low of $53.27 per Bbl. On December 31, 2014, the spot market price for natural gas at Henry Hub was $2.89 per Mmbtu, a 32% decrease from December 31, 2013. On December 31, 2014, the spot market price for crude oil at Cushing was $53.27 per Bbl, a 46% decrease from December 31, 2013. For 2014, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $87.80 per Bbl and $3.79 per Mcf, respectively, compared with 2013 average realized prices of $93.80 per Bbl and $3.35 per Mcf, respectively.
 
Our revenues, cash flow and profitability and our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms depend substantially upon oil and natural gas prices.

Changes in the differential between NYMEX or other benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we use to price our oil and natural gas sales sometimes reflect a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could have a material adverse effect on our results of operations and financial condition. We have recently experienced significant volatility in our price differentials including crude oil production from the Eagle Ford shale and natural gas production from certain areas in Appalachia. Our crude oil production from the Eagle Ford shale is currently sold at a price based on the Phillips 66 West Texas Intermediate index plus or minus the differential to the Argus Louisiana Light Sweet index. During 2014, this differential ranged from a high of $7.93 per barrel to a low of $2.21 per barrel. Our natural gas production from the Marcellus shale in Northeast Pennsylvania is sold at a price based on a Platts index that represents value into the Transco Leidy Pipeline. Due to the increased production in this region without an offsetting increase in pipeline capacity or infrastructure to the Northeast United States markets, this differential in 2014 ranged from a low of NYMEX less $1.32 per Mmbtu to a high of NYMEX less $2.94 per Mmbtu. These differentials vary depending on factors such as supply, demand, pipeline capacity, infrastructure, and weather.

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

Our ability to market our oil and natural gas production will depend upon the availability and capacity of gathering systems, pipelines and other transportation facilities. We are primarily dependent upon third parties to transport our production. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs, outages caused by accidents or other events, or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. We have experienced production curtailments in our producing regions resulting from capacity restraints, offsetting fracturing stimulation operations and short term shutdowns of certain pipelines for maintenance purposes. As we have increased our knowledge of our shale properties, we have begun to shut in production on adjacent wells when conducting completion operations. Due to the high production capabilities of these wells, these volumes can be significant. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas and the value of our common shares.

We have entered into marketing agreements with third-parties to sell a significant percentage of our anticipated oil and natural gas production in the East Texas/North Louisiana and South Texas regions. If these third-parties are unable or otherwise fail to market the oil and natural gas we produce, we would be required to find alternate means to market our production, which could increase our costs, reduce the revenues we might obtain from the sale of our oil and natural gas production or have a material adverse effect on our business, results of operations or financial condition.



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We may experience a financial loss if any of our significant customers fail to pay us for our oil or natural gas.

Our ability to collect payments from the sale of oil and natural gas to our customers depends on the payment ability of our customer base, which includes several significant customers. If any one or more of our significant customers fails to pay us for any reason, we could experience a material loss. In addition, in recent years, it has become more difficult to maintain and grow a customer base of creditworthy customers because a number of energy marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for our oil and natural gas production. As a result, we may experience a material loss as a result of the failure of our customers to pay us for prior purchases of our oil or natural gas. In addition, the loss of any significant customer may cause a temporary interruption in sales of, or a lower price for, our oil and natural gas.
 
Market conditions or operational impediments, such as lack of available transportation or infrastructure, may hinder our production or adversely impact our ability to receive market prices for our production or to achieve expected drilling results.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements or infrastructure may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations owned and operated by third-parties. Our failure to obtain these services on acceptable terms could have a material adverse effect on our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines, gathering systems or trucking capacity. A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, excessive pressures, maintenance, weather, field labor issues or other disruptions of service. Curtailments and disruptions may last from a few days to several months, and we have no control over when or if third-party facilities are restored.

In the past we have experienced production curtailments due to infrastructure and market constraints in the Eagle Ford shale formation, which has caused natural gas production to either be shut in or flared. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities or lack of availability of transportation would interfere with our ability to market our oil and natural gas production, and could have a material adverse effect on our cash flow and results of operations.

We have entered into significant natural gas firm transportation and marketing agreements primarily in East Texas and North Louisiana that require us to pay fixed amounts of money to the shippers or marketers regardless of quantities actually shipped or marketed. If we are unable to deliver the necessary quantities of natural gas, our results of operations and liquidity could be adversely affected.

We have entered into significant natural gas firm transportation contracts primarily in East Texas and North Louisiana that require us to pay fixed amounts of money to the shippers regardless of quantities actually shipped. The use of firm transportation agreements allows us priority space in a shippers’ pipeline.

We have entered into an agreement to deliver an aggregate minimum volume commitment of natural gas production from the Holly and Shelby fields to certain gathering systems over a five year period. If there is a shortfall to the minimum volume commitment in any year, then we are severally responsible with a joint venture partner to pay fixed amounts of money to the gatherer regardless of quantities actually produced in to the systems.

In addition, we have also entered into a marketing agreement with respect to our Haynesville production whereby we are required to deliver a minimum amount of natural gas from the Haynesville shale. We will be required to make material expenditures for these agreements if we fail to deliver the required quantities of natural gas in the future.

We anticipate the deliveries of natural gas in future periods will not meet the minimum quantities set forth in certain of these agreements and will require us to make payments for the shortfall below the minimum quantities. In the event the quantities delivered under these arrangements are significantly below the minimum volumes within the agreements, it could adversely affect our business, financial condition and results of operations.
    


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There are risks associated with our drilling activity that could impact our results of operations and financial condition. Our ability to develop properties in new or emerging formations may be subject to more uncertainties than drilling in areas that are more developed or have a longer history of established production.

Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to identify and acquire properties and to drill and complete wells. Additionally, seismic and other technology does not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment. We have experienced some delays in contracting for drilling rigs, obtaining fracture stimulation crews and materials, which result in increased costs to drill wells. Also, we may experience issues with the availability of water and sand used in our drilling and hydraulic fracturing activities. All of these risks could adversely affect our results of operations and financial condition.

The results of our drilling in new or emerging formations, including our properties in shale formations, are more uncertain initially than drilling results in areas that are developed, have established production or where we have a longer history of operation. Because new or emerging formations have limited or no production history, we are less able to use past drilling results in those areas to help predict future drilling results. Our experience with horizontal drilling in these areas to date, as well as the industry’s drilling and production history, while growing, is limited. The ultimate success of these drilling and completion techniques will be better evaluated over time as more wells are drilled and production profiles are better established. We plan to implement several initiatives to manage our base production and minimize the decline from our shale properties. If these initiatives are not successful and we are required to incur significant expenditures to manage our base production, this could negatively impact our production and cash flows from operations.
    
If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, and/or natural gas and oil prices decline, our investment in these areas may not be as attractive as we anticipate and we could incur material impairments of undeveloped properties and the value of our undeveloped acreage could decline in the future, which could have a material adverse effect on our business and results of operations.

Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on the acreage.

Leases on oil and natural gas properties typically have a term after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. While we seek to actively manage our leasehold inventory through drilling wells to hold the leasehold acreage that we believe is material to our operations, our drilling plans for these areas are subject to change.

We conduct a substantial portion of our operations through joint ventures, and our failure to continue such joint ventures or resolve any material disagreements with our partners could have a material adverse effect on the success of these operations, our financial condition and our results of operations. Furthermore, the actions taken by other working interest owners could prevent or alter our development plans.

We conduct a substantial portion of our operations through joint ventures with third parties, principally BG Group and Kohlberg Kravis Roberts & Co. L.P. ("KKR"), and as a result, the continuation of such joint ventures is vital to our continued success. We may also enter into other joint venture arrangements in the future. In many instances we depend on these third parties for elements of these arrangements that are important to the success of the joint venture, such as agreed payments of substantial development costs pertaining to the joint venture and their share of other costs of the joint venture. The performance of these third party obligations or the ability of third parties to meet their obligations under these arrangements is outside our control. If these parties do not meet or satisfy their obligations under these arrangements, the performance and success of these arrangements, and their value to us, may be adversely affected. If our current or future joint venture partners are unable to meet their obligations, we may be forced to undertake the obligations ourselves and/or incur additional expenses in order to have some other party perform such obligations. In such cases we may also be required to enforce our rights, which may cause disputes among our joint venture partners and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations, these joint ventures and/or our ability to enter into future joint ventures.

Such joint venture arrangements may involve risks not otherwise present when exploring and developing properties directly, including, for example:


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our joint venture partners may share certain approval rights over major decisions;
the possibility that our joint venture partners might become insolvent or bankrupt, leaving us liable for their shares of joint venture liabilities;
the possibility that we may incur liabilities as a result of an action taken by our joint venture partners;
joint venture partners may be in a position to take action contrary to our instructions or requests or contrary to our policies or objectives;
disputes between us and our joint venture partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects and prevent our officers and directors from focusing their time and effort on our business;
that under certain joint venture arrangements, neither joint venture partner may have the power to control the venture, and an impasse could be reached which might have a negative influence on our investment in the joint venture; and
our joint venture partners may decide to terminate their relationship with us in any joint venture company or sell their interest in any of these companies and we may be unable to replace such joint venture partner or raise the necessary financing to purchase such joint venture partner’s interest.
 
The failure to continue some of our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn negatively affect our financial condition and results of operations.

The owners of working interests may not consent to the development of certain properties that we operate which may require us to assume their share of the working interest during the development and a period after the well is on production. This may require us to expend additional capital not already anticipated as part of our development plans and assume additional risks associated with the development and future performance of the properties. The owners of working interests in certain properties that we operate may also hold rights within the respective operating agreements that could prevent us from performing additional development activities on the properties such as recompletions and other workovers without their consent.

We may be unable to obtain additional financing to implement our growth strategy.

The growth of our business will require substantial capital on a continuing basis. Due to the amount of debt we have incurred, it may be difficult for us in the foreseeable future to obtain additional debt financing or to obtain additional secured financing other than purchase money indebtedness. If we are unable to obtain additional capital on satisfactory terms and conditions or at all, we may lose opportunities to acquire oil and natural gas properties and businesses and, therefore, be unable to implement our growth strategy.

We may be unable to acquire or develop additional reserves, which would reduce our revenues and access to capital.

Our success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are profitable to produce. Factors that may hinder our ability to acquire or develop additional oil and natural gas reserves include competition, access to capital, prevailing oil and natural gas prices and the number and attractiveness of properties for sale. If we are unable to conduct successful development activities or acquire properties containing Proved Reserves, our total Proved Reserves will generally decline as a result of production. Also, our production will generally decline. In addition, if our reserves and production decline, then the amount we are able to borrow under the EXCO Resources Credit Agreement will also decline. We may be unable to locate additional reserves, drill economically productive wells or acquire properties containing Proved Reserves.
 
Acquisitions, development drilling and exploratory drilling are the main methods of replacing reserves. However, development and exploratory drilling operations may not result in any increases in reserves for various reasons. Our future oil and natural gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. The planned reduction in our development program in 2015 compared to prior years could negatively impact our ability to replace our reserves in the future.



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We may not identify all risks associated with the acquisition of oil and natural gas properties, and any indemnification we receive from sellers may be insufficient to protect us from such risks, which may result in unexpected liabilities and costs to us.

Generally, it is not feasible for us to review in detail every individual property involved in an acquisition. Our business strategy focuses on acquisitions of producing oil and natural gas properties. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards and liabilities, potential tax and Employee Retirement Income Security Act of 1974 liabilities, other liabilities and similar factors. Ordinarily, our review efforts are focused on the higher-valued properties. Even a detailed review of properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems from acquisitions could result in material liabilities and costs that could negatively impact our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnify us against all or part of these problems. Even if a seller agrees to provide indemnification, the indemnification may not be fully enforceable and may be limited by floors and caps on such indemnification.

If we are unable to complete the joint development of our assets in the Eagle Ford shale formation with KKR, we may need to find alternative sources of capital, which may not be available on favorable terms, or at all.

On July 31, 2013, we closed the acquisition of certain producing and non-producing oil, natural gas and mineral leases and wells in the Eagle Ford shale located in Zavala, Dimmit and Frio counties in South Texas. In connection with the closing of the acquisition of the Eagle Ford assets, we sold an undivided 50% interest in the undeveloped acreage to affiliates of KKR for approximately $130.9 million. With respect to each well drilled, we will assign half of our undivided 50% interest in such well to KKR such that KKR will fund and own 75% of each well drilled and we will fund and own 25% of each well drilled. There can be no assurance that KKR will elect to proceed with subsequent phases of the development of our Eagle Ford assets. If we cannot identify an alternative joint venture partner or partners for our Eagle Ford assets, sell assets at acceptable valuations or are unable to complete the joint development of our Eagle Ford assets, we will need to utilize cash flow from other operations or will need to find alternative sources of capital to finance the development of the Eagle Ford assets, which may slow the development of these assets and have a material adverse effect on our operations and prospects.

While we are required to make offers to purchase KKR’s interest in certain wells, we may not have sufficient funds or borrowing capacity under the EXCO Resources Credit Agreement to complete the acquisitions pursuant to the KKR Participation Agreement. In the event we fail to purchase a group of wells that KKR is obligated to sell, there are remedies available to KKR which allow KKR to reject future EXCO offers, terminate the KKR Participation Agreement, or pursue other legal remedies. This could require us to seek alternative financing to make offers to preserve KKR’s obligation to sell to us, or negatively impact our ability to increase our Eagle Ford assets through acquisitions of KKR’s producing properties.

We may not correctly evaluate reserve data or the exploitation potential of properties as we engage in our acquisition, exploration, development and exploitation activities.

Our future success will depend on the success of our acquisition, exploration, development and exploitation activities. Our decisions to purchase, explore, develop or otherwise exploit properties or prospects will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. These decisions could significantly reduce our ability to generate cash needed to service our debt and fund our capital program and other working capital requirements.

We may be unable to integrate successfully the operations of acquisitions with our operations and we may not realize all the anticipated benefits of any acquisitions.

Integration of our acquisitions with our business and operations has been a complex, time consuming and costly process. Failure to successfully assimilate our past or future acquisitions could adversely affect our financial condition and results of operations.

Our acquisitions involve numerous risks, including:



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operating a significantly larger combined organization and adding operations;
difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new business segment or geographic area;
the risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;
the loss of significant key employees from the acquired business;
the diversion of management’s attention from other business concerns;
the failure to realize expected profitability or growth;
the failure to realize expected synergies and cost savings;
coordinating geographically disparate organizations, systems and facilities; and
coordinating or consolidating corporate and administrative functions.
 
Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.
 
Our estimates of oil and natural gas reserves involve inherent uncertainty, which could materially affect the quantity and value of our reported reserves, our financial condition and the value of our common shares.

Numerous uncertainties are inherent in estimating quantities of Proved Reserves, including many factors beyond our control. This Annual Report on Form 10-K contains estimates of our Proved Reserves and the PV-10 and Standardized Measure of our Proved Reserves. These estimates are based upon reports of our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These estimates should not be construed as the current market value of our estimated Proved Reserves.

The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. As a result, the estimates are inherently imprecise evaluations of reserve quantities and future net revenue and such estimates prepared by different engineers or by the same engineers at different times, may vary substantially.

Our actual future production, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from those we have assumed in the estimates. Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of PV-10 and Standardized Measure described in this Annual Report on Form 10-K, and our financial condition. In addition, our reserves, the amount of PV-10 and Standardized Measure may be revised downward or upward, based upon production history, results of future exploitation and development activities, prevailing oil and natural gas prices, decisions and assumptions made by engineers and other factors. A material decline in prices paid for our production can adversely impact the estimated volumes and values of our reserves. Similarly, a decline in market prices for oil or natural gas may adversely affect our PV-10 and Standardized Measure. Any of these negative effects on our reserves or PV-10 and Standardized Measure may negatively affect the value of our common shares.

We may have impairments of our asset values, which could negatively affect our results of operations and net worth.

We follow the full cost method of accounting for our oil and natural gas properties. Depending upon oil and natural gas prices in the future, and at the end of each quarterly and annual period when we are required to test the carrying value of our assets using full cost accounting rules, we may be required to record an impairment to the value of our oil and natural gas properties if the present value of the after-tax future cash flows from our oil and natural gas properties falls below the net book value of these properties. We have in the past experienced, and may experience in the future, ceiling test impairments with respect to our oil and natural gas properties.

Our evaluation of impairment is based upon estimates of Proved Reserves. The value of our Proved Reserves may be lowered in future periods as a result of a decline in prices of oil and natural gas, a downward revision of our oil and natural gas reserves or other factors. As a result, our evaluation of impairment for future periods is subject to 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. Because several of these factors are beyond our control, we cannot accurately predict or control


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the amount of ceiling test impairments in future periods. Future ceiling test impairments could negatively affect our results of operations and net worth.

For the year ended December 31, 2014 , we did not recognize any impairments to our proved oil and natural gas properties. For the years ended December 31, 2013 and 2012 , we recognized impairments of $108.5 million and $1.3 billion , respectively, to our proved oil and natural gas properties. We may have additional impairments of our oil and natural gas properties in future periods if the cost of our unamortized proved oil and natural gas properties exceeds the limitation under the full cost method of accounting. As a result of recent decline in oil and natural gas prices, we expect to recognize additional impairments to our oil and natural gas properties in 2015 if prices do not increase.
    
We also test goodwill for impairment annually or when circumstances indicate that an impairment may exist. If the book value of our reporting units exceeds the estimated fair value of those reporting units, an impairment charge will occur, which would negatively impact our results of operations and net worth. As a result of our testing of goodwill for impairment, we did not record an impairment charge for the periods ended December 31, 2014 , 2013 and 2012 .

We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.

Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

fires, explosions and blowouts;
pipe failures;
abnormally pressured formations; and
environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).

We have in the past experienced some of these events during our drilling, production and midstream operations. These events may result in substantial losses to us from:

injury or loss of life;
severe damage to or destruction of property, natural resources and equipment;
pollution or other environmental damage;
environmental clean-up responsibilities;
regulatory investigation;
penalties and suspension of operations; or
attorneys’ fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in our industry, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover these potential losses or liabilities. Furthermore, insurance coverage may not continue to be available at commercially acceptable premium levels or at all. Due to cost considerations, from time to time we have declined to obtain coverage for certain drilling activities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events could require us to make large unbudgeted cash expenditures that could adversely impact our results of operations and cash flow.

Our operations may be interrupted by severe weather or drilling restrictions.

Our operations are conducted primarily in Texas, North Louisiana and Appalachia. The weather in these areas can be extreme and can cause interruption in our exploration and production operations. Severe weather can result in damage to our facilities entailing longer operational interruptions and significant capital investment.
 
Likewise, our operations are subject to disruption from earthquakes, hurricanes, winter storms and severe cold, which can limit operations involving fluids and impair access to our facilities. Additionally, many municipalities in Appalachia impose weight restrictions on the paved roads that lead to our jobsites due to the conditions caused by spring thaws.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain


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numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to comply with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.
Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, production and sale of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition and results of operations.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

The Obama administration’s budget proposals for fiscal year 2016 contain numerous proposed tax changes, and from time to time, legislation has been introduced that would enact many of these proposed changes. The proposed budget and legislation would repeal many tax incentives and deductions that are currently used by U.S. oil and natural gas companies and impose new fees. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domestic manufacturing tax deduction for oil and natural gas companies; increase in the geological and geophysical amortization period for independent producers. The passage of legislation containing some or all of these provisions or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available to us with respect to oil and natural gas exploration and development, and any such change could have a material adverse effect on our business, financial condition and results of operations.

The EPA’s implementation of climate change regulations could result in increased operating costs and reduced demand for our oil and natural gas production.

Although federal legislation regarding the control of emissions of GHGs for the present appears unlikely, the EPA has been implementing regulations under existing CAA authority, some of which may affect our operations. GHGs are certain gases, including carbon dioxide, a product of the combustion of natural gas, and methane, a primary component of natural gas, that may be contributing to the warming of the Earth’s atmosphere, resulting in climatic changes. These GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for our oil and natural gas production.

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. The EPA established GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although this rule does not limit the amount of GHGs that can be emitted, it requires us to incur costs to monitor, record and report GHG emissions associated with our operations. The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations. The measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and natural gas production sources and natural gas processing and transmission sources. In addition, some states have considered, and notably California has adopted, a state specific GHG regulatory program that may limit GHG emissions or may require costs in association with the control of GHG emissions.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Most hydraulic fracturing (other than hydraulic fracturing using diesel) is exempted from regulation under the SDWA. Congress has considered legislation to amend the federal SDWA to remove the exemption from regulation and permitting that is applicable to hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Sponsors of bills previously introduced before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Many states have adopted or are considering legislation regulating hydraulic fracturing, including the disclosure of chemicals used in the process. Such bills or similar legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance. At the state and local levels, some jurisdictions have adopted, and others are considering adopting, requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities, as well as bans on hydraulic fracturing activities. In the event that new or more stringent state or local legal


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restrictions relating to the hydraulic fracturing process are adopted in areas where we have properties, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program ("UIC"). Further, in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. Interim results of the study were expected in 2012; although final results are not yet available. The agency also announced that one of its enforcement initiatives for 2014 through 2016 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur further legislative or regulatory action regarding hydraulic fracturing or similar production operations.

In addition, the EPA has issued guidance under the SDWA providing direction on how it will address the use of diesel in hydraulic fracturing activities and how its UIC will be applied to such hydraulic fracturing activities. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. The Bureau of Land Management has proposed draft rules to regulate hydraulic fracturing on federal lands and the EPA has announced an initiative under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. If hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operations restrictions and also to associated permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we ultimately are able to produce.
 
Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures.

Our operations are subject to numerous complex U.S. federal, state and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. We could incur material costs, including clean-up costs, fines and civil and criminal sanctions (including injunctive relief) and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken. In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent, for example, the regulation of GHG emissions under the federal CAA, or state or regional regulatory programs. Regulation of GHG emissions by the EPA, or various states in the United States in areas in which we conduct business, for example, could have an adverse effect on our operations and demand for our oil and natural gas production. Moreover, the EPA has shown a general increased scrutiny on the oil and gas industry through its GHG, CAA and SDWA regulations.

The EPA has adopted rules subjecting oil and natural gas operations to regulation under the New Source Performance Standards ("NSPS"), and the National Emissions Standards for Hazardous Air Pollutants, ("NESHAPS"), programs under the CAA, and imposing new and amended requirements under both programs. Among other things, the rule amends standards applicable to natural gas processing plants and expands the NSPS to include all oil and natural gas operations, imposing requirements on those operations. The rule also imposes NSPS standards for completions of hydraulically fractured natural gas wells. These standards include the reduced emission completion techniques. Additionally, the EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations. The measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and natural gas production sources and natural gas processing and transmission sources. The NESHAPS also includes maximum achievable control technology standards for certain glycol dehydrators and storage vessels, and revises applicability provisions, alternative test protocols and the availability of the startup, shutdown and maintenance exemption. The implementation of these new requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations.



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Competition in our industry is intense and we may be unable to compete in acquiring properties, contracting for drilling equipment and hiring experienced personnel.

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have greater financial and technical resources and a larger headcount than we do. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant expense/cost increases. We may experience difficulties in obtaining drilling rigs and other services in certain areas as well as an increase in the cost for these services and related material and equipment. We are unable to predict when, or if, such shortages may again occur or how such shortages and price increases will affect our development and exploitation program. Competition has also been strong in hiring experienced personnel, particularly in petroleum engineering, geoscience, accounting and financial reporting, tax and land professions. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. We are often outbid by competitors in our attempts to acquire properties or companies. All of these challenges could make it more difficult to execute our growth strategy.

We are currently involved in a search for a new chief executive officer and if this search is further delayed or if we were to lose the services of other key personnel, our business could be negatively impacted.

We have been engaged in a search for a new chief executive officer since November 2013. To the extent there is a further delay in choosing a new chief executive officer, our business could be negatively impacted. In addition, our future success depends in part upon the continued service of key members of our senior management team. Our senior management team is critical to our management and they also play a key role in maintaining our culture and setting our strategic direction. All of our executive officers and key employees are at-will employees. The loss of key personnel could seriously harm our business.

Our use of derivative financial instruments is subject to risks that our counterparties may default on their contractual obligations to us and may cause us to forego additional future profits or result in us making cash payments.
    
To reduce our exposure to changes in the prices of oil and natural gas, we have entered into, and may in the future enter into, derivative financial instrument arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our derivative financial instruments are subject to mark-to-market accounting treatment. The change in the fair market value of these instruments is reported as a non-cash item in our consolidated statements of operations each quarter, which typically results in significant variability in our net income. Derivative financial instruments expose us to the risk of financial loss and may limit our ability to benefit from increases in oil and natural gas prices in some circumstances, including the following:

market prices may exceed the prices which we are contracted to receive, resulting in our need to make significant cash payments;
there may be a change in the expected differential between the underlying price in the derivative financial instrument agreement and actual prices received; or
the counterparty to the derivative financial instrument contract may default on its contractual obligations to us.
 
Our use of derivative financial instruments could have the effect of reducing our revenues and the value of our securities. During the year ended December 31, 2014 we paid cash settlements on our derivative financial instrument contracts totaling $19.0 million and during the year ended December 31, 2013, we received cash receipts of $42.1 million . For the year ended December 31, 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 $94.1 million . As of December 31, 2014, our oil and natural gas derivative financial instrument contracts were in the net asset position of $98.5 million . The ultimate settlement amount of these unrealized derivative financial instrument contracts is dependent on future commodity prices. We may incur significant realized and 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.



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Our ability to use net operating loss carryovers to reduce future tax payments may be limited.

Our net operating loss and other tax attribute carryovers ("NOLs") may be limited if we undergo an ownership change. Generally, an ownership change occurs if certain persons or groups increase their aggregate ownership in us by more than 50 percentage points looking back over a rolling three-year period. If an ownership change occurs, our ability to use our NOLs to reduce income taxes is limited to an annual amount, or the Section 382 limitation, equal to the fair market value of our common shares immediately prior to the ownership change multiplied by the long term tax-exempt interest rate, which is published monthly by the Internal Revenue Service ("IRS"). In the event of an ownership change, NOLs can be used to offset taxable income for years within a carryforward period subject to the Section 382 limitation. Any excess NOLs that exceed the Section 382 limitation in any year will continue to be allowed as carryforwards for the remainder of the carryforward period. Whether or not an ownership change occurs, the carryforward period for NOLs is 20 years from the year in which the losses giving rise to the NOLs were incurred. If the carryforward period for any NOL were to expire before that NOL had been fully utilized, the unused portion of that NOL would be lost. Our use of new NOLs arising after the date of an ownership change would not be affected by the Section 382 limitation (unless there is another ownership change after the new NOLs arise).

We exist in a litigious environment.

Any constituent could bring suit regarding our existing or planned operations or allege a violation of an existing contract. Any such action could delay when planned operations can actually commence or could cause a halt to existing production until such alleged violations are resolved by the courts. Not only could we incur significant legal and support expenses in defending our rights, but halting existing production or delaying planned operations could impact our future operations and financial condition. In addition, we are defendants in numerous cases involving claims by landowners for surface or subsurface damages arising from our operations and for claims by unleased mineral owners and royalty owners for unpaid or underpaid revenues customary in our business. We incur costs in defending these claims and from time to time must pay damages or other amounts due. Such legal disputes can also distract management and other personnel from their primary responsibilities.

Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions.

As an oil and natural gas production company, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities, essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows. Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

There are inherent limitations in all internal control over financial reporting, and misstatements due to error or fraud may occur and not be detected.

While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002, as amended, and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in our ability to control all circumstances. Our management, including our chief financial officer and chief accounting officer, does not expect that our internal controls and disclosure controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of our company or


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increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Risks relating to our indebtedness

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.

As of December 31, 2014 we had approximately $1.5 billion of indebtedness, including $202.5 million of indebtedness subject to variable interest rates and $750.0 million and $500.0 million of indebtedness under the 2018 Notes and 2022 Notes, respectfully. Our total interest expense, excluding amortization of deferred financing costs, on an annual basis based on currently available interest rates would be approximately $102.6 million and would change by approximately $2.0 million for every 1% change in interest rates.

Our level of debt could have important consequences, including the following:

it may be more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the EXCO Resources Credit Agreement or the indenture governing the 2018 Notes and 2022 Notes ("Indenture"), and the agreements governing our other indebtedness;
we may have difficulty borrowing money in the future for acquisitions (including obligations to acquire interests in wells pursuant to the Participation Agreement with KKR), capital expenditures or to meet our operating expenses or other general corporate obligations;
the amount of our interest expense may increase because certain of our borrowings are at variable rates of interest;
we will need to use a substantial portion of our cash flows to pay principal and interest on our debt, which will reduce the amount of money we have for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other business activities;
we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;
we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially declines in oil and natural gas prices;
when oil and natural gas prices decline, our ability to maintain compliance with our financial covenants becomes more difficult and our borrowing base is subject to reductions, which may reduce or eliminate our ability to fund our operations; and
our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will be unable to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our earnings will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough money to service our debt, we may be required but unable to refinance all or part of our existing debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all and may be required to surrender assets pursuant to the security provisions of the EXCO Resources Credit Agreement. Further, failing to comply with the financial and other restrictive covenants in the EXCO Resources Credit Agreement and the Indenture could result in an event of default, which could adversely affect our business, financial condition and results of operations.

We may incur substantially more debt, which may intensify the risks described above, including our ability to service our indebtedness.
    
Together with our subsidiaries, we may incur substantially more debt in the future in connection with our exploration, exploitation, development, acquisitions of undeveloped acreage and producing properties. The restrictions in our debt agreements on our incurrence of additional indebtedness are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness. To the extent new indebtedness is added to our current indebtedness, the risks described above could substantially increase. Significant additions of undeveloped acreage financed with debt may result in increased indebtedness without any corresponding increase in borrowing base, which could curtail drilling and development of this acreage or could cause us to not comply with our debt covenants.



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To service our indebtedness, fund our planned capital expenditure programs and fund acquisitions under the KKR Participation Agreement, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations.

Our ability to make payments on and to refinance our indebtedness, including the 2018 Notes, 2022 Notes and the EXCO Resources Credit Agreement, and to fund planned capital expenditures will depend on our ability to generate cash flow from operations and other resources in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, including the prices that we receive for oil and natural gas.

Our business may not generate sufficient cash flow from operations and future borrowings may not be available to us in an amount sufficient to enable us to pay our indebtedness, including our 2018 Notes, 2022 Notes and the EXCO Resources Credit Agreement, to fund planned capital expenditures or to fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our debt obligations and capital expenditure programs, we may be forced to sell assets, issue additional equity or debt securities or restructure our debt. These remedies may not be available on commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, which could cause us to default on our obligations and could impair our liquidity.

Our borrowing base under the EXCO Resources Credit Agreement is subject to semi-annual redeterminations. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices. This was evidenced by our recent borrowing base redetermination in February 2015 which reduced the borrowing base to $725.0 million primarily as a result of the recent declines in commodity prices as compared to commodity prices at the time of the prior borrowing base redetermination. If our borrowing base were to be reduced to a level which was less than the current borrowings, we would be required to reduce our borrowings to a level sufficient to cure any deficiency. We may be required to sell assets or seek alternative debt or equity which may not be available at commercially reasonable terms, if at all.

In addition, we conduct certain of our operations through our joint ventures and subsidiaries. Accordingly, repayment of our indebtedness, including the 2018 Notes and 2022 Notes, is dependent on the generation of cash flow by our joint ventures and subsidiaries and their ability to make such cash available to us, by dividend, debt repayment or otherwise. Unless they are guarantors of the 2018 Notes and 2022 Notes or our other indebtedness, our joint ventures and subsidiaries do not have any obligation to pay amounts due on the 2018 Notes and 2022 Notes or our other indebtedness or to make funds available for that purpose. Our joint ventures and subsidiaries may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect of our indebtedness. Each joint venture and subsidiary is a distinct legal entity, and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our joint ventures and subsidiaries. While the Indenture and the agreements governing certain of our other existing indebtedness limit the ability of certain of our joint ventures and subsidiaries to incur consensual restrictions on their ability to pay dividends or make other intercompany payments to us, these limitations are subject to qualifications and exceptions. In the event that we do not receive distributions from our joint ventures and subsidiaries, we may be unable to make required principal and interest payments on our indebtedness.

If we cannot make scheduled payments on our debt, we will be in default and holders of the 2018 Notes and 2022 Notes could declare all outstanding principal and interest to be due and payable, the lenders under the EXCO Resources Credit Agreement could terminate their commitments to loan money, our secured lenders could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms or at all, would materially and adversely affect our financial position and results of operations.
 
Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

The EXCO Resources Credit Agreement and the Indenture contain a number of significant covenants that, among other things, restrict our ability to:

dispose of assets;
incur or guarantee additional indebtedness and issue certain types of preferred shares;


43


pay dividends on our capital stock;
create liens on our assets;
enter into sale or leaseback transactions;
enter into specified investments or acquisitions;
repurchase, redeem or retire our capital stock or subordinated debt;
merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;
engage in specified transactions with subsidiaries and affiliates; or
pursue other corporate activities.

Also, the EXCO Resources Credit Agreement requires us to maintain compliance with certain financial covenants. Our ability to comply with these financial covenants may be affected by events beyond our control, and, as a result, we may be unable to meet these financial covenants. These financial covenants could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under the EXCO Resources Credit Agreement and the Indenture. A breach of any of these covenants or our inability to comply with the required financial covenants could result in an event of default under the applicable indebtedness. When oil and/or natural gas prices decline for an extended period of time, our ability to comply with these covenants becomes more difficult. Such a default, if not cured or waived, may allow the creditors to accelerate the related indebtedness and could result in acceleration of any other indebtedness to which a cross-acceleration or cross-default provision applies. An event of default under the Indenture would permit the lenders under the EXCO Resources Credit Agreement to terminate all commitments to extend further credit under the agreement. Furthermore, if we were unable to repay the amounts due and payable under the EXCO Resources Credit Agreement, those lenders could proceed against the collateral granted to them to secure that indebtedness. In the event that our lenders or noteholders accelerate the repayment of our borrowings, we and our subsidiaries may not have sufficient assets to repay that indebtedness. As a result of these restrictions, we may be:

limited in how we conduct our business;
unable to raise additional debt or equity financing during general economic, business or industry downturns; or
unable to compete effectively or to take advantage of new business opportunities.
 
The credit risk of financial institutions could adversely affect us.

We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges and insurance companies in the form of claims under our policies. In addition, if any lender under the EXCO Resources Credit Agreement is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under the credit agreement.

Risks Relating to Our Common Shares

Our common share price may fluctuate significantly.

Our common shares trade on the NYSE but an active trading market for our common shares may not be sustained. The market price of our common shares could fluctuate significantly as a result of:

announcements relating to our business or the business of our competitors;
changes in expectations as to our future financial performance or changes in financial estimates of public market analysis;
actual or anticipated quarterly variations in our operating results;
conditions generally affecting the oil and natural gas industry;
the success of our operating strategy; and
the operating and share price performance of other comparable companies.
 
Many of these factors are beyond our control and we cannot predict their potential effects on the price of our common shares. In addition, the stock markets in general can experience considerable price and volume fluctuations.



44


Our articles of incorporation permit us to issue preferred shares that may restrict a takeover attempt that you may favor.

Our articles of incorporation permit our board to issue up to 10,000,000 preferred shares and to establish by resolution one or more series of preferred shares and the powers, designations, preferences and participating, optional or other special rights of each series of preferred shares. The preferred shares may be issued on terms that are unfavorable to the holders of our common shares, including the grant of superior voting rights, the grant of preferences in favor of preferred shareholders in the payment of dividends and upon our liquidation and the designation of conversion rights that entitle holders of our preferred shares to convert their shares into common shares on terms that are dilutive to holders of our common shares. The issuance of preferred shares in future offerings may make a takeover or change in control of us more difficult.

Oaktree Capital Management, WL Ross & Co. LLC and/or their respective affiliates have significant influence over matters requiring shareholder approval because of their ownership of our common shares.

As of December 31, 2014, Oaktree Capital Management, L.P. (“Oaktree”), and WL Ross & Co. LLC (“WL Ross”), directly or through certain affiliates, beneficially owned approximately 16.6% and 18.7% , respectively, of our outstanding common shares. The beneficial ownership of Oaktree and WL Ross and/or their affiliates provides them with significant influence regarding matters submitted for shareholder approval, including proposals regarding:
 
any merger, consolidation or sale of all or substantially all of our assets;
the election of members of our board of directors; and
any amendment to our articles of incorporation.

The current or increased ownership position of Oaktree, WL Ross and/or their respective affiliates could delay, deter or prevent a change of control or adversely affect the price that investors might be willing to pay in the future for our common shares. The interests of Oaktree, WL Ross, and/or their respective affiliates may significantly differ from the interests of our other shareholders and they may vote the common shares they beneficially own in ways with which our other shareholders disagree.

Item  1B.
Unresolved Staff Comments
    
Not applicable.

Item 2.    Properties
Corporate offices

We lease office space in Dallas, Texas and Cranberry Township, Pennsylvania. We also have small offices for technical and field operations in Texas, Louisiana, Pennsylvania and West Virginia. The table below summarizes our material corporate leases.

Location
 
Approximate square footage
 
Approximate monthly payment
 
Expiration
Dallas, Texas (1)
 
155,000

 
$
253,826

 
May 31, 2025
Cranberry Township, Pennsylvania
 
15,400

 
$
22,500

 
December 31, 2017
(1)
The office lease in Dallas, Texas contains a right on our behalf to terminate the lease agreement early on June 30, 2020 or June 30, 2022.
Other

We have described our oil and natural gas properties, oil and natural gas reserves, acreage, wells, production and drilling activity in “Item 1. Business” of this Annual Report on Form 10-K.

Item 3.     Legal Proceedings
    


45


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  4.      Mine Safety Disclosures
    
Not applicable.
PART II

Item  5.
Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market information for our common shares

Our common shares trade on the NYSE under the symbol “XCO.” The following table sets forth, for the periods indicated, the high and low sales prices per share of our common share as reported by the NYSE:
 
 
 
Price per share
 
 
 
 
High
 
Low
 
Dividends Declared
2014
 
 
 
 
 
 
First Quarter
 
$
5.85

 
$
4.60

 
$
0.05

Second Quarter
 
6.60

 
5.05

 
0.05

Third Quarter
 
5.95

 
3.25

 
0.05

Fourth Quarter
 
3.80

 
1.98

 

 
 
 
 
 
 
 
2013
 
 
 
 
 
 
First Quarter
 
$
7.92

 
$
5.97

 
$
0.05

Second Quarter
 
8.70

 
6.52

 
0.05

Third Quarter
 
9.00

 
6.63

 
0.05

Fourth Quarter
 
7.25

 
4.83

 
0.05


Our shareholders

According to our transfer agent, Continental Stock Transfer & Trust Company, there were 253 holders of record of our common shares on December 31, 2014 (including nominee holders such as banks and brokerage firms who hold shares for beneficial holders and holders of restricted shares).

Our dividend policy

On December 15, 2014, our board of directors suspended our cash dividend to provide additional funds to reinvest into the Company and did not approve a cash dividend for the fourth quarter 2014. In 2014 , we paid cash dividends of $0.15 per share, or $0.05 per share for each of the first three quarters, totaling $41.1 million . Any future declaration of dividends, as well as the establishment of record and payment dates, will depend on our earnings, capital requirements, financial condition, prospects and other factors our board of directors may deem relevant.


46



Issuer repurchases of common shares

The following table details our repurchases of common shares for the three months ended December 31, 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) (2)
October 1 - October 31
 

 
$

 

 
$
192.5

November 1 - November 30
 
32,011

 
3.78

 

 
192.5

December 1 - December 31
 
6,810

 
2.24

 

 
192.5

       Total
 
38,821

 
3.51

 

 
 
(1) Represents shares that were tendered by employees to satisfy minimum tax withholding amounts for the vesting of restricted share awards.
(2)
On July 19, 2010, we announced a $200.0 million share repurchase program.

Item 6.
Selected Financial Data
    
The following table presents our selected historical financial and operating data. This financial data should be read in conjunction with “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations,” our consolidated financial statements, the notes to our consolidated financial statements and the other financial information included in this Annual Report on Form 10-K. This information does not replace the consolidated financial statements.


47


Selected consolidated financial and operating data
 
 
Year Ended December 31,
(in thousands, except per share amounts)
 
2014
 
2013
 
2012
 
2011
 
2010
Statement of operations data (1):
 
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
660,269

 
$
634,309

 
$
546,609

 
$
754,201

 
$
515,226

Cost and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production (2)
 
94,326

 
83,248

 
104,610

 
108,641

 
108,184

Gathering and transportation
 
101,574

 
100,645

 
102,875

 
86,881

 
54,877

Depletion, depreciation and amortization
 
263,569

 
245,775

 
303,156

 
362,956

 
196,963

Impairment of oil and natural gas properties
 

 
108,546

 
1,346,749

 
233,239

 

Accretion of discount on asset retirement obligations
 
2,690

 
2,514

 
3,887

 
3,652

 
3,758

General and administrative (3)
 
65,920

 
91,878

 
83,818

 
104,618

 
105,114

(Gain) loss on divestitures and other operating items (4)
 
5,315

 
(177,518
)
 
17,029

 
23,819

 
(509,872
)
Total cost and expenses
 
533,394

 
455,088

 
1,962,124

 
923,806

 
(40,976
)
Operating income (loss)
 
126,875

 
179,221

 
(1,415,515
)
 
(169,605
)
 
556,202

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(94,284
)
 
(102,589
)
 
(73,492
)
 
(61,023
)
 
(45,533
)
Gain (loss) on derivative financial instruments (5)
 
87,665

 
(320
)
 
66,133

 
219,730

 
146,516

Other income (expense)
 
241

 
(828
)
 
969

 
788

 
327

Equity income (loss) (6)
 
172

 
(53,280
)
 
28,620

 
32,706

 
16,022

Total other income (expense)
 
(6,206
)
 
(157,017
)
 
22,230

 
192,201

 
117,332

Income (loss) before income taxes
 
120,669

 
22,204

 
(1,393,285
)
 
22,596

 
673,534

Income tax expense
 

 

 

 

 
1,608

Net income (loss)
 
$
120,669

 
$
22,204

 
$
(1,393,285
)
 
$
22,596

 
$
671,926

Basic net income (loss) per share
 
$
0.45

 
$
0.10

 
$
(6.50
)
 
$
0.11

 
$
3.16

Diluted net income (loss) per share
 
$
0.45

 
$
0.10

 
$
(6.50
)
 
$
0.10

 
$
3.11

Cash dividends declared per share
 
$
0.15

 
$
0.20

 
$
0.16

 
$
0.16

 
$
0.14

Weighted average common shares and common share equivalents outstanding:
 
 
 
 
 
 
 
 
 
 
Basic
 
268,258

 
215,011

 
214,321

 
213,908

 
212,465

Diluted
 
268,376

 
230,912

 
214,321

 
216,705

 
215,735

Statement of cash flow data:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
362,093

 
$
350,634

 
$
514,786

 
$
428,543

 
$
339,921

Investing activities
 
(221,588
)
 
(252,478
)
 
(427,094
)
 
(709,531
)
 
(712,854
)
Financing activities
 
(144,683
)
 
(93,317
)
 
(74,045
)
 
268,756

 
348,755

Balance sheet data:
 
 
 
 
 
 
 
 
 
 
Current assets
 
$
330,766

 
$
305,854

 
$
361,866

 
$
678,008

 
$
520,460

Total assets
 
2,356,896

 
2,408,628

 
2,323,732

 
3,791,587

 
3,477,420

Current liabilities
 
365,371

 
349,170

 
237,931

 
287,399

 
285,698

Long-term debt
 
1,446,535

 
1,858,912

 
1,848,972

 
1,887,828

 
1,588,269

Shareholders' equity
 
510,004

 
147,905

 
149,393

 
1,558,332

 
1,540,552

Total liabilities and shareholders' equity
 
2,356,896

 
2,408,628

 
2,323,732

 
3,791,587

 
3,477,420




48


(1)
We have completed numerous acquisitions and dispositions which impact the comparability of the selected financial data between periods.     
(2)
Share-based compensation calculated pursuant to FASB Accounting Standards Codification 718, Compensation-Stock Compensation ("ASC 718") included in oil and natural gas production costs was $0.1 million and $1.0 million for the years ended December 31, 2011 and 2010, respectively. We had no share-based compensation included in oil and natural gas production costs for the years ended December 31, 2014, 2013 and 2012.
(3)
Share-based compensation calculated pursuant to ASC 718 included in general and administrative expenses was $5.0 million , $10.7 million , $8.9 million , $10.9 million and $15.8 million for the years ended December 31, 2014 , 2013, 2012, 2011 and 2010, respectively.
(4)
During 2013, we recognized a gain on the contribution of properties to Compass. During 2010, we recognized gains on the sale transactions attributable to the formation of our joint ventures with BG Group.
(5)
We do not designate our derivative financial instruments as hedges and, as a result, the changes in the fair value of our derivative financial instruments are recognized in our Consolidated Statements of Operations. See "Note 2. Summary of significant accounting policies" in the Notes to our Consolidated Financial Statements for a description of this accounting method.
(6)
On November 15, 2013, we sold our equity interest in TGGT to Azure in exchange for cash proceeds and an equity interest in Azure. We report our equity interest acquired in Azure using the cost method of accounting.

Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
    
The following management's discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K. In addition to historical financial information, the following management's discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K.

Overview and history

We are an independent oil and natural gas company engaged in the exploitation, exploration, 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 maintaining 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 shares on January 17, 2014 which resulted in the issuance of 54,574,734 shares of common shares 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 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 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 the EXCO Resources Credit


49


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 the 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 under the EXCO Resources Credit Agreement ("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

On October 31, 2014, we closed the sale of our entire interest in Compass to HGI for $118.8 million in cash. We used a portion of the proceeds to reduce indebtedness under the EXCO Resources Credit Agreement. Prior to the closing of the sale, we reported our 25.5% interest in Compass using proportional consolidation. Our consolidated assets and liabilities were reduced by our proportionate share of Compass's net assets of $31.4 million which included our proportionate share of Compass's indebtedness of $83.2 million on October 31, 2014. The sale of our interest in Compass did not significantly alter the relationship between our capitalized costs and proved reserves and was 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. As a result, our capitalized costs were further reduced by $87.4 million .

At the closing, EXCO and HGI terminated the existing operating and administrative services agreements and entered 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.

EXCO Resources Credit Agreement amendment

On February 6, 2015, we amended the EXCO Resources Credit Agreement which decreased our borrowing base to $725.0 million as a result of the recent decline in oil and natural gas prices. In addition, the financial covenants were amended to include an interest coverage ratio and senior secured indebtedness to consolidated EBITDAX ratio. The leverage ratio was suspended until the fourth quarter of 2016 and the ratio requirements thereafter were modified. See further discussion of the amendment to the EXCO Resources Credit Agreement as part of "Our liquidity, capital resources and capital commitments" in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations”.

Critical accounting estimates

The process of preparing financial statements in conformity with GAAP requires us to make estimates and assumptions to determine reported amounts of certain assets, liabilities, revenues, expenses and related disclosures. We have identified the most critical accounting policies used in the preparation of our consolidated financial statements. We determined the critical policies by considering accounting policies that involve the most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our estimates of Proved Reserves, derivative financial instruments, business combinations, share-based compensation, oil and natural gas properties, goodwill, revenue recognition, asset retirement obligations and income taxes.

The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in our application of GAAP. For a more complete discussion of our accounting policies see "Note 2. Summary of significant accounting policies" in the Notes to our Consolidated Financial Statements.



50


Estimates of Proved Reserves

The Proved Reserves data included in this Annual Report on Form 10-K was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:

the quality and quantity of available data;
the interpretation of this data;
the accuracy of various mandated economic assumptions; and
the technical qualifications, experience and judgment of the persons preparing the estimates.
 
Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. The assumptions used for our shale properties and reservoir characteristics and performance are subject to further refinement as additional production history is accumulated.

You should not assume that the present value of future net cash flows represents the current market value of our estimated Proved Reserves. In accordance with the SEC's requirements, we based the estimated discounted future net cash flows from Proved Reserves according to the requirements in the SEC's Release No. 33-8995 Modernization of Oil and Gas Reporting. Actual future prices and costs may be materially higher or lower than the prices and costs used in the preparation of the estimate. Further, the mandated discount rate of 10% may not be an accurate assumption of future interest rates or cost of capital.

Proved Reserve quantities directly and materially impact depletion expense. If the Proved Reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in the estimate of Proved Reserves may result from lower market prices, making it uneconomical to drill or produce from higher cost fields. In addition, a decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties and require an impairment of the carrying value of our oil and natural gas properties.

Business combinations

When we acquire assets that qualify as a business, we use FASB ASC 805-10, Business Combinations (" ASC 805-10") to record our acquisitions of oil and natural gas properties or entities. ASC 805-10 requires that acquired assets, identifiable intangible assets and liabilities be recorded at their fair value, with any excess purchase price being recognized as goodwill. Application of ASC 805-10 requires significant estimates to be made by management using information available at the time of acquisition. Since these estimates require the use of significant judgment, actual results could vary as the estimates are subject to changes as new information becomes available.

Derivative financial instruments

We use derivative financial instruments to manage price fluctuations, protect our investments and achieve a more predictable cash flow. The estimates of the fair values of our derivative financial instruments require judgment. The fair value of our derivative financial instruments is determined by quoted futures prices, utilization of the credit-adjusted risk-free rate curves and the implied rates of volatility. 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. 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.

Share-based compensation

We account for share-based compensation in accordance with ASC 718 which requires share-based compensation to employees to be recognized in our Consolidated Statements of Operations based on their estimated fair values. Estimating the grant date fair value of our share-based compensation requires management to make assumptions and to apply judgment in estimating the fair value. These assumptions and judgments include estimating the volatility of our share price, dividend yields, expected term, forfeiture rates and other company-specific inputs. Changes in these assumptions could materially affect the estimate of the fair value. If actual results are not consistent with the assumptions used, the share-based compensation expense reported in our financial statements may not be representative of the actual economic impact of the share-based compensation.


51



Oil and natural gas properties

The accounting for, and disclosure of, oil and natural gas producing activities require 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 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 extension or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. In determining whether such costs should be impaired or transferred, we evaluate lease expiration dates, recent drilling results, future development plans and current market values. Our undeveloped properties are predominantly 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.
    
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 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. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities.
    
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 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. 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. The price used for NGL's was based on the trailing 12 month average of realized prices. 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 impacts 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.


52



Goodwill

In accordance with FASB ASC 350-20, Intangibles-Goodwill and Other , goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of December 31 of each year. Losses, if any, resulting from impairment tests will be reflected in operating income in the Consolidated Statements of Operations.
    
We apply a two-part, equally weighted approach in determining the fair value of our business as part of the goodwill impairment test. We perform an income approach, which uses a discounted cash flow model to value our business, and a market approach, in which our value is determined using trading metrics and transaction multiples of peer companies. The discounted cash flow model used in the income approach requires us to make various judgmental assumptions about future production, revenues, operating and capital expenditures, discount rates and other inputs which are based on our budgets, business plans, economic projections and anticipated future cash flows. The market approach requires us to make assumptions regarding the identifications of comparable companies and transactions as well as the future performance of ourselves and the comparable companies. Due to the changing market conditions, it is possible that assumptions used in the model may change in the future, which could materially affect the estimate of the fair value of our business.

Revenue recognition and natural gas imbalances

We use the sales method of accounting for oil and natural gas revenues. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes primarily on company-measured volume readings. We then adjust our oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. Historically, these differences have been immaterial. Gas imbalances at December 31, 2014, 2013 and 2012 were not significant.

Asset retirement obligations

We follow FASB ASC 410-20, Asset Retirement Obligations (" ASC 410-20") to account for legal obligations associated with the retirement of long-lived assets. ASC 410-20 requires these obligations be recognized at their estimated fair value at the time that the obligations are incurred. The costs of plugging and abandoning oil and natural gas properties fluctuate with costs associated with the industry. Our calculation of asset retirement obligation uses numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. We periodically assess the estimated costs of our asset retirement obligations and adjust the liability according to these estimates.

Income taxes

Income taxes are accounted for in accordance FASB ASC 740, Income Taxes . Deferred taxes are recorded to reflect the tax benefits and consequences of future years' differences between the tax basis of assets and liabilities and their financial reporting basis. We must make certain estimates related to the reversal of temporary differences, and actual results could vary from those estimates. We assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. Examples of positive and negative evidence include historical taxable income or losses, forecasted income or losses, the estimated timing of the reversals of existing temporary differences as well as prudent and feasible tax planning strategies. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of December 31, 2014 , we continued to have a full valuation allowance against our net deferred tax assets. A significant amount of judgment is also required in determining the amount of unrecognized tax benefit to record for uncertain tax positions. We consider the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of unrecognized tax benefit. We currently do not have any uncertain tax positions recorded as of December 31, 2014 .




53


Our results of operations

A summary of key financial data for the years ended December 31, 2014 , 2013 and 2012 related to our results of operations is presented below:
 
 
Year Ended December 31,
 
Year to year change
(dollars in thousands, except per unit prices)
 
2014
 
2013
 
2012
 
2014-2013
 
2013-2012
Production:
 
 
 
 
 
 
 
 
 
 
Oil (Mbbls)
 
2,236

 
1,188

 
704

 
1,048

 
484

Natural gas (Mmcf)
 
120,980

 
153,321

 
182,644

 
(32,341
)
 
(29,323
)
Natural gas liquids (Mbbls)
 
224

 
243

 
510

 
(19
)
 
(267
)
Total production (Mmcfe) (1)
 
135,740

 
161,907

 
189,928

 
(26,167
)
 
(28,021
)
Average daily production (Mmcfe)
 
372

 
444

 
519

 
(72
)
 
(75
)
Revenues before derivative financial instrument activities:
 
 
Oil
 
$
196,316

 
$
111,440

 
$
62,119

 
$
84,876

 
$
49,321

Natural gas
 
457,946

 
514,309

 
462,422

 
(56,363
)
 
51,887

Natural gas liquids
 
6,007

 
8,560

 
22,068

 
(2,553
)
 
(13,508
)
Total revenues
 
$
660,269

 
$
634,309

 
$
546,609

 
$
25,960

 
$
87,700

Oil and natural gas derivative financial instruments:
 
 
Gain (loss) on derivative financial instruments
 
$
87,665

 
$
(320
)
 
$
66,133

 
$
87,985

 
$
(66,453
)
Average sales price (before cash settlements of derivative financial instruments):
 
 
Oil (per Bbl)
 
$
87.80

 
$
93.80

 
$
88.24

 
$
(6.00
)
 
$
5.56

Natural gas (per Mcf)
 
3.79

 
3.35

 
2.53

 
0.44

 
0.82

Natural gas liquids (per Bbl)
 
26.82

 
35.23

 
43.27

 
(8.41
)
 
(8.04
)
Natural gas equivalent (per Mcfe)
 
4.86

 
3.92

 
2.88

 
0.94

 
1.04

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas operating costs
 
$
64,467

 
$
61,277

 
$
77,127

 
$
3,190

 
$
(15,850
)
Production and ad valorem taxes
 
29,859

 
21,971

 
27,483

 
7,888

 
(5,512
)
Gathering and transportation
 
101,574

 
100,645

 
102,875

 
929

 
(2,230
)
Depletion
 
258,266

 
237,899

 
288,401

 
20,367

 
(50,502
)
Depreciation and amortization
 
5,303

 
7,876

 
14,755

 
(2,573
)
 
(6,879
)
General and administrative (2)
 
65,920

 
91,878

 
83,818

 
(25,958
)
 
8,060

Interest expense, net
 
94,284

 
102,589

 
73,492

 
(8,305
)
 
29,097

Costs and expenses (per Mcfe):
 
 
 
 
 
 
 
 
 
 
Oil and natural gas operating costs
 
$
0.47

 
$
0.38

 
$
0.41

 
$
0.09

 
$
(0.03
)
Production and ad valorem taxes
 
0.22

 
0.14

 
0.14

 
0.08

 

Gathering and transportation
 
0.75

 
0.62

 
0.54

 
0.13

 
0.08

Depletion
 
1.90

 
1.47

 
1.52

 
0.43

 
(0.05
)
Depreciation and amortization
 
0.04

 
0.05

 
0.08

 
(0.01
)
 
(0.03
)
General and administrative
 
0.49

 
0.57

 
0.44

 
(0.08
)
 
0.13

Interest expense, net
 
0.69

 
0.63

 
0.39

 
0.06

 
0.24

Net income (loss)
 
$
120,669

 
$
22,204

 
$
(1,393,285
)
 
$
98,465

 
$
1,415,489


(1)
Mmcfe is calculated by converting one barrel of oil or NGLs into six Mcf of natural gas.
(2)
Share-based compensation expense included in general and administrative expenses was $5.0 million , $10.7 million and $8.9 million for the years ended December 31, 2014 , 2013 and 2012 , respectively.
    
The following is a discussion of our financial condition and results of operations for the years ended December 31, 2014 , 2013 and 2012 .

The comparability of our results of operations for 2014 , 2013 and 2012 was affected by:


54



the acquisitions of the Haynesville and Eagle Ford assets during 2013;
the formation and subsequent sale of Compass during 2013 and 2014, respectively;
the sale of our equity interest in TGGT Holdings, LLC ("TGGT") during 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 in 2013 and 2012;
asset impairments and other non-recurring costs;
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:

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

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

Marketing arrangements

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

We sell the majority of our natural gas under individually negotiated gas purchase contracts using market sensitive pricing. Our sales contracts vary in length from spot market sales of a single day to term agreements that may extend for a year or more. Our natural gas customers include utilities, natural gas marketing companies and a variety of commercial and industrial end users. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price


55


received for natural gas sold on the spot market varies daily, reflecting changing market conditions. Some of our natural gas is sold under contracts which provide for sharing in a percentage of proceeds of NGLs extracted by third party plants.
    
We may be unable to market all of the oil, natural gas or NGLs we produce. If our oil and natural gas can be marketed, we may be unable to negotiate favorable pricing and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil and natural gas reserves. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.
We engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. If this occurs, companies purchasing oil, natural gas or NGLs in these areas may reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of our oil or natural gas reserves, we may shut in our oil or natural gas wells for certain periods of time. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated. Economic conditions, particularly depressed oil and natural gas prices, may negatively impact the liquidity and creditworthiness of our purchasers and may expose us to risk with respect to the ability to collect payments for the oil and natural gas we deliver.

Presentation of results of operations

Our discussion of production, revenues and direct operating expenses is based on our producing regions and Compass. Compass included 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 from its formation on February 14, 2013 to the closing of the sale of our interest on October 31, 2014. 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 table presents our production, revenue and average sales prices for the years ended December 31, 2014 and 2013 :
 
 
Year Ended December 31,
 
 
 
 
 
 
 
 
2014
 
2013
 
Year to year 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
 
92,916

 
$
371,074

 
$
3.99

 
123,218

 
$
417,811

 
$
3.39

 
(30,302
)
 
$
(46,737
)
 
$
0.60

South Texas
 
13,713

 
176,022

 
12.84

 
6,197

 
85,926

 
13.87

 
7,516

 
90,096

 
(1.03
)
Appalachia
 
21,289

 
67,794

 
3.18

 
22,816

 
78,424

 
3.44

 
(1,527
)
 
(10,630
)
 
(0.26
)
Other
 
364

 
3,649

 
10.02

 
1,139

 
9,135

 
8.02

 
(775
)
 
(5,486
)
 
2.00

Compass
 
7,458

 
41,730

 
5.60

 
8,537

 
43,013

 
5.04

 
(1,079
)
 
(1,283
)
 
0.56

        Total
 
135,740

 
$
660,269

 
$
4.86

 
161,907

 
$
634,309

 
$
3.92

 
(26,167
)
 
$
25,960

 
$
0.94


Production for the year ended December 31, 2014 decreased by 26.2 Bcfe, or 16% , as compared with 2013. The decrease in production in the East Texas/North Louisiana region was primarily due to production declines from changes in our drilling program and the initial contribution of properties to Compass in the first quarter of 2013. 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 region resulted in 27 wells turned-to-sales in North Louisiana and 8 wells turned-to-sales in East Texas for the year ended December 31, 2014 compared to 51 wells turned-to-sales in North Louisiana for the year ended December 31, 2013. The wells turned-to-sales for the year ended December 31, 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 63 wells turned-to-sales for the year ended December 31, 2014 compared to 26 wells turned-to-sales for the year ended December 31, 2013. The decrease in production of 1.5 Bcfe in the Appalachia region was a result of natural production declines following the suspension of our drilling program during the second half of 2013. The decrease in production in the Other region was


56


primarily the result of the contribution of properties in the Permian Basin to Compass in 2013. The decrease in our proportionate share of Compass's production was due to the sale of our interest in Compass on October 31, 2014.

Oil and natural gas revenues for the year ended December 31, 2014 increased by $26.0 million , or 4% , as compared with 2013. The increase in revenues was primarily the result of the acquisition of Haynesville and Eagle Ford assets in the third quarter of 2013 and an increase in natural gas prices. This was partially offset by the decrease in production compared to the prior year. Our average natural gas sales price increased 13% to $3.79 per Mcf for the year ended December 31, 2014 from $3.35 per Mcf for the year ended December 31, 2013. Our average sales price for natural gas during the year ended December 31, 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 6% to $87.80 per Bbl for the year ended December 31, 2014 from $93.80 per Bbl for the year ended December 31, 2013. Our average sales price for oil in the South Texas region is most closely correlated to the Louisiana Light Sweet ("LLS") price index. Our average sales price of NGLs per Bbl decreased 24% to $26.82 per Bbl for the year ended December 31, 2014 from $35.23 per Bbl for the year ended December 31, 2013.

The following table and discussion presents our production, revenue and average sales prices for the years ended December 31, 2013 and 2012 :
 
 
Year Ended December 31,
 
 
 
 
 
 
 
 
2013
 
2012
 
Year to year 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
 
123,218

 
$
417,811

 
$
3.39

 
164,779

 
$
420,579

 
$
2.55

 
(41,561
)
 
$
(2,768
)
 
$
0.84

South Texas
 
6,197

 
85,926

 
13.87

 

 

 

 
6,197

 
85,926

 
13.87

Appalachia
 
22,816

 
78,424

 
3.44

 
16,153

 
47,379

 
2.93

 
6,663

 
31,045

 
0.51

Other
 
1,139

 
9,135

 
8.02

 
8,996

 
78,651

 
8.74

 
(7,857
)
 
(69,516
)
 
(0.72
)
Compass
 
8,537

 
43,013

 
5.04

 

 

 

 
8,537

 
43,013

 
5.04

        Total
 
161,907

 
$
634,309

 
$
3.92

 
189,928

 
$
546,609

 
$
2.88

 
(28,021
)
 
$
87,700

 
$
1.04

    
Production in our East Texas/North Louisiana region for the year ended December 31, 2013 decreased by 41.6 Bcfe from 2012. The decrease in production was primarily due to the impact of the contribution of properties to Compass of 24.7 Bcfe, as well as normal production declines and a reduced drilling program. The decrease was partially offset by additional production from the acquisition of Haynesville assets during July 2013. Our drilling activities in East Texas/North Louisiana resulted in 51 wells turned-to-sales for the year ended December 31, 2013 compared to 84 wells turned-to-sales for the year ended December 31, 2012. We acquired assets in South Texas region focused on the Eagle Ford shale on July 31, 2013. Our production in the South Texas region was 6.2 Bcfe from the acquisition date to December 31, 2013, which consisted of 941 Mbbls of oil, 28 Mbbls of NGLs and 379 Mmcf of natural gas. The increase in production of 6.7 Bcfe in the Appalachia region was a result of our completion activities in the Marcellus shale. During 2013, we turned-to-sales 20 wells in the Marcellus shale which primarily consisted of wells in our inventory waiting upon completion as of the end of 2012. The decrease in production in the Permian and other region was primarily the result of the contribution of properties to Compass. Our proportionate share of Compass's production consisted of 6.7 Bcfe from East Texas/North Louisiana and 1.8 Bcfe from the Permian Basin.

For the years ended December 31, 2013 and 2012, oil and natural gas revenues were $634.3 million and $546.6 million, respectively. The increase in revenues was primarily the result of an increase in oil and natural gas prices and the acquisition of Haynesville and Eagle Ford assets, which was partially offset by lower revenues arising from the contribution of properties to Compass and normal production declines. Our average natural gas sales price increased 32% to $3.35 per Mcf for the year ended December 31, 2013 from $2.53 per Mcf for the year ended December 31, 2012. Our average sales price for natural gas during 2013 was negatively impacted by the widening of differentials in Appalachia as a result of an oversupply in the Northeast region. Our average sales price of oil per Bbl increased 6% to $93.80 per Bbl for the year ended December 31, 2013 from $88.24 per Bbl for the year ended December 31, 2012. Our average sales price of NGLs per Bbl decreased 19% to $35.23 per Bbl for the year ended December 31, 2013 from $43.27 per Bbl for the year ended December 31, 2012.


57


Oil and natural gas operating costs

The following tables and discussion present our oil and natural gas operating costs for the years ended December 31, 2014, 2013, and 2012.
 
 
Year Ended December 31,
 
 
 
 
 
 
 
 
2014
 
2013
 
Year to year 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
 
$
18,056

 
$
3,815

 
$
21,871

 
$
16,980

 
$
4,294

 
$
21,274

 
$
1,076

 
$
(479
)
 
$
597

South Texas
 
15,242

 
396

 
15,638

 
11,454

 
13

 
11,467

 
3,788

 
383

 
4,171

Appalachia
 
14,072

 
58

 
14,130

 
14,073

 

 
14,073

 
(1
)
 
58

 
57

Other
 
300

 

 
300

 
1,623

 

 
1,623

 
(1,323
)
 

 
(1,323
)
Compass
 
10,838

 
1,690

 
12,528

 
11,397

 
1,443

 
12,840

 
(559
)
 
247

 
(312
)
Total
 
$
58,508

 
$
5,959

 
$
64,467

 
$
55,527

 
$
5,750

 
$
61,277

 
$
2,981

 
$
209

 
$
3,190

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
 
 
 
 
 
 
 
2014
 
2013
 
Year to year 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

 
$
0.04

 
$
0.23

 
$
0.14

 
$
0.03

 
$
0.17

 
$
0.05

 
$
0.01

 
$
0.06

South Texas
 
1.11

 
0.03

 
1.14

 
1.85

 

 
1.85

 
(0.74
)
 
0.03

 
(0.71
)
Appalachia
 
0.66

 

 
0.66

 
0.62

 

 
0.62

 
0.04

 

 
0.04

Other
 
0.82

 

 
0.82

 
1.42

 

 
1.42

 
(0.60
)
 

 
(0.60
)
Compass
 
1.45

 
0.23

 
1.68

 
1.34

 
0.17

 
1.51

 
0.11

 
0.06

 
0.17

Total
 
$
0.43

 
$
0.04

 
$
0.47

 
$
0.34

 
$
0.04

 
$
0.38

 
$
0.09

 
$

 
$
0.09

    
Oil and natural gas operating costs for the year ended December 31, 2014 increased by $3.2 million , or 5% , as compared with 2013. The increase in oil and natural gas operating costs was primarily due to the acquisition of the Eagle Ford assets. This was partially offset by the lower operating costs resulting from the contribution of properties to Compass in the first quarter of 2013 as well as the sale of our interest in Compass on October 31, 2014. We implemented several costs reduction initiatives in the South Texas region in 2014 which resulted in decreased saltwater disposal costs, improved efficiencies and reduced reliance on third-party contractors.

Oil and natural gas operating costs for the year ended December 31, 2014 were $0.47 per Mcfe compared to $0.38 per Mcfe for the year ended December 31, 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. This increase was partially offset by the cost reduction initiatives in the South Texas region, as well as the contribution and the sale of properties to Compass in 2013 and 2014, respectively, which typically have a higher average cost per Mcfe compared to the average for the rest of our properties. As a result of the cost reduction initiatives in the South Texas region, we were able to reduce our costs per Mcfe in the region to $1.14 per Mcfe in 2014 from $1.85 per Mcfe in 2013.


58


 
 
Year Ended December 31,
 
 
 
 
 
 
 
 
2013
 
2012
 
Year to year 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
 
$
16,980

 
$
4,294

 
$
21,274

 
$
39,897

 
$
9,497

 
$
49,394

 
$
(22,917
)
 
$
(5,203
)
 
$
(28,120
)
South Texas
 
11,454

 
13

 
11,467

 

 

 

 
11,454

 
13

 
11,467

Appalachia
 
14,073

 

 
14,073

 
14,882

 

 
14,882

 
(809
)
 

 
(809
)
Other
 
1,623

 

 
1,623

 
12,539

 
312

 
12,851

 
(10,916
)
 
(312
)
 
(11,228
)
Compass
 
11,397

 
1,443

 
12,840

 

 

 

 
11,397

 
1,443

 
12,840

Total
 
$
55,527

 
$
5,750

 
$
61,277

 
$
67,318

 
$
9,809

 
$
77,127

 
$
(11,791
)
 
$
(4,059
)
 
$
(15,850
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
 
 
 
 
 
 
 
2013
 
2012
 
Year to year 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
 
$
0.14

 
$
0.03

 
$
0.17

 
$
0.24

 
$
0.06

 
$
0.30

 
$
(0.10
)
 
$
(0.03
)
 
$
(0.13
)
South Texas
 
1.85

 

 
1.85

 

 

 

 
1.85

 

 
1.85

Appalachia
 
0.62

 

 
0.62

 
0.92

 

 
0.92

 
(0.30
)
 

 
(0.30
)
Other
 
1.42

 

 
1.42

 
1.39

 
0.03

 
1.42

 
0.03

 
(0.03
)
 

Compass
 
1.34

 
0.17

 
1.51

 

 

 

 
1.34

 
0.17

 
1.51

Total
 
$
0.34

 
$
0.04

 
$
0.38

 
$
0.36

 
$
0.05

 
$
0.41

 
$
(0.02
)
 
$
(0.01
)
 
$
(0.03
)

Our oil and natural gas operating costs for the years ended December 31, 2013 and 2012 were $61.3 million and $77.1 million, respectively. The decreases in total oil and natural gas operating expenses for 2013 as compared to 2012 were primarily due to the contribution of properties to Compass. Additionally, we continued to focus on cost saving initiatives throughout the organization. These decreases were offset by additional oil and natural gas operating costs as a result of the acquisition of Haynesville and Eagle Ford assets.
    
Oil and natural gas operating costs for the year ended December 31, 2013 were $0.38 per Mcfe, a decrease of 7% from 2012. The net decrease in oil and natural gas operating costs per Mcfe is attributable to the contribution of properties to Compass, which typically have a higher cost per Mcfe compared to the rest of our properties. This was partially offset by a higher cost per Mcfe associated with our oil production in the South Texas region.
Gathering and transportation

Gathering and transportation expenses for the year ended December 31, 2014 increase d by $0.9 million , or 1% , as compared with 2013. Gathering and transportation expenses were $0.75 per Mcfe for the year ended December 31, 2014, as compared to $0.62 per Mcfe for the year ended December 31, 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 amended in April 2014 resulting in higher gathering and transportation expenses.
 
Gathering and transportation expenses totaled $100.6 million, or $0.62 per Mcfe, for the year ended December 31, 2013, as compared to $102.9 million, or $0.54 per Mcfe for the year ended December 31, 2012. The increase in gathering and transportation expense on a per Mcfe basis was due to lower volumes in relation to fixed costs under firm transportation contracts in the East Texas/North Louisiana region.



59


Production and ad valorem taxes
    
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
(in thousands, except per unit rate)
 
Production and ad valorem taxes
 
% of revenue
 
Taxes $/Mcfe
 
Production and ad valorem taxes
 
% of revenue
 
Taxes $/Mcfe
 
Production and ad valorem taxes
 
% of revenue
 
Taxes $/Mcfe
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
East Texas/North Louisiana
 
$
10,032

 
2.7
%
 
$
0.11

 
$
9,287

 
2.2
%
 
$
0.08

 
$
17,501

 
4.2
%
 
$
0.11

South Texas
 
13,406

 
7.6
%
 
0.98

 
4,962

 
5.8
%
 
0.80

 

 
%
 

Appalachia
 
2,256

 
3.3
%
 
0.11

 
2,653

 
3.4
%
 
0.12

 
3,013

 
6.4
%
 
0.19

Other
 
92

 
2.5
%
 
0.25

 
815

 
8.9
%
 
0.72

 
6,969

 
8.9
%
 
0.77

Compass
 
4,073

 
9.8
%
 
0.55

 
4,254

 
9.9
%
 
0.50

 

 
%
 

Total
 
$
29,859

 
4.5
%
 
$
0.22

 
$
21,971

 
3.5
%
 
$
0.14

 
$
27,483

 
5.0
%
 
$
0.14


Production and ad valorem taxes for the year ended December 31, 2014 increased by $7.9 million , or 36% , as compared to 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 higher severance tax rates in the State of Louisiana and the expiration of severance tax holidays on certain Haynesville shale wells in the East Texas/North Louisiana region. Production and ad valorem taxes for the year ended December 31, 2013 decrease d by $5.5 million , or 20% , as compared to the same period in 2012 . The decrease for the year ended December 31, 2013 compared to 2012 was primarily attributable to lower production volumes due to the contribution of properties to Compass and lower severance tax rates in the State of Louisiana. These decreases were partially offset by higher production and ad valorem taxes associated with our liquids production in the South Texas region.

Production and ad valorem tax rates per Mcfe were $0.22 , $0.14 and $0.14 for 2014 , 2013 and 2012 , respectively. The rate per Mcfe increased from 2013 to 2014 due to higher production and ad valorem taxes per Mcfe associated with oil production in the South Texas region, higher severance tax rates in the State of Louisiana and the expiration of severance tax holidays on certain Haynesville shale wells in the East Texas/North Louisiana region. The rate per Mcfe was consistent on a consolidated basis for the year ended December 31, 2013 compared 2012 as a result of higher production and ad valorem taxes per Mcfe associated with oil production in the South Texas region that were offset by lower severance tax rates in the State of Louisiana.

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.
    
Production and ad valorem taxes are set by state and local governments and vary as to the tax rate and the value to which that rate is applied. In Louisiana, where a substantial percentage of our production is derived, severance taxes are levied on a per Mcf basis. Therefore, the resulting dollar value of production is not sensitive to changes in prices for natural gas, except for holiday exemptions, if any. In our other operating areas, particularly Texas, production taxes are based on a fixed percentage of gross value of production sold. As such, our realized severance and ad valorem tax rates may become more sensitive to prices, except for wells that receive holiday exemptions, if any. The Commonwealth of Pennsylvania requires an impact fee to be paid on all unconventional wells spud based on a price tier calculation for a period of 15 years. The Commonwealth of Pennsylvania is currently considering reforms to its tax code which could result in the enactment of a severance tax on the production of oil and natural gas. This severance tax may replace the impact fee and could have an impact on our production taxes in future periods. There is no certainty that this legislation will be passed nor is it possible to quantify the impact at this time.
Depletion, depreciation and amortization

Depletion expense for the year ended December 31, 2014 increased by $20.4 million , or 9% , as compared with 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 year ended December 31, 2014 was $1.90 per Mcfe, compared with $1.47 per Mcfe in 2013. The increase in the depletion rate was primarily due to the acquisition of assets in the Haynesville and Eagle Ford shale


60


during the third quarter of 2013 which increased our depletable base and higher future development costs associated with the 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. The depletion rate for the year ended December 31, 2013 was $1.47 per Mcfe, a $0.05 decrease from the year ended December 31, 2012. The decrease is primarily the result of significant impairments of our oil and natural gas properties during 2012, which lowered our depletable base.

Depreciation and amortization costs for the year ended December 31, 2014 decreased by $2.6 million , or 33% , 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. Our depreciation and amortization costs for the year ended December 31, 2013 decreased by $6.9 million, or 47%, compared to 2012. The decrease was due to contribution of gathering assets to Compass and the sale of other corporate assets in 2012.

Accretion of discount on asset retirement obligations for the year ended December 31, 2014 increased by $0.2 million , or 7% , compared with 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 and was partially offset by the contribution and sale of properties to Compass. The decrease for the year ended December 31, 2013 compared to 2012 was the result of the contribution of properties to Compass.
Impairment of oil and natural gas properties

For the year ended December 31, 2014 , we did not record an impairment to our oil and natural gas properties. For the years ended December 31, 2013 and 2012 , we recorded impairments of our oil and natural gas properties of $108.5 million and $1.3 billion , respectively. The impairments for the year ended December 31, 2013 were primarily due to low natural gas prices for the trailing 12 months at the end of the first quarter of 2013, downward revisions to the reserves of our Haynesville shale properties based on operational matters, narrowing of basis differentials between oil price indices, and higher costs associated with the gathering and transportation of our natural gas production from the Eagle Ford shale. The impairment of our oil and natural gas properties during 2012 was due to the significant decline in natural gas prices. As a result of recent declines in oil and natural gas prices, we expect to incur additional impairments to our oil and natural gas properties during 2015 if prices do not increase.
General and administrative
    
The following table presents our general and administrative expenses for the years ended December 31, 2014 , 2013 and 2012 :
 
 
Year Ended December 31,
 
Year to year change
(in thousands, except per unit rate)
 
2014
 
2013
 
2012
 
2014-2013
 
2013-2012
General and administrative costs:
 
 
 
 
 
 
 
 
 
 
Gross general and administrative expense
 
$
119,959

 
$
147,432

 
$
152,057

 
$
(27,473
)
 
$
(4,625
)
Technical services and service agreement charges
 
(24,747
)
 
(26,846
)
 
(25,242
)
 
2,099

 
(1,604
)
Operator overhead reimbursements
 
(13,507
)
 
(10,462
)
 
(20,544
)
 
(3,045
)
 
10,082

Capitalized salaries and share-based compensation
 
(15,785
)
 
(18,246
)
 
(22,453
)
 
2,461

 
4,207

General and administrative expense
 
$
65,920

 
$
91,878

 
$
83,818

 
$
(25,958
)
 
$
8,060

    
General and administrative expenses for the year ended December 31, 2014 decrease d by $26.0 million , or 28% , compared with 2013. Significant components of the changes in general and administrative expense for the year ended December 31, 2014 compared to 2013 were a result of:

decreased personnel and employee relocation costs of $12.4 million . The decrease was primarily the result of a reduction in our workforce and the centralization of certain functions from the Appalachia region. Also, we incurred$5.0 million of severance costs during 2013 associated with the resignation of our former chairman and chief executive officer. The decrease was partially offset by $2.2 million in severance costs associated with the reduction in our workforce during the second quarter of 2014;
decreased gross share-based compensation expense of $7.6 million . The decrease was primarily due to a reduction in headcount, higher forfeitures and additional expenses incurred with the modification of share-based payments in connection with the retirement and resignation of former executives in the prior year;


61


decreased various other gross general and administrative expenses of $7.5 million . The decrease reflects 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 asset acquisitions in 2013;
decreased technical services and service agreement recoveries of $2.1 million . The decrease was 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 $3.0 million . The increase is primarily associated with the additional operated wells acquired and developed in the Haynesville and Eagle Ford shales; and
decreased capitalized salaries and share-based compensation expense of $2.5 million primarily as a result of a reduction in employee headcount.
    
General and administrative expenses for the year ended December 31, 2013 increase d by $8.1 million , or 10% , compared with 2012. Significant components of the changes in general and administrative expense for the year ended December 31, 2013 compared to 2012 were a result of:

decreased personnel expenses of $11.0 million primarily related to a reduction in employee headcount. This decrease was partially offset by $5.0 million of severance costs during 2013 associated with the resignation of our former chairman and chief executive officer. The decrease also included a reduction in contract labor costs as part of cost-cutting initiatives throughout the Company;
increased technical service and service agreement recoveries of $1.6 million primarily due to service agreement charges associated with the operations of Compass, which was partially offset by decreased employee costs;
decreased overhead recoveries of $10.1 million arising from reductions in our drilling program and the contribution of properties to Compass;
decreased capitalized salaries and share-based compensation expense of $4.2 million primarily as a result of a reduction in employee headcount;
increased share-based compensation expense of $1.6 million primarily associated with the modification of share-based payments in connection with the retirement and resignation of former executives in the prior year. This was partially offset by a reduction in employee headcount from prior year; and
increased various other expenses of $4.8 million primarily consisting of employee relocation costs associated with the centralization of certain functions from the Appalachia region, transition service costs associated with the acquisition of Haynesville and Eagle Ford assets, as well as higher engineering and technology costs.

We have implemented initiatives to reduce our general and administrative costs during 2015 including a 15% reduction in our workforce. This will reduce our general and administrative expenses in future periods however we will incur severance payments in connection with these actions.
(Gain) loss on divestitures and other operating items

(Gain) loss on divestitures and other operating items was a net loss of $5.3 million , a net gain of $177.5 million and a net loss of $17.0 million for the years ended December 31, 2014, 2013 and 2012, respectively. The net loss for the year ended December 31, 2014 primarily consisted of legal expenses. The net gain for the year ended December 31, 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 $3.0 million of transaction costs associated with the acquisition of Haynesville and Eagle Ford assets and $6.7 million of legal expenses. The net loss of $17.0 million for the year ended December 31, 2012 included the retroactive portion of the Pennsylvania impact fee, resolution of various title defect adjustments, legal expenses, and losses related to equipment sales and inventory impairments.
Interest expense, net
 
The following table presents our interest expense for the years ended December 31, 2014 , 2013 and 2012 :


62


 
 
Year Ended December 31,
 
Period to period change
(in thousands)
 
2014
 
2013
 
2012
 
2014-2013
 
2013-2012
Interest expense:
 
 
 
 
 
 
 
 
 
 
2018 Notes
 
$
57,585

 
$
57,485

 
$
57,394

 
$
100

 
$
91

2022 Notes
 
30,104

 

 

 
30,104

 

EXCO Resources Credit Agreement
 
16,368

 
33,119

 
31,068

 
(16,751
)
 
2,051

Compass Production Partners Credit Agreement
 
2,022

 
2,335

 

 
(313
)
 
2,335

Amortization of deferred financing costs
 
7,939

 
28,169

 
8,644

 
(20,230
)
 
19,525

Capitalized interest
 
(20,060
)
 
(18,729
)
 
(23,809
)
 
(1,331
)
 
5,080

Other
 
326

 
210

 
195

 
116

 
15

Total interest expense
 
$
94,284

 
$
102,589

 
$
73,492

 
$
(8,305
)
 
$
29,097


Our interest expense, net for the year ended December 31, 2014 decreased $8.3 million from 2013 primarily due to a decrease in the amortization of deferred financing costs and lower average outstanding indebtedness. We incurred $21.0 million in expense related to accelerated deferred financing costs during 2013 primarily as a result of amendments to the EXCO Resources Credit Agreement. This was partially offset by higher average interest rates during 2014 as a result of the issuance of the 2022 Notes.

Our interest expense, net for the year ended December 31, 2013 increased $29.1 million from the year ended December 31, 2012. The increase was primarily due to the acceleration of deferred financing costs as a result of amendments to the EXCO Resources Credit Agreement. The increase in interest expense, net was also the result of a reduction in capitalized interest related to lower balances of unproved oil and natural gas properties. The increase in our average interest rate under the EXCO Resources Credit Agreement was partially offset by lower average borrowings during 2013 compared to 2012.
Derivative financial instruments

Our oil and natural gas derivative financial instruments resulted in a net gain of $87.7 million , net loss of $0.3 million and a net gain of $66.1 million for the years ended December 31, 2014 , 2013 and 2012 , respectively. The net gains during 2014 were primarily the result of declines in the futures prices of oil and natural gas towards the end of the year. Based on the nature of our derivative contracts, decreases in the related commodity price typically result in increases 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.
 
 
Year Ended December 31,
 
Period to period change
Average realized pricing:
 
2014
 
2013
 
2012
 
2014-2013
 
2013-2012
Natural gas equivalent per Mcfe
 
$
4.86

 
$
3.92

 
$
2.88

 
$
0.94

 
$
1.04

Cash settlements (payments) on derivative financial instruments, per Mcfe
 
(0.14
)
 
0.26

 
1.06

 
(0.40
)
 
(0.80
)
Net price per Mcfe, including derivative financial instruments
 
$
4.72

 
$
4.18

 
$
3.94

 
$
0.54

 
$
0.24


Our total cash settlements for 2014 were payments of $19.0 million , or $0.14 per Mcfe compared to receipts of $42.1 million , or $0.26 per Mcfe, in 2013 and $202.1 million , or $1.06  per Mcfe, in 2012 . As noted above, the significant fluctuations between settlements on our derivative financial instruments demonstrate the volatility in commodity prices.
Equity income (loss)
    
Our equity income (loss) was net income of $0.2 million , a net loss of $53.3 million and net income of $28.6 million for the years ended December 31, 2014, 2013 and 2012, respectively. The increase in equity income for the year ended December 31, 2014 compared with 2013 was primarily due to an impairment of our investment in TGGT during 2013. This was partially offset by equity income from our investment in TGGT prior to the sale of our interest on November 15, 2013.
    


63


The decrease in equity income for the year ended December 31, 2013 compared to 2012 was primarily due to the impairment of our investment in TGGT in 2013. Equity losses from our investment in OPCO increased $4.7 million from 2012 primarily due to impairment charges on a water management system as a result of low utilization. These decreases were partially offset by an increase in equity income from our investment in our midstream joint venture in Appalachia.
Income taxes

The following table presents a reconciliation of our income tax provision (benefit) for the years ended December 31, 2014 , 2013 and 2012 :
 
 
Year Ended December 31,
(in thousands)
 
2014
 
2013
 
2012
Federal income taxes (benefit) provision at statutory rate of 35%
 
$
42,234

 
$
7,772

 
$
(487,649
)
Increases (reductions) resulting from:
 
 
 
 
 
 
Goodwill
 

 
16,382

 

Adjustments to the valuation allowance
 
(64,757
)
 
(28,865
)
 
544,949

Non-deductible compensation
 
3,409

 
1,328

 
1,893

State taxes net of federal benefit
 
3,464

 
3,239

 
(59,406
)
State tax rate change
 
15,496

 

 

Other
 
154

 
144

 
213

Total income tax provision
 
$

 
$

 
$


During both 2014 and 2013, both federal and state income taxes were reduced to zero by a corresponding decrease to the valuation allowance previously recognized against net deferred tax assets. The net result was no income tax provision for both 2014 and 2013.

During 2012 , our net loss was significantly impacted by the impairments of our proved oil and natural gas properties. The tax benefits arising from these impairments were offset by a valuation allowance. There were no material sales transactions during the year to impact taxable income. The net result was no income tax provision for 2012.
    
As of December 31, 2014 , 2013 , and 2012 , there were no unrecognized tax benefits, including interest and penalties, that would be required to be recognized in our financial statements.

Our liquidity, capital resources and capital commitments

Overview

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;
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


64


our ability to maintain compliance with debt covenants.

Recent events affecting liquidity

During 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 an aggregate amount of $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.

On October 31, 2014, we closed the sale of our entire interest in Compass for $118.8 million in cash. We used a portion of the proceeds to reduce indebtedness under the EXCO Resources Credit Agreement. Our borrowing base was not affected by this sale as Compass was not a guarantor subsidiary. In addition, we amended the EXCO Resources Credit Agreement to increase our borrowing base to $900.0 million. As a result of these transactions, our liquidity improved from $224.6 million as of December 31, 2013 to $761.2 million as of December 31, 2014.

On February 6, 2015, we amended the EXCO Resources Credit Agreement to decrease our borrowing base from $900.0 million to $725.0 million as a result of the recent decline in oil and natural gas prices. The decrease in our borrowing base would have resulted in liquidity of $586.2 million on a pro forma basis if the borrowing base redetermination would have occurred on December 31, 2014. The next borrowing base redetermination for the EXCO Resources Credit Agreement will occur in August 2015. In addition, the financial covenants were amended to include an interest coverage ratio and senior secured indebtedness to consolidated EBITDAX ratio. The leverage ratio was suspended until the fourth quarter of 2016 and the ratio requirements thereafter were modified.

As a result of the recent decline in commodity prices, we plan to reduce our capital expenditures and defer a significant amount of our development until commodity prices improve. Our 2015 capital budget is expected to exceed our cash flows from operations and the deficit will be funded with borrowings under the EXCO Resources Credit Agreement. We have implemented cost reduction initiatives in order to mitigate the impact on our cash flows and liquidity. This includes the negotiation of development and operating cost reductions with several key vendors and plans to continue to pursue further reductions. Also, we have implemented initiatives to reduce our general and administrative costs including a 15% reduction in our workforce during 2015. We believe this strategy will allow us to preserve our liquidity in order to execute on our development program and corporate strategies.
 
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. Reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices. Accordingly, our ability to effectively execute our corporate strategies and manage our operating, general and administrative expenses and capital expenditure programs is critical to our financial condition, liquidity and our results of operations.

The following table presents information relating to our liquidity as of December 31, 2014 :
(in thousands)
 
December 31, 2014
EXCO Resources Credit Agreement
 
$
202,492

2018 Notes (1)
 
750,000

2022 Notes
 
500,000

Total debt
 
$
1,452,492

Net debt
 
$
1,382,217

Borrowing base (2)
 
$
900,000

Unused borrowing base (3)
 
$
690,935

Cash (4)
 
$
70,275

Unused borrowing base plus cash
 
$
761,210




65


(1)
Excludes unamortized discount of $6.0 million at December 31, 2014 .    
(2)
On February 6, 2015, our borrowing base was reduced to $725.0 million , which would have resulted in liquidity of $586.2 million on a pro forma basis if the borrowing base redetermination had occurred on December 31, 2014.
(3)
Net of $6.6 million in letters of credit as of December 31, 2014 .
(4)
Includes restricted cash of $24.0 million at December 31, 2014 .

Debt covenants

As of December 31, 2014 , our consolidated debt consisted of the EXCO Resources Credit Agreement, the 2018 Notes and the 2022 Notes (see "Note 6. Debt" in the Notes to our Consolidated Financial Statements for a further description of each agreement).

As of December 31, 2014 , EXCO was in compliance with the financial covenants contained in its credit agreement:

our consolidated current ratio (as defined in the EXCO Resources Credit Agreement) of 2.5 to 1.0 exceeded the minimum of at least 1.0 to 1.0 as of the end of any fiscal quarter; and
our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) of 3.9 to 1.0 did not exceed the maximum of 4.5 to 1.0 at the end of any fiscal quarter.

On February 6, 2015, we entered into the fourth amendment to the EXCO Resources Credit Agreement which amended our financial covenants under the agreement. The financial covenants (as defined in the EXCO Resources Credit Agreement) were amended to require that we:

maintain a consolidated current ratio of at least 1.0 to 1.0 as of the end of any fiscal quarter;
maintain a ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio") of at least 2.0 to 1.0 as of the end of any fiscal quarter;
not permit our ratio of senior secured indebtedness to consolidated EBITDAX ("Secured Indebtedness Ratio") to be greater than 2.50 to 1.0 as of the end of any fiscal quarter; and
not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX ("Leverage Ratio") as of the end of any fiscal quarter to be greater than the ratio set forth for the following periods:
Period
 
Ratio
The fiscal quarter ending December 31, 2016
 
6.00 to 1.00
The fiscal quarter ending March 31, 2017 and June 30, 2017
 
5.75 to 1.00
The fiscal quarter ending September 30, 2017
 
5.25 to 1.00
The fiscal quarter ending December 31, 2017
 
4.75 to 1.00
Each fiscal quarter ending thereafter
 
4.50 to 1.00

The Leverage Ratio will be calculated based on the consolidated EBITDAX for the trailing four quarter period ending on the last day of such fiscal quarter, except, the consolidated EBITDAX for quarter period ending December 31, 2016 shall be consolidated EBITDAX for quarter ending December 31, 2016 multiplied by 4.00, consolidated EBITDAX for the two quarter period ending March 31, 2017 shall be consolidated EBITDAX for such period multiplied by 2.00, and consolidated EBITDAX for the three quarter period ending June 30, 2017 shall be consolidated EBITDAX for such period multiplied by 4/3.

The amendments to the financial covenants will become effective as of March 31, 2015. If these covenants were effective as of December 31, 2014, our Interest Coverage Ratio of 3.6 to 1.0 would have exceeded the minimum of at least 2.0 to 1.0 and our Secured Indebtedness Ratio of 0.6 to 1.0 would not have exceeded the maximum of 2.50 to 1.0.

The indenture governing the 2018 Notes and 2022 Notes contains incurrence covenants which restrict our ability to incur additional indebtedness or pledge assets, among other things.

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 Interest Coverage Ratio, Secured Indebtedness Ratio, and Leverage Ratio, each as defined in the EXCO Resources Credit Agreement, are computed using EBITDAX for a trailing period 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 these covenants is negatively impacted when


66


oil and/or natural gas prices and/or production declines over an extended period of time. If we are not able to meet our debt covenants in future periods, we may be required but unable to refinance all or part of our existing debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all and may be required to surrender assets pursuant to the security provisions of the EXCO Resources Credit Agreement. Further, failing to comply with the financial and other restrictive covenants in the EXCO Resources Credit Agreement, 2018 Notes and 2022 Notes could result in an event of default, which could adversely affect our business, financial condition and results of operations. See "Note 6. Debt" in the Notes to our Consolidated Financial Statements for a description of our covenants under the EXCO Resources Credit Agreement, 2018 Notes and 2022 Notes.

Capital commitments

During 2013, we entered into the 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 at least 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. The wells included in the offer process that meet all of the specific well criteria are deemed to be "Committed Wells" and wells that do not meet the criteria are deemed to be "Uncertainty Wells." The specific well criteria includes factors such as the amount of time on artificial lift, temporary shut-in time, interference from other wells, recent offset fracturing activities or other trends that may result in variability in the performance trends used to establish estimates of reserves. Our joint venture partner is required to accept our offer on Committed Wells if they meet the established return thresholds. If a group of Committed Wells does not meet the established return thresholds, our joint venture partner has the right to decline our offer and the wells can be included in future offers. Our joint venture partner may accept the offers for the Uncertainty Wells; however, they have the ability to elect to defer those wells to future periods when they meet all of the criteria. Any well included in the offer process that remains an Uncertainty Well for two consecutive quarters becomes a Committed Well in the next quarterly offer process. Our joint venture partner has a right to retain an undivided 15% of their collective interest in the wells that we acquire.

The value of EXCO’s offers will be based on the PV-10 of the producing properties within each quarterly tranche of wells that have been on production for approximately one year. The pricing used in determining the PV-10 value will be based on NYMEX WTI futures contracts for 60 months then held constant for oil, NYMEX Henry Hub futures contracts for 60 months then held constant for natural gas, and the trailing 12 month actual NGL prices realized relative to WTI prices for NGLs. If EXCO and our joint venture partner are unable to agree upon the PV-10 value, an independent external engineering firm will be engaged to provide an independent valuation. The required return utilized in the offer acceptance process is based on 120% of our joint venture partner’s total invested capital for the wells within each quarterly tranche. The total invested capital used in the calculation of required return is reduced by the cash flows from the production of the wells prior to the offer date. Our joint venture partner is required to accept the offer if it exceeds the required return. If the PV-10 value exceeds our joint venture partner’s required return on investment, then EXCO and our joint venture partner will share the excess returns in the determination of the purchase price. This will result in a purchase price less than the PV-10 value.

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 December 31, 2014, we had spud 86 wells and turned-to-sales 60 wells which are expected to be included within future offers under the Participation Agreement. During 2015, we expect to spud an additional 16 wells which will be included in future offers under the Participation Agreement. The timing of these offers and potential acquisitions is dependent upon the date these wells are turned-to-sales, downtime during the year preceding the offer process 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 is approximately $3.8 million per well and our share 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 is approximately $3.6 million per well and our share prior to the acquisition is $1.2 million per well.


67



We made our first offer for wells drilled under the Participation Agreement during the first quarter of 2015. This included 7 wells for a total offer price of approximately $15.0 million. The offer consisted of 1 Committed Well for approximately $3.0 million and 6 Uncertainty Wells for approximately $12.0 million. Therefore, our joint venture partner is only required to accept the offer for the Committed Well. Our joint venture partner may accept the offers for the Uncertainty Wells, however they have the ability to elect to defer those wells to future periods when they meet all of the criteria. We expect the offer and acceptance process to be completed and the acquisition to close during the first quarter of 2015. There are 34 additional wells that are expected to be included in the offer process during the remainder of 2015; however, the extent and timing of these acquisitions in future periods will be dependent on the terms and conditions of the offer process. If our offers for the wells included in the first four quarters of the offer process do not meet the established return thresholds, we must increase our offer to meet the thresholds or our joint venture partner will no longer be required to accept future offers for Committed Wells that meet the established return thresholds. If we do not meet this requirement, this could prevent us from acquiring additional working interests in properties from our joint venture partner under the Participation Agreement if they do not accept our offers in the future.

Historical sources and uses of funds
Our primary sources of cash in 2014 were cash flows from operations, proceeds received from the Rights Offering 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:
 
 
Year Ended December 31,
(in thousands)
 
2014
 
2013
 
2012
Net cash provided by operating activities
 
$
362,093

 
$
350,634

 
$
514,786

Net cash used in investing activities
 
(221,588
)
 
(252,478
)
 
(427,094
)
Net cash used in financing activities
 
(144,683
)
 
(93,317
)
 
(74,045
)
Net increase (decrease) in cash
 
$
(4,178
)
 
$
4,839

 
$
13,647


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 the sales of oil, natural gas and NGLs 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 year ended December 31, 2014, our net cash provided by operating activities was $362.1 million as compared to $350.6 million for the year ended December 31, 2013. The increase is primarily attributable to higher revenues from the Haynesville and Eagle Ford shale assets we acquired in 2013 as well as an increase in natural gas prices. This was partially offset by lower natural gas production as well as a decrease in oil prices. In addition, the increase was due to changes in accounts receivable which provided cash of $52.0 million fo r the year ended December 31, 2014 as compared to $46.2 million of cash used for the year ended December 31, 2013. The decrease in accounts receivable for the year end December 31, 2014 as compared to prior year was primarily due to timing of collections of our oil and natural gas sales. This was partially offset by cash payments of $19.0 million on derivative contracts for the year ended December 31, 2014 co mpared to cash receipts of $42.1 million in the prior year.
Net cash provided by operating activities for the year ended December 31, 2013 was $350.6 million as compared to $514.8 million for the year ended December 31, 2012. The decrease is primarily attributable to lower settlement proceeds on our derivatives and less favorable working capital conversions. Settlements on derivative contracts decreased by $160.0 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012. The cash inflows from the acquisition of the Haynesville and Eagle Ford assets and higher realized oil and natural gas prices were partially offset by lower production primarily due to our contribution of properties to Compass.



68


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.
For the year ended December 31, 2014 , our net cash used in investing activities was $221.6 million which consisted of $391.8 million of drilling and development activities focused on the Haynesville, Bossier and Eagle Ford shales. This was partially offset by $118.8 million of proceeds received from the sale of our interest in Compass and approximately $68.2 million of proceeds received from the sale of our interest in certain non-operated assets in the Permian Basin.
For the year ended December 31, 2013, our cash flows used in investing activities were $252.5 million. Our property acquisitions during 2013 were primarily attributable to the acquisition of Haynesville and Eagle Ford assets of $942.9 million and our proportionate share of Compass's acquisition of the shallow Cotton Valley assets from an affiliate of BG Group. Our capital expenditures of $320.5 million were primarily focused on our development program in the East Texas/North Louisiana and South Texas regions. The cash used in investing activities was partially offset by the $574.8 million in proceeds as a result of the contribution of properties to Compass, the sale of our equity investment in TGGT of $236.6 million, net of commissions and fees, the sale of undeveloped acreage in the Eagle Ford for $130.9 million and other asset divestitures of $37.9 million.
For the year ended December 31, 2012, our cash flows used in investing activities were $427.1 million primarily related to development and exploration activities in the Haynesville and Marcellus shales.

Financing activities
For the year ended December 31, 2014, our net cash used in financing activities was $144.7 million primarily due to $859.9 million in net payments of outstanding indebtedness under the EXCO Resources Credit Agreement, $41.1 million of dividend payments and $10.3 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 year ended December 31, 2013, our cash flows used in financing activities were $93.3 million . The cash flows used in financing activities were primarily attributable to net borrowings under the EXCO Resources Credit Agreement to fund the acquisition of the Haynesville and Eagle Ford assets and the additional borrowings of Compass to fund the acquisition of shallow Cotton Valley assets. In addition, we paid $33.6 million of deferred financing costs associated with amendments to the EXCO Resources Credit Agreement and we paid $43.2 million of dividends on our common shares during 2013.
For the year ended December 31, 2012, our cash flows used in financing activities were $74.0 million. The cash flows used in investing activities primarily consisted of net repayments of indebtedness under the EXCO Resources Credit Agreement of $40.0 million. We paid $34.4 million of dividends on our common shares during 2012.

Capital expenditures
During 2014 , our capital expenditures, including oil and natural gas property acquisitions, totaled $434.8 million , of which $356.3 million was related to drilling and development activities. Our development program during 2014 primarily focused on our properties in the Haynesville, Bossier and Eagle Ford shales. During 2014, we operated three to six operated drilling rigs in the Haynesville and Bossier shales focused on our core area in DeSoto Parish, Louisiana and the Shelby area of East Texas. Our capital expenditures in this region also included re-fracture stimulation treatments on 5 gross ( 2.8 net) mature Haynesville shale wells. Our development program in the Eagle Ford shale focused on our core area in Zavala County, Texas and limited drilling outside our core area as part of a farmout agreement. We operated two to five operated drilling rigs in this region during 2014. We also installed pumping units on 87 gross ( 45.6 net) wells in the region to optimize our production. Our development activities during the year featured enhanced drilling and completion techniques which improved our well performance while we efficiently managed our capital expenditures.
During 2013 , our capital expenditures primarily consisted of our acquisitions of Haynesville and Eagle Ford assets as well as our development programs in these regions. The oil and natural gas property acquisitions of $942.9 million during 2013 included the Eagle Ford and Haynesville assets acquired from Chesapeake. In connection with closing the acquisition of the Eagle Ford assets, we entered into a Participation Agreement with a joint venture partner and sold an undivided 50% interest in the undeveloped acreage we acquired for approximately $130.9 million . Our development program during 2013 focused on our properties in the Haynesville and Eagle Ford shales. We operated three drilling rigs throughout 2013 in the Haynesville shale focused on our core area in DeSoto and Caddo Parish, Louisiana. We began our development program in the


69


Eagle Ford shale which included three to four operated drilling rigs from the date we acquired the properties to year-end. We also incurred additional expenditures in this region for surface acreage, infrastructure and operating facilities. Our expenditures in the Appalachia region focused on a limited appraisal drilling program, completion activities and the construction of pads for future drilling activity.
During 2012 , our capital expenditures primarily focused on our development program in the Haynesville shale as well as our appraisal and development program in the Marcellus shale. We significantly reduced our capital expenditures during 2012 as a result of the decline in natural gas prices. We also had a limited development program in the Permian Basin focused on conventional assets which were contributed to Compass during 2013. Our lease purchases during 2012 were primarily in the Permian Basin on acreage with horizontal drilling potential.
The following table presents our capital expenditures for the years ended December 31, 2014 , 2013 and 2012 .
 
 
Year Ended December 31,
(in thousands)
 
2014
 
2013
 
2012
Capital expenditures:
 
 
 
 
 
 
Lease purchases and seismic
 
$
10,477

 
$
25,052

 
$
49,158

Development capital expenditures
 
356,344

 
265,120

 
403,342

Field operations, gathering and water pipelines
 
20,256

 
12,379

 
1,044

Corporate and other
 
37,198

 
37,287

 
48,303

Total capital expenditures excluding oil and natural gas property acquisitions
 
424,275

 
339,838

 
501,847

Oil and natural gas property acquisitions (1)
 
10,562

 
942,946

 
3,349

Total capital expenditures including oil and natural gas property acquisitions
 
$
434,837

 
$
1,282,784

 
$
505,196


(1)
The oil and natural gas property acquisitions of $942.9 million during 2013 included the Eagle Ford and Haynesville assets. This amount was reduced by $130.9 million from the sale of a portion of the undeveloped acreage we acquired in the Eagle Ford shale to a joint venture partner.     

2015 capital budget
Our board of directors approved a capital budget of up to $275.0 million for 2015 , of which $215.0 million is allocated to development and completion activities. Our development activities in the East Texas/North Louisiana region are primarily focused on the Shelby area in East Texas and a limited drilling and completion program in the Holly area in North Louisiana. This includes a limited amount of capital allocated towards our re-fracture stimulation program. We have reduced our drilling activity in South Texas in response to lower crude oil prices. Our development activities in this region are designed to preserve leasehold commitments, fulfill continuous drilling obligations and drill key test wells in the Buda formation. Our capital expenditures in these regions are directed towards areas which have recently yielded strong results from enhanced drilling and completion methods. This has improved the economics of developing these locations and provides attractive returns even in a low commodity price environment. We also have plans for a limited appraisal drilling program in the Marcellus shale. We believe the capital budget is appropriate for current commodity prices and our capital structure. The 2015 capital budget is currently allocated among the different budget categories as follows:
 
 
Gross Wells Spud (1)
 
Net Wells Spud (1)
 
Net Wells Completed (1)
 
Drilling & Completion
 
Other Capital
 
Total Capital
(in millions, except wells)
 
 
 
 
 
 
East Texas/North Louisiana
 
25

 
11.9

 
17.6

 
$
150.0

 
$
8.0

 
$
158.0

South Texas
 
23

 
7.1

 
10.7

 
59.0

 
7.0

 
66.0

Appalachia
 
2

 
0.7

 
0.5

 
6.0

 
8.0

 
14.0

Corporate and other (2)
 

 

 

 

 
37.0

 
37.0

Total
 
50

 
19.7

 
28.8

 
$
215.0

 
$
60.0

 
$
275.0


(1)
The wells spud and completed within this table only include those operated by EXCO.
(2)
Includes $21.0 million of capitalized interest and $16.0 million of capitalized general and administrative expenses.

The 2015 capital budget excludes our acquisition program with a joint venture partner in the Eagle Ford shale, which is expected to be funded with borrowings under the EXCO Resources Credit Agreement.



70


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 December 31, 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:
 
 
 
 
 
 
 
 
2015
 
42,888

 
$
4.20

 
1,095

 
$
91.09

Basis swaps:
 
 
 
 
 
 
 
 
2015
 

 

 
91

 
6.10

Call options:
 
 
 
 
 
 
 
 
2015
 
20,075

 
4.29

 
365

 
100.00

Three-way collars:
 
 
 
 
 
 
 
 
2015
 
27,375

 
 
 

 
 
Sold call
 
 
 
4.47

 
 
 

Purchased put
 
 
 
3.83

 
 
 

Sold put
 
 
 
3.33

 
 
 

2016
 
10,980

 
 
 

 
 
Sold call
 
 
 
4.80

 
 
 

Purchased put
 
 
 
3.90

 
 
 

Sold put
 
 
 
3.40

 
 
 

See further details on our derivative financial instruments in "Note 4. Derivative financial instruments" and "Note 5. Fair value measurements" in the Notes to our Consolidated Financial Statements.

Off-balance sheet arrangements
As of December 31, 2014 , we had no arrangements or any guarantees of off-balance sheet debt to third parties.

Contractual obligations and commercial commitments
The following table presents our contractual obligations and commercial commitments as of December 31, 2014 . Gathering and firm transportation services presented in the following table represent our gross commitments under these contracts and a portion of these costs will be incurred by working interest and other owners. The commitments do not include those of our equity method investments.
 
 
Payments due by period
(in thousands)
 
 Less than one year
 
 One to three years
 
Three to five years
 
More than five years
 
Total
EXCO Resources Credit Agreement (1)
 
$

 
$

 
$
202,492

 
$

 
$
202,492

Senior Notes (2)
 

 

 
750,000

 
500,000

 
1,250,000

Gathering and firm transportation services (3)
 
136,040

 
266,289

 
218,200

 
101,618

 
722,147

Other fixed commitments (4)
 
17,332

 
18,696

 
5,613

 
3,530

 
45,171

Drilling contracts (5)
 
22,191

 
2,538

 

 

 
24,729

Operating leases and other
 
5,912

 
9,070

 
6,145

 
1,623

 
22,750

Total contractual obligations
 
$
181,475

 
$
296,593

 
$
1,182,450

 
$
606,771

 
$
2,267,289



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(1)
The EXCO Resources Credit Agreement matures on July 31, 2018. The interest rate grid on the revolving credit facility of the EXCO Resources Credit Agreement 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.
(2)
The 2018 Notes are due on September 15, 2018. The annual interest obligation is $56.3 million . The 2022 Notes are due on April 15, 2022. The annual interest obligation is $42.5 million .
(3)
Gathering and firm transportation services reflect contracts whereby EXCO commits to transport a minimum quantity of natural gas on a gatherer's system or a shippers’ pipeline. Whether or not EXCO delivers the minimum quantity, we pay the fees as if the quantities were delivered. These expenses represent our gross commitments under these contracts and a portion of these costs will be incurred by working interest and other owners.
(4)
Other fixed commitments are primarily related to completion service contracts and minimum sales commitments under marketing contracts.
(5)
Drilling contracts represent the early termination fees we would incur if we terminated our contracts for drilling rigs at December 31, 2014. The actual drilling costs under these contracts will be incurred by working interest owners in the development of the related properties.
Item 7A.     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 losses 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. 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 year ended December 31, 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 $94.1 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 December 31, 2014 , our exposure to interest rate changes related primarily to borrowings under the EXCO Resources Credit Agreement. The interest rate on the 2018 Notes is fixed at 7.5% per annum and the interest rate on the 2022 Notes is fixed at 8.5% per annum. Interest is payable on borrowings under the EXCO Resources Credit Agreement based on a floating rate as more fully described in "Note 6. Debt" in the Notes to our Consolidated Financial Statements. At December 31, 2014 , we had approximately $202.5 million in outstanding borrowings under the EXCO Resources Credit Agreement. A 1% increase in interest rates (100 bps) based on the variable borrowings as of December 31, 2014 would result in an increase in our interest expense of approximately $2.0 million per year. The interest we pay on these borrowings is set periodically based upon market rates.



72



Item 8.
Financial Statements and Supplementary Data
EXCO Resources, Inc.
Index to Consolidated Financial Statements
Contents
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



73


Management's Report on Internal Control Over Financial Reporting
To the Board of Directors and Shareholders of
EXCO Resources, Inc.:
    
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended). Our internal control over financial reporting is designed to provide reasonable assurance to management and our board of directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2014 . In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in Internal Control-Integrated Framework (2013) . Based on management's assessment, management believes that, as of December 31, 2014 , our internal control over financial reporting was effective based on those criteria.
    
The effectiveness of EXCO Resources, Inc.'s internal control over financial reporting as of December 31, 2014 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears herein.
By:
/s/ Harold L. Hickey
 
By:
/s/ Richard A. Burnett
Title:
President and Chief Operating Officer
 
Title:
Vice President, Chief Financial Officer
 
 
 
 
and Chief Accounting Officer
Dallas, Texas
 
 
 
 
February 25, 2015
 
 
 
 



74


Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
EXCO Resources, Inc.:
We have audited the accompanying consolidated balance sheets of EXCO Resources, Inc. and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, cash flows, and changes in shareholders’ equity for each of the years in the three-year period ended December 31, 2014. We also have audited EXCO Resources, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). EXCO Resources, Inc.’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting . Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EXCO Resources, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles. Also in our opinion, EXCO Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ KPMG LLP
Dallas, Texas
February 25, 2015


75



EXCO RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS

(in thousands)
 
December 31,
2014
 
December 31,
2013
 
 
 
 
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
46,305

 
$
50,483

Restricted cash
 
23,970

 
20,570

Accounts receivable, net:
 
 
 
 
Oil and natural gas
 
81,720

 
128,352

Joint interest
 
65,398

 
70,759

Other
 
8,945

 
18,022

Derivative financial instruments
 
97,278

 
8,226

Inventory and other
 
7,150

 
9,442

Total current assets
 
330,766

 
305,854

Equity investments
 
55,985

 
57,562

Oil and natural gas properties (full cost accounting method):
 
 
 
 
Unproved oil and natural gas properties and development costs not being amortized
 
276,025

 
425,307

Proved developed and undeveloped oil and natural gas properties
 
3,852,073

 
3,554,210

Accumulated depletion
 
(2,414,461
)
 
(2,183,464
)
Oil and natural gas properties, net
 
1,713,637

 
1,796,053

Gathering assets
 
1,488

 
33,473

Accumulated depreciation and amortization
 
(168
)
 
(10,338
)
Gathering assets, net
 
1,320

 
23,135

Office, field and other assets, net
 
23,324

 
27,233

Deferred financing costs, net
 
30,636

 
28,807

Derivative financial instruments
 
2,138

 
6,829

Deferred income taxes
 
35,935

 

Goodwill
 
163,155

 
163,155

Total assets
 
$
2,356,896

 
$
2,408,628


See accompanying notes.


















76



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

December 31,
2014

December 31,
2013
 

 

 
Liabilities and shareholders’ equity




Current liabilities:




Accounts payable and accrued liabilities

$
110,211


$
109,217

Revenues and royalties payable

152,651


154,862

Drilling advances
 
37,648

 
22,971

Accrued interest payable

26,265


18,144

Current portion of asset retirement obligations

1,769


191

Income taxes payable




Deferred income taxes
 
35,935

 

Derivative financial instruments

892


11,919

Current maturities of long-term debt
 

 
31,866

Total current liabilities

365,371


349,170

Long-term debt
 
1,446,535

 
1,858,912

Derivative financial instruments



9,671

Asset retirement obligations and other long-term liabilities

34,986


42,970

Commitments and contingencies




Shareholders’ equity:

 

 
Common shares, $0.001 par value; 350,000,000 authorized shares; 274,351,756 shares issued and 273,773,714 shares outstanding at December 31, 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 December 31, 2014; 54,574,734 issued and outstanding at December 31, 2013
 

 
55

Additional paid-in capital

3,502,209


3,219,748

Accumulated deficit

(2,984,860
)

(3,064,634
)
Treasury shares, at cost; 578,042 at December 31, 2014 and 539,221 at December 31, 2013

(7,615
)

(7,479
)
Total shareholders’ equity

510,004


147,905

Total liabilities and shareholders’ equity

$
2,356,896


$
2,408,628


See accompanying notes.



77


EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

 
 
Year Ended December 31,
(in thousands, except per share data)
 
2014
 
2013
 
2012
Revenues:
 
 
 
 
 
 
Oil
 
$
196,316

 
$
111,440

 
$
62,119

Natural gas
 
457,946

 
514,309

 
462,422

Natural gas liquids
 
6,007

 
8,560

 
22,068

Total revenues
 
660,269

 
634,309

 
546,609

Costs and expenses:
 
 
 
 
 
 
Oil and natural gas operating costs
 
64,467

 
61,277

 
77,127

Production and ad valorem taxes
 
29,859

 
21,971

 
27,483

Gathering and transportation
 
101,574

 
100,645

 
102,875

Depletion, depreciation and amortization
 
263,569

 
245,775

 
303,156

Impairment of oil and natural gas properties
 

 
108,546

 
1,346,749

Accretion of discount on asset retirement obligations
 
2,690

 
2,514

 
3,887

General and administrative
 
65,920

 
91,878

 
83,818

(Gain) loss on divestitures and other operating items
 
5,315

 
(177,518
)
 
17,029

Total costs and expenses
 
533,394

 
455,088

 
1,962,124

Operating income (loss)
 
126,875

 
179,221

 
(1,415,515
)
Other income (expense):
 
 
 
 
 
 
Interest expense, net
 
(94,284
)
 
(102,589
)
 
(73,492
)
Gain (loss) on derivative financial instruments
 
87,665

 
(320
)
 
66,133

Other income (expense)
 
241

 
(828
)
 
969

Equity income (loss)
 
172

 
(53,280
)
 
28,620

Total other income (expense)
 
(6,206
)
 
(157,017
)
 
22,230

Income (loss) before income taxes
 
120,669

 
22,204

 
(1,393,285
)
Income tax expense
 

 

 

Net income (loss)
 
$
120,669

 
$
22,204

 
$
(1,393,285
)
Earnings (loss) per common share:
 
 
 
 
 
 
Basic:
 
 
 
 
 
 
Net income (loss)
 
$
0.45

 
$
0.10

 
$
(6.50
)
Weighted average common shares outstanding
 
268,258

 
215,011

 
214,321

Diluted:
 
 
 
 
 
 
Net income (loss)
 
$
0.45

 
$
0.10

 
$
(6.50
)
Weighted average common shares and common share equivalents outstanding
 
268,376

 
230,912

 
214,321


See accompanying notes.



78


EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Year Ended December 31,
(in thousands)
 
2014
 
2013
 
2012
Operating Activities:
 
 
 
 
 
 
Net income (loss)
 
$
120,669

 
$
22,204

 
$
(1,393,285
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
 
Depletion, depreciation and amortization
 
263,569

 
245,775

 
303,156

Share-based compensation expense
 
4,962

 
10,748

 
8,926

Accretion of discount on asset retirement obligations
 
2,690

 
2,514

 
3,887

Impairment of oil and natural gas properties
 

 
108,546

 
1,346,749

(Income) loss from equity investments
 
(172
)
 
53,280

 
(28,620
)
(Gain) loss on derivative financial instruments
 
(87,665
)
 
320

 
(66,133
)
Cash settlements (payments) of derivative financial instruments
 
(18,991
)
 
42,119

 
202,078

Amortization of deferred financing costs and discount on debt issuance
 
12,055

 
29,624

 
9,788

(Gain) loss on divestitures and other non-operating items
 
(17
)
 
(185,163
)
 
1,303

Effect of changes in:
 
 
 
 
 
 
Accounts receivable
 
52,007

 
(46,176
)
 
112,919

Other current assets
 
(2,609
)
 
9,627

 
7,090

Accounts payable and other current liabilities
 
15,595

 
57,216

 
6,928

Net cash provided by operating activities
 
362,093

 
350,634

 
514,786

Investing Activities:
 
 
 
 
 
 
Additions to oil and natural gas properties, gathering assets and equipment
 
(391,776
)
 
(320,538
)
 
(534,175
)
Property acquisitions
 
(10,790
)
 
(976,714
)
 
(2,748
)
Proceeds from disposition of property and equipment
 
187,655

 
749,628

 
38,045

Restricted cash
 
(3,400
)
 
49,515

 
85,840

Net changes in advances to joint ventures
 
(5,026
)
 
10,645

 
851

Equity method investments
 
1,749

 
236,289

 
(14,907
)
Other
 

 
(1,303
)
 

Net cash used in investing activities
 
(221,588
)
 
(252,478
)
 
(427,094
)
Financing Activities:
 
 
 
 
 
 
Borrowings under credit agreements
 
100,000

 
1,004,523

 
53,000

Repayments under credit agreements
 
(964,970
)
 
(1,022,785
)
 
(93,000
)
Proceeds received from issuance of 2022 Notes
 
500,000

 

 

Proceeds from issuance of common shares, net
 
271,773

 
1,712

 
1,968

Payment of common share dividends
 
(41,060
)
 
(43,214
)
 
(34,358
)
Deferred financing costs and other
 
(10,290
)
 
(33,553
)
 
(1,655
)
Payments of common shares repurchased
 
(136
)
 

 

Net cash used in financing activities
 
(144,683
)
 
(93,317
)
 
(74,045
)
Net increase (decrease) in cash
 
(4,178
)
 
4,839

 
13,647

Cash at beginning of period
 
50,483

 
45,644

 
31,997

Cash at end of period
 
$
46,305

 
$
50,483

 
$
45,644

Supplemental Cash Flow Information:
 
 
 
 
 
 
Cash interest payments
 
$
91,735

 
$
88,936

 
$
86,298

Income tax payments
 

 

 

Supplemental non-cash investing and financing activities:
 
 
 
 
 
 
Capitalized share-based compensation
 
$
5,498

 
$
7,288

 
$
7,513

Capitalized interest
 
20,060

 
18,729

 
23,809

Issuance of common shares for director services
 
235

 
93

 
597

Debt eliminated upon sale of Compass and assumed upon formation of Compass, net for the years ended December 31, 2014 and 2013, respectively
 
(83,246
)
 
58,613

 

Issuance of subscription rights
 

 
55

 


See accompanying notes.


79


EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

 
 
Common Shares
 
Subscription Rights
 
Treasury Shares
 
Additional paid-in capital
 
Accumulated deficit
 
Total shareholders’ equity
(in thousands)
 
Shares
 
Amount
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
Balance at December 31, 2011
 
217,245

 
$
215

 

 
$

 
(539
)
 
$
(7,479
)
 
$
3,181,063

 
$
(1,615,467
)
 
$
1,558,332

Issuance of common shares
 
266

 

 

 

 

 

 
2,565

 

 
2,565

Share-based compensation
 

 

 

 

 

 

 
16,439

 

 
16,439

Restricted shares issued, net of cancellations
 
615

 

 

 

 

 

 

 

 

Common share dividends
 

 

 

 

 

 

 

 
(34,658
)
 
(34,658
)
Net income
 

 

 

 

 

 

 

 
(1,393,285
)
 
(1,393,285
)
Balance at December 31, 2012
 
218,126

 
$
215

 

 
$

 
(539
)
 
$
(7,479
)
 
$
3,200,067

 
$
(3,043,410
)
 
$
149,393

Issuance of common shares
 
228

 

 

 

 

 

 
1,805

 

 
1,805

Share-based compensation
 

 

 

 

 

 

 
17,931

 

 
17,931

Restricted shares issued, net of cancellations
 
429

 

 

 

 

 

 

 

 

Common share dividends
 

 

 

 

 

 

 

 
(43,428
)
 
(43,428
)
Issuance of subscription rights
 

 

 
54,575

 
55

 

 

 
(55
)
 

 

Net income
 

 

 

 

 

 

 

 
22,204

 
22,204

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 shares
 
54,582

 
55

 
(54,575
)
 
(55
)
 

 

 
272,008

 

 
272,008

Share-based compensation
 

 

 

 

 

 

 
10,453

 

 
10,453

Restricted shares issued, net of cancellations
 
987

 

 

 

 

 

 

 

 

Common share dividends
 

 

 

 

 

 

 

 
(40,895
)
 
(40,895
)
Treasury share repurchases
 

 

 

 

 
(39
)
 
(136
)
 

 

 
(136
)
Net income
 

 

 

 

 

 

 

 
120,669

 
120,669

Balance at December 31, 2014
 
274,352

 
$
270

 

 
$

 
(578
)
 
$
(7,615
)
 
$
3,502,209

 
$
(2,984,860
)
 
$
510,004

 
See accompanying notes.


80


EXCO RESOURCES, INC.
NOTES TO CONSO LIDATED FINANCIAL STATEMENTS

1.
Organization and basis of presentation
    
Unless the context requires otherwise, references in this Annual Report on Form 10-K 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.

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 and 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, Buda 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.

The accompanying Consolidated Balance Sheets as of December 31, 2014 and 2013 , Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2014 , 2013 and 2012 are for EXCO and its subsidiaries. The 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.

2.
Summary of significant accounting policies

Principles of consolidation
    
We consolidate all of our subsidiaries in the accompanying Consolidated Balance Sheets as of December 31, 2014 and 2013 and the Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Changes in Shareholders' Equity for the years ended December 31, 2014 , 2013 and 2012 . Investments in unconsolidated affiliates in which we are able to exercise significant influence are accounted for using the equity method. We use the cost method of accounting for investments in unconsolidated affiliates in which we are not able to exercise significant influence. All intercompany transactions and accounts have been eliminated.
    
We report our interests in oil and natural gas properties using the proportional consolidation method of accounting. We reported our 25.5% interest in Compass Production Partners, L.P. ("Compass") using proportional consolidation for the period from its formation on February 14, 2013 to the sale of our interests on October 31, 2014. See further discussion in "Note 3. Acquisitions, divestitures and other significant events."


81


Management estimates
    
In preparing the consolidated financial statements in conformity with GAAP, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting periods. The more significant estimates pertain to proved oil and natural gas reserve volumes, future development costs, asset retirement obligations, share-based compensation, estimates relating to oil and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and goodwill. Actual results may differ from management's estimates.
Cash equivalents
    
We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.
Restricted cash
    
The restricted cash on our balance sheet is principally comprised of our share of an evergreen escrow account with BG Group that is used to fund our share of development operations in East Texas/North Louisiana. Funds held in this escrow account are restricted and can be used primarily for drilling and operations in East Texas/North Louisiana.
Concentration of credit risk and accounts receivable
    
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivative financial instruments. We place our cash with financial institutions which we believe have sufficient credit quality to minimize risk of loss. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil or natural gas or participants in oil and natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to wells which we operate. Oil and natural gas receivables are generally uncollateralized. The allowance for doubtful accounts was immaterial at both December 31, 2014 and 2013 . We place our derivative financial instruments with financial institutions that we believe have high credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with our counterparties on 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.
    
For the years ended December 31, 2014 , 2013 and 2012 , sales to BG Energy Merchants LLC accounted for approximately 34% , 48% and 36% , respectively, of total consolidated revenues. BG Energy Merchants LLC is a subsidiary of BG Group. For the years ended December 31, 2014 and 2013 , Chesapeake Energy Marketing Inc. accounted for approximately 31% and 14% , respectively, of total consolidated revenues. Chesapeake Energy Marketing Inc. is a subsidiary of Chesapeake Energy Corporation ("Chesapeake").
Derivative financial instruments
    
We use derivative financial instruments to mitigate the impacts of commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow. Financial Accounting Standards Board ("FASB"), Accounting Standards Codification, ("ASC"), Topic 815, Derivatives and Hedging, ("ASC 815"), requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its estimated fair value. ASC 815 requires that changes in the derivative's estimated fair value be recognized in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales as permitted by ASC 815 exist. We do not designate our derivative financial instruments as hedging instruments and, as a result, recognize the change in a derivative's estimated fair value in earnings as a component of other income or expense. Our derivative financial instruments are not held for trading purposes.
Oil and natural gas properties
    
The accounting for, and disclosure of, oil and natural gas producing activities require 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.


82


Our unproved property costs, which include unproved oil and natural gas properties, properties under development, and major development projects, collectively totaled $276.0 million and $425.3 million  as of December 31, 2014 and 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 extension or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. Our undeveloped properties are predominantly 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. As a result of this evaluation, we did no t record an impairment of undeveloped properties during 2014 and recorded impairments of $1.0 million and $60.8 million of undeveloped properties during 2013 and 2012 , respectively. These impairments were transferred to the depletable portion of the full cost pool during each year. The impairments were recorded to reflect the estimated market price which included certain properties that were no longer part of our drilling plans.
    
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 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. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities.
    
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 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 December 31, 2014 , the trailing 12 month reference prices were $4.35 per Mmbtu for natural gas at Henry Hub ("HH"), and $94.99 per Bbl of oil for West Texas Intermediate ("WTI") at Cushing, Oklahoma. 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. The price used for NGLs was $33.03 per Bbl and was based on the trailing 12 month average of realized prices. 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 impacts of the derivative financial instruments in our ceiling test computations. The ceiling test limitation exceeded the book value of the full cost pool as of December 31, 2014 .

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.
    
For the year ended December 31, 2014 , we did no t recognize an impairment to our proved oil and natural gas properties and for the years ended December 31, 2013 and 2012 we recognized impairments $108.5 million and $1.3 billion , respectively, to our proved oil and natural gas properties. The impairments for the year ended December 31, 2013 were primarily due to low natural gas prices for the trailing 12 months at the end of the first quarter of 2013, downward revisions to the reserves of our Haynesville shale properties based on operational matters, narrowing of basis differentials between oil price indices, and higher


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costs associated with the gathering and transportation of our natural gas production from the Eagle Ford shale. The impairment of our oil and natural gas properties during 2012 was due to the significant decline in natural gas prices.
    
As a result of recent decline in oil and natural gas prices, we expect to incur additional impairments to our oil and natural gas properties in 2015 if prices do not increase. Based on the commodity prices to date during 2015, we expect the reference prices to be utilized in the ceiling test calculation beginning in the first quarter of 2015 to be significantly lower than the price used at December 31, 2014.
Inventory
    
Inventory includes tubular goods and other lease and well equipment which we plan to utilize in our ongoing exploration and development activities and is carried at the lower of cost or market value. The cost of inventory is capitalized in our full cost pool or gathering system assets once it has been placed into service.
Office, field and other equipment
    
Office, field and other equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives ranging from 3 to 15  years.
Goodwill
    
In accordance with FASB ASC 350-20, Intangibles-Goodwill and Other , goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of December 31 of each year. Losses, if any, resulting from impairment tests will be reflected in operating income in the Consolidated Statements of Operations.
    
We apply a two-part, equally weighted approach in determining the fair value of our business as part of the goodwill impairment test. We perform an income approach, which uses a discounted cash flow model to value our business, and a market approach, in which our value is determined using trading metrics and transaction multiples of peer companies. We also consider our market capitalization in our evaluation of the fair value of our business. As a result of testing, the fair value of our business exceeded the carrying value of net assets by approximately 18% at December 31, 2014 and we did not record an impairment charge for the periods ending December 31, 2014 , 2013 and 2012 .
Asset retirement obligations
    
We apply FASB ASC 410-20, Asset Retirement and Environmental Obligations ("ASC 410-20") to account for estimated future plugging and abandonment costs. ASC 410-20 requires legal obligations associated with the retirement of long-lived assets to be recognized at their estimated fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Our asset retirement obligations primarily represent the present value of the estimated amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws.


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The following is a reconciliation of our asset retirement obligations for the periods indicated:
 
 
December 31,
(in thousands)
 
2014
 
2013
 
2012
Asset retirement obligations at beginning of period
 
$
42,954

 
$
61,864

 
$
58,088

Activity during the period:
 
 
 
 
 
 
Liabilities incurred during the period
 
576

 
514

 
971

Revisions in estimated assumptions
 

 
1,268

 

Liabilities settled during the period
 
(33
)
 
(187
)
 
(338
)
Adjustment to liability due to acquisitions
 
107

 
5,566

 

Adjustment to liability due to divestitures (1)
 
(9,539
)
 
(28,585
)
 
(744
)
Accretion of discount
 
2,690

 
2,514

 
3,887

Asset retirement obligations at end of period
 
36,755

 
42,954

 
61,864

Less current portion
 
1,769

 
191

 
1,200

Long-term portion
 
$
34,986

 
$
42,763

 
$
60,664


(1)
For the year ended December 31, 2014, the adjustment to liability due to divestitures consisted primarily of $9.4 million from the sale of our interest in Compass. For the year ended December 31, 2013, the adjustment to liability due to divestitures consisted primarily of $28.3 million from the contribution of our certain conventional assets to Compass.
    
Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs and assumptions developed by management. We have no assets that are legally restricted for purposes of settling asset retirement obligations.
Revenue recognition and gas imbalances
    
We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at December 31, 2014 , 2013 and 2012 were not significant.
Gathering and transportation
    
We generally sell oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a net-back arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation incurred by the purchaser. In this case, we record sales at the price received from the purchaser, net of the transportation costs. Under the other arrangement, we sell oil or natural gas at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no transportation deduction. In this case, we record the transportation cost as gathering and transportation expense. Due to these two distinct selling arrangements, our computed realized prices, before the impact of derivative financial instruments, include revenues which are reported under two separate bases. Gathering and transportation expenses totaled $101.6 million , $100.6 million and $102.9 million for the years ended December 31, 2014 , 2013 and 2012 , respectively.
Capitalization of internal costs
    
As part of our proved developed oil and natural gas properties, we capitalize a portion of salaries and related share-based compensation for employees who are directly involved in the acquisition, exploration, exploitation and development of oil and natural gas properties. During the years ended December 31, 2014 , 2013 and 2012 , we capitalized $15.8 million , $18.2 million and $22.5 million , respectively. The capitalized amounts include $5.5 million , $7.3 million and $7.5 million of share-based compensation for the years ended December 31, 2014 , 2013 and 2012 , respectively.
Overhead reimbursement fees
    
We have classified fees from overhead charges billed to working interest owners of $13.5 million , $10.5 million and $20.5 million for the years ended December 31, 2014 , 2013 and 2012 , respectively, as a reduction of general and administrative


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expenses in the accompanying Consolidated Statements of Operations. We classified our share of these charges as oil and natural gas production costs in the amount of $6.4 million , $5.8 million and $10.3 million for the years ended December 31, 2014 , 2013 and 2012 , respectively.
    
In addition, we have agreements with BG Group that allow us to bill each other certain personnel costs and related fees incurred on behalf of certain properties in the East Texas/North Louisiana JV and the Appalachia JV. In connection with the formation of Compass, we entered into an agreement to perform certain operational, managerial, and administrative services. Compass reimbursed us for costs incurred in connection with the performance of these services based on an agreed upon service fee. As a result of the Compass sale, this agreement was terminated on October 31, 2014 and we entered 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. For the years ended December 31, 2014 , 2013 and 2012 , general and administrative expenses were reduced by $24.7 million , $26.8 million and $25.2 million , respectively, for recoveries of fees for our personnel and services provided to our joint ventures and other partners. These recoveries are net of fees charged to us by BG Group for their personnel and services.
Environmental costs
    
Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.
Income taxes
    
Income taxes are accounted for in accordance with FASB ASC 740, Income Taxes ("ASC 740"), under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Earnings per share
    
We account for earnings per share in accordance with FASB ASC 260-10, Earnings Per Share ("ASC 260-10"). ASC 260-10 requires companies to present two calculations of earnings per share ("EPS"); basic and diluted. Basic EPS is based on the weighted average number of common shares outstanding during the period, excluding stock options, restricted share units and restricted share awards. Diluted EPS is computed in the same manner as basic EPS after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units and restricted share awards, whether exercisable or not. Our diluted EPS for the year ended December 31, 2013 also included subscription rights which were the result of the rights offering of our common shares as discussed in "Note 15. Rights Offering and other equity transactions".
Share-based compensation
    
We account for our share-based compensation in accordance with FASB ASC Topic 718, Compensation-Stock Compensation ("ASC 718"). ASC 718 requires all share-based payments to employees, including grants of employee stock options, restricted share units and restricted share awards, to be recognized in our Consolidated Statements of Operations based on their estimated fair values. We recognize expense on a straight-line basis over the vesting period of the option, restricted share unit or restricted share award. We capitalize part of our share-based compensation that is attributable to our acquisition, exploration, exploitation and development activities.
    
Our 2005 Amended and Restated Long-Term Incentive Plan ("2005 Incentive Plan") provides for the granting of options and other equity incentive awards of our common shares in accordance with terms within the agreements. New shares will be issued for any options exercised or awards granted. Under the 2005 Incentive Plan, we have only issued stock options, restricted share units and restricted share awards, although the plan allows for other share-based awards.  
Recent accounting pronouncements
    
In April 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No.


86


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. As discussed in "Note 6. Debt", our ability to maintain compliance with certain debt covenants might be negatively impacted when oil and/or natural gas prices and production declines over an extended period of time. If such event occurs in future periods that could affect our ability to continue as going concern, we will provide appropriate disclosures as required by ASU 2014-15.

3.
Acquisitions, divestitures and other significant events

2014 divestitures

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").

Compass divestiture

On October 31, 2014, we closed the sale of our entire interest in Compass to Harbinger Group, Inc. ("HGI") for $118.8 million in cash. We used a portion of the proceeds to reduce indebtedness under the EXCO Resources Credit Agreement. Prior to the closing of the sale, we reported our 25.5% interest in Compass using proportional consolidation. Our consolidated assets and liabilities were reduced by our proportionate share of Compass's net assets of $31.4 million which included our proportionate share of the Compass's indebtedness of $83.2 million on October 31, 2014. The sale of our interest in Compass did not significantly alter the relationship between our capitalized costs and proved reserves and was 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. As a result, our capitalized costs were further reduced by $87.4 million .

At the closing, EXCO and HGI terminated the existing operating and administrative services agreements and entered into a customary transition services agreement pursuant to which EXCO will provide certain transition services to Compass for


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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.

2013 acquisitions, divestitures and other significant events

Compass

On February 14, 2013 , we formed Compass. Pursuant to the agreements governing the transaction, we contributed our conventional shallow producing assets in East Texas and North Louisiana and our shallow Canyon Sand and other assets in the Permian Basin of West Texas to Compass, in exchange for net cash proceeds of $574.8 million , after final purchase price adjustments, and a 25.5% economic interest in the partnership. HGI's economic interest in Compass was 74.5% at its formation.

The contribution of oil and natural gas properties to Compass significantly altered the relationship between our capitalized costs and proved reserves. In accordance with full cost accounting rules, we recorded a gain of $186.4 million , net of a proportionate reduction in goodwill of $55.1 million , for the year ended December 31, 2013.
Immediately following the closing, Compass entered into an agreement to purchase the remaining shallow Cotton Valley assets in East Texas/North Louisiana from an affiliate of BG Group for $130.7 million , after final purchase price adjustments. The assets acquired as a result of this transaction represented an incremental working interest in properties owned by Compass. The transaction closed on March 5, 2013 and was funded with borrowings from Compass's credit agreement.

Permian Basin transaction
On March 13, 2013 , we closed a sale and joint development agreement with a private party for the sale of an undivided 50% of our interest in certain undeveloped acreage in the Permian Basin. The private party was designated as the operator under the joint development agreement. We received $37.9 million in cash, after final closing adjustments.

Haynesville and Eagle Ford Acquisitions
On July 2, 2013 , we entered into definitive agreements with Chesapeake to acquire producing and undeveloped oil and natural gas assets in the Haynesville and Eagle Ford shale formations. We closed the acquisition of the Haynesville assets on July 12, 2013 for a purchase price of $281.1 million , after final purchase price adjustments. The acquisition included certain producing wells and non-producing oil, natural gas and mineral leases located in our core Haynesville shale operating area in Caddo Parish and DeSoto Parish, Louisiana. These properties included Chesapeake's non-operated interests in 170 wells operated by EXCO on approximately 5,500 net acres, and operated interests in 11 producing wells on approximately 4,000 net acres. The acquisition added approximately 55 identified drilling locations in the Haynesville shale formation to our drilling inventory. BG Group elected not to exercise its preferential right to acquire a 50% interest in these assets.

We closed the acquisition of the Eagle Ford assets on July 31, 2013 for a purchase price of $661.8 million , after final purchase price adjustments. The acquisition included certain producing wells and non-producing oil, natural gas and mineral leases in the Eagle Ford shale in the counties of Zavala, Dimmit and Frio in South Texas. These properties initially included operated interests in 120 wells on approximately 53,500 net acres. In connection with the acquisition of the Eagle Ford assets, we entered into a farm-out agreement with Chesapeake covering acreage adjacent to the acquired properties. Pursuant to the terms of the farm-out agreement, Chesapeake retains an overriding royalty interest in wells drilled on acreage covered by the farm-out agreement, with an option to convert the overriding royalty interest to a working interest at payout of the well.

We accounted for the acquisitions in accordance with FASB ASC Topic 805, Business Combinations . The following table presents a summary of the fair value of assets acquired and liabilities assumed as part of the Haynesville and Eagle Ford acquisitions based on the final settlement statements as of July 12, 2013 and July 31, 2013, respectively:


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Purchase Price Allocation (in thousands):
 
Haynesville Acquired Properties
 
Eagle Ford Acquired Properties
Assets acquired:
 
 
 
 
Unproved oil and natural gas properties
 
$
2,319

 
$
227,869

Proved developed and undeveloped oil and natural gas properties
 
282,918

 
437,616

Liabilities assumed:
 
 
 
 
Accounts payable and accrued liabilities
 

 
(580
)
Revenues and royalties payable
 
(3,526
)
 

Asset retirement obligations
 
(610
)
 
(3,060
)
Total purchase price
 
$
281,101

 
$
661,845

We performed a valuation of the assets acquired and liabilities assumed as of the respective acquisition dates. A summary of the key inputs are as follows:

Oil and Natural Gas Properties - The fair value allocated to proved and unproved oil and natural gas properties was $285.2 million for the Haynesville assets and $665.5 million for the Eagle Ford assets. The fair value of oil and natural gas properties was determined based on a discounted cash flow model of the estimated reserves. The estimated quantities of reserves utilized assumptions based on our internal geological, engineering and financial data. We utilized NYMEX forward strip prices to value the reserves, then applied various discount rates depending on the classification of reserves and other risk characteristics.

Asset Retirement Obligations - The fair value allocated to asset retirement obligations was $0.6 million for the Haynesville assets and $3.1 million for the Eagle Ford assets. These asset retirement obligations represent the present value of the estimated amount to be incurred to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws. The fair value was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate, and timing associated with the incurrence of these costs.

Revenues and royalties payable and accounts payable and accrued liabilities - The fair value was equivalent to the carrying amount because of the short-term nature of these liabilities.

Pro forma results of operations - The following table reflects the unaudited pro forma results of operations as though the acquisition of the Haynesville and Eagle Ford assets had occurred on January 1, 2012:
 
 
Year Ended December 31,
(in thousands, except for per share data)
 
2013
 
2012
Oil and natural gas revenues
 
$
784,628

 
$
715,286

Net income (loss) (1)
 
$
38,663

 
$
(1,398,169
)
Basic earnings (loss) per share
 
$
0.18

 
$
(6.52
)
Diluted earnings (loss) per share
 
$
0.17

 
$
(6.52
)
(1)
Net loss for the year ended December 31, 2012 was primarily due to the impairment of our oil and natural gas properties due to the significant decline in natural gas prices.

KKR Participation Agreement
In connection with closing the acquisition of the Eagle Ford assets, we entered into a participation agreement with KKR ("Participation Agreement") and sold an undivided 50% interest in the undeveloped acreage we acquired for approximately $130.9 million , after final purchase price adjustments. Proceeds from the sale of properties under the Participation Agreement were used to reduce outstanding borrowings under the EXCO Resources Credit Agreement. After giving effect to the KKR payment, the EXCO Resources Credit Agreement borrowing base and outstanding borrowings were reduced by $130.9 million .

Under the Participation Agreement, 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


89


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.

TGGT transaction
On November 15, 2013, EXCO and BG Group closed the conveyance of 100% of the equity interests in TGGT to Azure Midstream Holdings LLC ("Azure"). We received $240.2 million in net cash proceeds at the closing and an equity interest in Azure of approximately 4% . We recorded an equity investment of $13.4 million , net of a discount for a control premium, in Azure which is accounted for under the cost method of accounting. Investments accounted for by the cost method are tested for impairment if an impairment indicator is present.

At the closing of the agreement, EXCO and BG Group agreed to deliver to Azure’s gathering systems an aggregate minimum volume commitment of 600,000 Mmbtu/day of natural gas production from the Holly and Shelby fields over a five year period. The minimum volume commitment may be satisfied with (i) production of EXCO, BG Group and each of their respective affiliates, (ii) production of joint venture partners of either EXCO, BG Group or their affiliates, and (iii) production of non-operating working interest owners to the extent EXCO, BG Group, and each of their respective affiliates or its joint venture partner controls such production. If there is a shortfall to the minimum volume commitment in any year, then EXCO and BG Group are severally responsible for paying to Azure a shortfall payment in an amount equal to the amount of the shortfall (calculated on an annualized basis) times $0.40 per Mmbtu. EXCO and BG Group are entitled to credit 25% of any production volumes delivered in excess of the minimum volume commitment during any year to the subsequent year.

We used all of the cash proceeds from the sale of TGGT to reduce outstanding borrowings under the EXCO Resources Credit Agreement. We recorded an other than temporary impairment of $86.8 million to our investment in TGGT during 2013 as a result of the carrying value exceeding the fair value.

2012 acquisitions and divestitures

During 2012, we made acreage purchases in our Appalachia and Permian regions and sold a portion of our West Virginia acreage for net proceeds of $14.3 million .

4.
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 losses 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)
 
December 31, 2014
 
December 31, 2013
Derivative financial instruments - Current assets
 
$
97,278

 
$
8,226

Derivative financial instruments - Long-term assets
 
2,138

 
6,829

Derivative financial instruments - Current liabilities
 
(892
)
 
(11,919
)
Derivative financial instruments - Long-term liabilities
 

 
(9,671
)
Net derivative financial instruments
 
$
98,524

 
$
(6,535
)


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The Effect of Derivative Financial Instruments
 
 
Year Ended December 31,
(in thousands)
 
2014
 
2013
 
2012
Gain (loss) on derivative financial instruments
 
$
87,665

 
$
(320
)
 
$
66,133

    
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.

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.


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The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments as of December 31, 2014 :
(in thousands, except prices)
 
Volume Mmbtu/Bbl
 
Weighted average strike price per Mmbtu/Bbl
 
Fair value at December 31, 2014
Natural gas:
 
 
 
 
 
 
Swaps:
 
 
 
 
 
 
2015
 
42,888

 
$
4.20

 
49,926

Call options:
 
 
 
 
 
 
2015
 
20,075

 
4.29

 
(784
)
Three-way collars:
 
 
 
 
 
 
2015
 
27,375

 
 
 
10,205

Sold call
 
 
 
4.47

 
 
Purchased put
 
 
 
3.83

 
 
Sold put
 
 
 
3.33

 
 
2016
 
10,980

 
 
 
2,138

Sold call
 
 
 
4.80

 
 
Purchased put
 
 
 
3.90

 
 
Sold put
 
 
 
3.40

 
 
Total natural gas
 
 
 
 
 
$
61,485

Oil:
 
 
 
 
 
 
Swaps:
 
 
 
 
 
 
2015
 
1,095

 
$
91.09

 
36,797

Basis swaps:
 
 
 
 
 
 
2015
 
91

 
6.10

 
350

Call options:
 
 
 
 
 
 
2015
 
365

 
100.00

 
(108
)
Total oil
 
 
 
 
 
$
37,039

Total oil and natural gas derivative financial instruments
 
 
 
 
 
$
98,524

    
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 December 31, 2014 , the average forward NYMEX WTI oil price per Bbl for the calendar year 2015 was $56.26 , the average forward NYMEX Louisiana Light Sweet ("LLS") oil price per barrel for the calendar years 2015 was $58.51 and the average forward NYMEX Henry Hub natural gas prices per Mmbtu for the calendar years 2015 and 2016 were $3.01 and $3.46 , respectively.

Our derivative financial instruments covered approximately 69% and 57% of production volumes for the years ended December 31, 2014 and 2013 .

5.
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:


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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 years ended December 31, 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 December 31, 2014 and 2013 .
 
 
December 31, 2014
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total
Oil and natural gas derivative financial instruments
 
$

 
$
98,524

 
$

 
$
98,524

 
 
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. 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.

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 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 4. 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.



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The carrying values of our borrowings under the revolving commitment of the EXCO Resources Credit Agreement approximates fair value, as it is 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"), at December 31, 2014 and December 31, 2013 are presented below. The estimated fair values of the 2018 Notes, 2022 Notes and Term Loan have been calculated based on market quotes.
 
 
 
December 31, 2014
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total
2018 Notes
 
$
558,750

 
$

 
$

 
$
558,750

2022 Notes
 
373,500

 

 

 
373,500

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

 
$

 
$

 
$
714,000

Term Loan
 
298,500

 

 

 
298,500


6.
Debt
    
Our total debt is summarized as follows:
(in thousands)
 
December 31, 2014
 
December 31, 2013
Revolving credit facility under EXCO Resources Credit Agreement
 
$
202,492

 
$
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
 
(5,957
)
 
(7,293
)
2022 Notes
 
500,000

 

Total debt excluding Compass
 
1,446,535

 
1,802,293

Compass Production Partners Credit Agreement
 

 
88,485

Total debt
 
1,446,535

 
1,890,778

Less amounts due within one year
 

 
31,866

Total debt due after one year
 
$
1,446,535

 
$
1,858,912

    
Terms and conditions of each of these debt obligations are discussed below.
EXCO Resources Credit Agreement

As of December 31, 2014, the EXCO Resources Credit Agreement had $202.5 million of outstanding indebtedness, $900.0 million of available borrowing base and $690.9 million of unused borrowing base, net of letters of credit. The maturity date of the EXCO Resources Credit Agreement is July 31, 2018 . 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 December 31, 2014, the one month LIBOR was 0.2% , which resulted in an interest rate of approximately 1.9% on the revolving commitment.

We closed a rights offering and related private placement of our common shares 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.



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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. 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.

On October 31, 2014 we closed the sale of our entire interest in Compass. The transaction resulted in a reduction to our consolidated indebtedness by our proportionate share of Compass's indebtedness, which at closing was $83.2 million . In addition, we used a portion of our proceeds from this transaction to reduce the outstanding indebtedness under the EXCO Resources Credit Agreement. Compass was not a guarantor to the EXCO Resources Credit Agreement, 2018 Notes or the 2022 Notes. As such, our borrowing base was not affected by this sale. See further discussion in "Note 3. Acquisitions, divestitures, and other significant events".

On February 6, 2015, we amended the EXCO Resources Credit Agreement which decreased our borrowing base from $900.0 million to $725.0 million as a result of the recent decline in oil and natural gas prices. The next borrowing base redetermination for the EXCO Resources Credit Agreement will occur in August 2015. Subsequent redeterminations will occur semi-annually with us and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. In addition, the financial covenants were amended to include an interest coverage ratio and senior secured indebtedness to consolidated EBITDAX ratio. The leverage ratio was suspended until the fourth quarter of 2016 and the ratio requirements thereafter were modified.

The majority of our subsidiaries are guarantors under the EXCO Resources Credit Agreement. The EXCO Resources Credit Agreement permits investments, loans and advances to the unrestricted subsidiaries related to our joint ventures with certain limitations, and allows us to repurchase up to $200.0 million of our common shares, of which $7.6 million has been repurchased to date. We repurchased 38,821 shares for $0.1 million in 2014 that were tendered by employees to satisfy minimum tax withholding amounts for restricted share awards. There were no share repurchases during 2013 and 2012 .

Borrowings under the EXCO Resources Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than 80% of the engineered value, as defined in the agreement, in our oil and natural gas properties covered by the borrowing base. We are permitted to have derivative financial instruments covering no more than 100% of forecasted production from total Proved Reserves, as defined in the agreement, for any month during the first two years of the forthcoming five-year period, 90% of forecasted production from total Proved Reserves for any month during the third year of the forthcoming five-year period and 85% of forecasted production from total Proved Reserves for any month during the fourth and fifth years of the forthcoming five-year period.

The EXCO Resources Credit Agreement sets forth the terms and conditions under which we are permitted to pay a cash dividend on our common shares. In July 2014, we amended the EXCO Resources Credit Agreement to provide that we may declare and pay cash dividends on our common shares 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 December 31, 2014 , we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which required 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.

On February 6, 2015, we amended the EXCO Resources Credit Agreement which requires that we:

maintain a consolidated current ratio of at least 1.0 to 1.0 as of the end of any fiscal quarter;
maintain a ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio") of at least 2.0 to 1.0 as of the end of any fiscal quarter;
not permit our ratio of senior secured indebtedness to consolidated EBITDAX ("Secured Indebtedness Ratio") to be greater than 2.50 to 1.0 as of the end of any fiscal quarter; and
not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX ("Leverage Ratio") as of the end of any fiscal quarter to be greater than the ratio set forth for the following periods:


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Period
 
Ratio
The fiscal quarter ending December 31, 2016
 
6.00 to 1.00
The fiscal quarter ending March 31, 2017 and June 30, 2017
 
5.75 to 1.00
The fiscal quarter ending September 30, 2017
 
5.25 to 1.00
The fiscal quarter ending December 31, 2017
 
4.75 to 1.00
Each fiscal quarter ending thereafter
 
4.50 to 1.00

The Leverage Ratio will be calculated based on the consolidated EBITDAX for the trailing four quarter period ending on the last day of such fiscal quarter, except, the consolidated EBITDAX for quarter period ending December 31, 2016 shall be consolidated EBITDAX for quarter ending December 31, 2016 multiplied by 4.00 , consolidated EBITDAX for the two quarter period ending March 31, 2017 shall be consolidated EBITDAX for such period multiplied by 2.00 , and consolidated EBITDAX for the three quarter period ending June 30, 2017 shall be consolidated EBITDAX for such period multiplied by 4/3 .
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 December 31, 2014 , $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at December 31, 2014 was $6.0 million . Interest accrues at 7.5% and is payable semi-annually in arrears on March 15th and September 15th 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 shares;
pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
make certain investments;
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.

The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and 2022 Notes.

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 2015 and into 2016, there are certain


96


risks arising from depressed oil and natural gas prices and declines in production volumes that could impact our liquidity and ability to meet debt covenants in future periods. Our ability to maintain compliance with our debt covenants may be negatively impacted when oil and/or natural gas prices remain depressed for an extended period of time. Reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices. Accordingly, our ability to effectively execute our corporate strategies and manage our operating, general and administrative expenses and capital expenditure programs is critical to our financial condition, liquidity and our results of operations.

If we are not able to meet our debt covenants in future periods, we may be required but unable to refinance all or part of our existing debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all, and may be required to surrender assets pursuant to the security provisions of the EXCO Resources Credit Agreement. Further, failing to comply with the financial and other restrictive covenants in the EXCO Resources Credit Agreement, 2018 Notes and 2022 Notes could result in an event of default, which could adversely affect our business, financial condition and results of operations.

7.
Environmental regulation

Various federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipate that we will be required in the foreseeable future to expend amounts material in relation to the financial statements taken as a whole by reason of environmental laws and regulations. Because these laws and regulations are constantly being changed, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us.

8.
Commitments and contingencies
    
The following table presents our future minimum obligations under our commercial commitments as of December 31, 2014. The commitments do not include those of our equity method investments. Gathering and firm transportation services presented in the following tables represent our gross commitments under these contracts and a portion of these costs will be incurred by working interest and other owners.
(in thousands)
 
Gathering and firm transportation services
 
Other fixed commitments
 
Drilling contracts
 
Operating leases and other
 
Total
2015
 
$
136,040

 
$
17,332

 
$
22,191

 
$
5,912

 
$
181,475

2016
 
133,429

 
13,253

 
2,538

 
5,223

 
154,443

2017
 
132,860

 
5,443

 

 
3,847

 
142,150

2018
 
129,140

 
3,210

 

 
3,094

 
135,444

2019
 
89,060

 
2,403

 

 
3,051

 
94,514

Thereafter
 
101,618

 
3,530

 

 
1,623

 
106,771

Total
 
$
722,147

 
$
45,171

 
$
24,729

 
$
22,750

 
$
814,797

    
We lease our offices and certain equipment. Our rental expenses were approximately $5.1 million , $5.9 million and $6.8 million for the years ended December 31, 2014 , 2013 and 2012 , respectively. We have also entered into various drilling rig contracts primarily to develop our Haynesville and Eagle Ford shale assets. The actual drilling costs under these contracts will be incurred by working interest owners in the development of the related properties. These contracts are short-term in nature and are dependent on our planned drilling program.

We have entered into firm transportation and gathering agreements with pipeline companies to facilitate sales from our East Texas/North Louisiana production and report these costs as a component of gathering and transportation expenses. At December 31, 2014, our firm transportation and gathering agreements covered the following gross volumes of natural gas:


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(in Bcf)
 
Firm transportation services
 
Gathering services
2015
 
293

 
110

2016
 
272

 
110

2017
 
269

 
110

2018
 
269

 
100

2019
 
269

 

Thereafter
 
299

 

Total
 
1,671

 
430


Our other fixed commitments primarily consist of completion service contracts and marketing contracts in which we are obligated to pay the buyer a fee if we fail to deliver minimum quantities of natural gas.

In the ordinary course of business, we are periodically a party to lawsuits. From time to time, oil and natural gas producers, including EXCO, have been named in various lawsuits alleging underpayment of royalties and the allocation of production costs in connection with oil, natural gas and NGLs produced and sold. We have reserved our estimated exposure and do not believe it was material to our current, or future, financial position or results of operations.
    
We do not believe that any resulting liability from any additional existing legal proceedings, individually or in the aggregate, will have a material adverse effect on our results of operations or financial condition and have properly reflected any potential exposure in our financial position when determined to be both probable and estimable.

9.
Employee benefit plans
    
We sponsor a 401(k) plan for our employees and match 100% of employee contributions. Our matching contributions were $7.1 million , $8.8 million and $9.4 million for the years ended December 31, 2014 , 2013 and 2012 , respectively.  

10.
Earnings per share
    
The following table presents the basic and diluted earnings (loss) per share computations for the years ended December 31, 2014 , 2013 and 2012
 
 
Year Ended December 31,
(in thousands, except per share data)
 
2014
 
2013
 
2012
Basic net income (loss) per common share:
 
 
 
 
 
 
    Net income (loss)
 
$
120,669

 
$
22,204

 
$
(1,393,285
)
    Weighted average common shares outstanding
 
268,258

 
215,011

 
214,321

    Net income (loss) per basic common share
 
$
0.45

 
$
0.10

 
$
(6.50
)
Diluted net income (loss) per common share:
 
 
 
 
 
 
   Net income (loss)
 
$
120,669

 
$
22,204

 
$
(1,393,285
)
Weighted average common shares outstanding
 
268,258

 
215,011

 
214,321

Dilutive effect of:
 
 
 
 
 
 
Stock options
 

 

 

Restricted shares and restricted share units
 
118

 
420

 

Subscription rights
 

 
15,481

 

Weighted average common shares and common share equivalents outstanding
 
268,376

 
230,912

 
214,321

    Net income (loss) per diluted common share
 
$
0.45

 
$
0.10

 
$
(6.50
)
    
The computation of diluted EPS excluded 14,316,409 , 55,524,191 and 17,242,306 antidilutive common share equivalents for the years ended December 31, 2014 , 2013 and 2012 , respectively. The antidilutive common share equivalents for the year ended December 31, 2014 and 2012 primarily related to out-of-the-money stock options, unvested restricted share units and unvested restricted share awards. The antidilutive common share equivalents for the year ended December 31, 2013 primarily consisted of subscription rights outstanding, out-of-the-money stock options and unvested restricted shares.



98


11.
Stock options and awards

Description of plan

Our 2005 Incentive Plan is a shareholder-approved plan authorizing the issuance of up to 45,500,000 restricted shares, restricted share units and stock options. As of December 31, 2014 and 2013 , there were 19,763,916 and 21,118,292 shares, respectively, available for issuance under the 2005 Incentive Plan. Option grants count as one share against the total number of shares we have available for grant and restricted share grants count as 1.17 shares for awards granted before October 6, 2011, 2.1 shares for awards granted after October 6, 2011 and 1.74 shares for awards granted after June 11, 2013. The holders of restricted shares, excluding certain market-based restricted share awards discussed below, have voting rights, and upon vesting, the right to receive all accrued and unpaid dividends.

Compensation costs

We account for our stock-based options and awards in accordance with ASC 718. As required by ASC 718, the granting of options and awards to our employees under the 2005 Incentive Plan are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital.

Total share-based compensation to be recognized on unvested options, restricted share awards and restricted share units as of December 31, 2014 was $20.4 million . Of this amount, $3.1 million related to unvested options and will be recognized over a weighted average period of 1.7 years and $17.3 million related to unvested restricted share units and awards will be recognized over a weighted average period of 2.2 years.

The following is a reconciliation of our share-based compensation expense for the years ended December 31, 2014 , 2013 and 2012 :

 
 
Year Ended December 31,
(in thousands)
 
2014
 
2013
 
2012
Share-based compensation expense
 
$
4,962

 
$
10,748

 
$
8,926

Share-based compensation capitalized
 
5,498

 
7,288

 
7,513

Total share-based compensation
 
$
10,460

 
$
18,036

 
$
16,439


We did not recognize a tax benefit attributable to our share-based compensation for the years ended December 31, 2014, 2013 and 2012.
 
Stock options
    
Our outstanding stock option expiration dates range from 5 to 10 years following the date of grant and have a weighted average remaining life of 3.7 years. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant.
    


99


The following table summarizes stock option activity related to our employees under the 2005 Incentive Plan for the years ended December 31, 2014 , 2013 and 2012 :
 
 
 
Stock Options
 
Weighted average exercise price per share
 
Weighted average remaining terms (in years)
 
Aggregate intrinsic value
 
 
Options outstanding at December 31, 2011
 
15,670,168

 
$
13.44

 
 
 
 
 
Granted
 
146,500

 
8.00

 
 
 
 
 
Forfeitures
 
(1,543,933
)
 
16.12

 
 
 
 
 
Exercised
 
(256,940
)
 
7.66

 
 
 
 
 
Options outstanding at December 31, 2012
 
14,015,795

 
13.20

 
 
 
 
 
Granted
 
2,886,500

 
7.48

 
 
 
 
 
Forfeitures
 
(4,969,877
)
 
11.32

 
 
 
 
 
Exercised
 
(220,675
)
 
7.66

 
 
 
 
 
Options outstanding at December 31, 2013
 
11,711,743

 
12.69

 
 
 
 
 
Granted
 
141,525

 
5.24

 
 
 
 
 
Forfeitures
 
(1,700,250
)
 
12.71

 
 
 
 
 
Exercised
 
(2,500
)
 
5.22

 
 
 
 
 
Options outstanding at December 31, 2014
 
10,150,518

 
$
12.58

 
3.7
 
$

 
Options exercisable at December 31, 2014
 
9,181,306

 
$
13.15

 
3.2
 
$


 The weighted average fair value of stock options on the date of the grant during the years ended December 31, 2014 , 2013 and 2012 was $2.23 , $3.53 and $3.96 , respectively. The total intrinsic value of stock options exercised for the years ended December 31, 2014 , 2013 and 2012 was $0.0 million , $0.2 million and $0.1 million , respectively.

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The exercise price of the options is based on the fair market value of the common shares on the date of grant. The following assumptions were used for the options included in the table above, for the years ended December 31:
 
 
2014
 
2013
 
2012
Expected life
 
7.5 years
 
3.8 to 7.5 years
 
3.8 to 7.5 years
Risk-free rate of return
 
2.25 - 2.61 %
 
0.48 - 2.49 %
 
0.56 - 1.64 %
Volatility
 
59.46 - 59.61 %
 
49.47 - 59.86 %
 
57.34 - 60.24 %
Dividend yield
 
3.36 - 4.34 %
 
2.27 - 3.87 %
 
0.52 - 1.92 %

Expected life was determined based on EXCO's exercise history. Risk-free rate of return is a rate of a similar term U.S. Treasury zero coupon bond. Volatility was determined based on the weighted average of historical volatility of our common shares and the daily closing prices from comparable public companies. Dividend yield was determined based on EXCO's expected annual dividend and the market price of our common stock on the date of grant.

Service-based restricted share awards
    
Our service-based restricted share awards are valued at the closing price of our common shares on the date of grant and vest over a range of two to five years. A summary of our service-based restricted share activity for the years ended December 31, 2014 , 2013 and 2012 are as follows:


100


 
 
 
Shares
 
Weighted average grant date fair value per share
 
 
Non-vested shares outstanding at December 31, 2011
 
2,562,409

 
$
11.72

 
Granted
 
926,900

 
7.57

 
Vested
 
(370,448
)
 
12.89

 
Forfeited
 
(312,496
)
 
11.89

 
Non-vested shares outstanding at December 31, 2012
 
2,806,365

 
$
10.16

 
Granted
 
556,700

 
7.15

 
Vested
 
(832,706
)
 
10.47

 
Forfeited
 
(602,045
)
 
9.84

 
Non-vested shares outstanding at December 31, 2013
 
1,928,314

 
$
9.26

 
Granted
 
1,339,782

 
5.20

 
Vested
 
(1,109,866
)
 
9.79

 
Forfeited
 
(280,301
)
 
6.89

 
Non-vested shares outstanding at December 31, 2014
 
1,877,929

 
$
6.40


Market-based restricted share awards
    
On August 13, 2013, EXCO’s officers were granted a market-based restricted share award. The total number of shares granted was 736,000 of which 368,000 will be vested following any 30 consecutive trading days in which the company’s common stock equals or exceeds $10.00 per share and 368,000 shares will be vested following any 30 consecutive trading days in which the Company’s common shares equals or exceeds $15.00 per share ("Target Price Awards"). Shares vest over a two year period and are subject to other vesting provisions depending on when the attainment date occurs. No such awards were granted in 2014.
    
During the third quarter of 2014, EXCO's officers were granted 820,317 restricted share units which have a vesting percentage between 0% and 200% depending on EXCO's total shareholder return ("TSR") in comparison to an identified peer group. These units will vest on the third anniversary of the date of grant, subject to the achievement of certain criteria. Total compensation expense will be recognized over the vesting period using the straight-line method.
    
The grant date fair values of our market-based restricted share awards and restricted share units were determined using a Monte Carlo model which uses company-specific inputs to generate different stock price paths.

A summary of our market-based restricted share activity for the years ended December 31, 2014 and 2013 is as follows:
 
 
Target Price Awards
 
TSRs
 
 
Shares
 
Weighted average grant date fair value per share
 
Shares
 
Weighted average grant date fair value per share
 
 
 
 
 
Non-vested shares outstanding at December 31, 2012
 

 
$

 

 
$

Granted
 
736,000

 
6.36

 

 

Vested
 

 

 

 

Forfeited
 
(261,400
)
 
6.36

 

 

Non-vested shares outstanding at December 31, 2013
 
474,600

 
$
6.36

 

 
$

Granted
 

 

 
820,317

 
7.33

Vested
 

 

 

 

Forfeited
 
(73,200
)
 
6.36

 
(104,167
)
 
7.33

Non-vested shares outstanding at December 31, 2014
 
401,400

 
$
6.36

 
716,150

 
$
7.33



12.
Income taxes

The income tax provision attributable to our income (loss) before income taxes for the years ended December 31, 2014 , 2013 and 2012 , consisted of the following:



101


 
 
Year ended December 31,
(in thousands)
 
2014
 
2013
 
2012
Current:
 
 
 
 
 
 
Federal
 
$

 
$

 
$

State
 

 

 

Total current income tax (benefit)
 
$

 
$

 
$

 
 
 
 
 
 
 
Deferred:
 
 
 
 
 
 
Federal
 
$
45,797

 
$
25,626

 
$
(485,543
)
State
 
18,960

 
3,239

 
(59,406
)
Valuation allowance
 
(64,757
)
 
(28,865
)
 
544,949

Total deferred income tax (benefit)
 

 

 

Total income tax (benefit)
 
$

 
$

 
$

    
We have net operating loss carryforwards ("NOLs") for United States income tax purposes that have been generated from our operations. Our NOLs are scheduled to expire if not utilized between 2027 and 2034. NOLs and alternative minimum tax credits available for utilization as of December 31, 2014 were approximately $2.0 billion and $1.5 million , respectively. In addition, we generated a net capital loss of approximately $105.6 million during the year ended December 31, 2014 as a result of the sale of our interest in Compass.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax liabilities and assets are as follows:
(in thousands)
 
December 31, 2014
 
December 31, 2013
Current deferred tax assets (liabilities):
 
 
 
 
Derivative financial instruments
 
$
(38,519
)
 
$

Other
 
2,584

 
5,332

Valuation allowance
 

 
(5,332
)
Net current deferred tax assets (liabilities)
 
(35,935
)
 

Non-current deferred tax assets:
 
 
 
 
Net operating loss and AMT credits carryforwards
 
$
781,899

 
$
737,399

Capital loss carryforwards
 
40,356

 

Share-based compensation
 
14,856

 
16,060

Oil and natural gas properties, gathering assets, and equipment
 

 
47,491

Goodwill
 
5,419

 
9,812

Derivative financial instruments
 

 
2,102

Investment in partnerships
 
72,988

 
73,328

Other
 
84

 
85

Total non-current deferred tax assets
 
915,602

 
886,277

Valuation allowance
 
(826,852
)
 
(886,277
)
Total non-current deferred tax assets
 
88,750

 

Non-current deferred tax liabilities:
 
 
 
 
Oil and natural gas properties, gathering assets, and equipment
 
$
(51,961
)
 
$

Derivative financial instruments
 
(854
)
 

Total non-current deferred tax liabilities
 
(52,815
)
 

Net non-current deferred tax assets (liabilities)
 
$
35,935

 
$


The reversal of the temporary differences related to the net current deferred tax liability is expected to be offset by taxable losses generated in the same fiscal year as the reversal. If we do not generate taxable losses in the same fiscal year to offset the reversal of the temporary differences then we will utilize our NOLs to offset the taxable income.



102


A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the years ended December 31, 2014 , 2013 and 2012 is presented in the following table:
 
 
Year Ended December 31,
(in thousands)
 
2014
 
2013
 
2012
Federal income taxes (benefit) provision at statutory rate of 35%
 
$
42,234

 
$
7,772

 
$
(487,649
)
Increases (reductions) resulting from:
 
 
 
 
 
 
Goodwill
 

 
16,382

 

Adjustments to the valuation allowance
 
(64,757
)
 
(28,865
)
 
544,949

Non-deductible compensation
 
3,409

 
1,328

 
1,893

State taxes net of federal benefit
 
3,464

 
3,239

 
(59,406
)
State tax rate change
 
15,496

 

 

Other
 
154

 
144

 
213

Total income tax provision
 
$

 
$

 
$


During both 2014 and 2013, both federal and state income taxes were reduced to zero by a corresponding decrease to the valuation allowance previously recognized against net deferred tax assets. The net result was no income tax provision for both 2014 and 2013.

During 2012, our net loss was greatly impacted by the impairments of our proved oil and natural gas properties and the recognized valuation allowance almost completely offset the impairments. There were no material sales transactions during the year to impact taxable income. The net result was no income tax provision for 2012.
    
We adopted the provisions of ASC 740-10 on January 1, 2007. As a result of the implementation of ASC 740-10, the Company did not recognize any liabilities for unrecognized tax benefits. As of December 31, 2014 , 2013 and 2012 , the Company's policy is to recognize interest related to unrecognized tax benefits of interest expense and penalties in operating expenses. The Company has not accrued any interest or penalties relating to unrecognized tax benefits in the consolidated financial statements.
    
We file a corporate consolidated income tax return for U.S. federal income tax purposes and file income tax return in various states. With few exceptions, we are no longer subject to U.S. federal and state and local examinations by tax authorities for years before 2006. The Company was notified during the year ended December 31, 2013 that the corporate tax return for the year ended December 31, 2011 would be examined by the Internal Revenue Service. In addition, two pass-through entities in which the Company owns an interest will also be examined for the year ended December 31, 2010. During 2014 the Internal Revenue Service completed the exam on the corporate return and on one of the two pass-through entities. No changes were made to either the corporate or partnership return as originally filed as a result of the exams. We do not anticipate that the remaining tax exam on the pass-through entity will result in a material change to the tax return as originally filed.

13.
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 years ended December 31, 2014 , 2013 and 2012 these transactions included the following:
 
 
Year Ended December 31,
(in thousands)
 
2014
 
2013
 
2012
Advances to OPCO
 
$

 
$
28,378

 
$
76,729

Amounts received from OPCO
 
53,002

 
43,632

 
52,206




103


As of December 31, 2014 and 2013 , the amounts owed under the service agreements were as follows:
(in thousands)
 
December 31, 2014
 
December 31, 2013
Amounts due to EXCO (1)
 
$
2,799

 
$
2,283

Amounts due from EXCO (1)
 

 


(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 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 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 the 2022 Notes.

As discussed in "Note 15. Rights offering and other equity transactions", we entered into investment agreements and closed a related private placement of our common shares 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 of whom serve on EXCO's board of directors.

14.
Dividends
    
Total dividends paid to our shareholders in 2014 , 2013 and 2012 were $41.1 million , $43.2 million , and $34.4 million , respectively. On December 15, 2014, our board of directors suspended the cash dividend and did not approve a cash dividend for the fourth quarter of 2014.
    
Any future declaration of dividends, as well as the establishment of record and payment dates, will depend on our earnings, capital requirements, financial condition, prospects and other factors our board of directors may deem relevant.

15.
Rights Offering and other equity transactions

On December 19, 2013, the Company granted subscription rights to holders of common shares which entitled the holder to purchase 0.25 of a share of our common stock for each share of common stock owned by such holders. Each subscription right entitled the holder to a basic subscription right and an over-subscription privilege. The basic subscription right entitled the holder to purchase 0.25 of a share of the Company’s common shares at a subscription price equal to $5.00 per share of common stock. The over-subscription privilege entitled the holders who exercised their basic subscription rights in full (including in respect of subscription rights purchased from others) to purchase any or all shares of our common shares that other rights holders did not purchase through the purchase of their basic subscription rights at a subscription price equal to $5.00 per share of our common shares. The subscription rights expired if they were not exercised by January 9, 2014.
The Company entered into two investment agreements ("Investment Agreements") in connection with the Rights Offering, each dated as of December 17, 2013, one with certain affiliates of WL Ross and one with Hamblin Watsa pursuant to which, subject to the terms and conditions thereof, each of them has 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 subject to pro rata allocation among the subscription rights holders who have elected to exercise their over-subscription privilege.
The Rights Offering and related transactions under the Investment Agreements closed on January 17, 2014 which resulted in the issuance of 54,574,734 shares for proceeds of $272.9 million . We used the proceeds to pay indebtedness under the EXCO Resources Credit Agreement which is further discussed in "Note 6. Debt". 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.


104


Preferred Shares
We canceled all classes of our preferred shares in 2014. We have 10,000,000 preferred shares authorized with no preferred shares issued and outstanding. Our issued and outstanding shares of capital stock consist solely of common shares.

16.
Condensed consolidating financial statements
As of December 31, 2014 , the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement and the indenture governing the 2018 Notes and 2022 Notes. All of our non-guarantor subsidiaries were considered unrestricted subsidiaries under the indenture governing the 2018 Notes and 2022 Notes, with the exception of our equity investment in OPCO.     
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.


105


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2014
 (in thousands)
 
 Resources
 
 Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
 Eliminations
 
 Consolidated
 Assets
 
 
 
 
 
 
 
 
 
 
 Current assets:
 
 
 
 
 
 
 
 
 
 
 Cash and cash equivalents
 
$
86,837

 
$
(40,532
)
 
$

 
$

 
$
46,305

 Restricted cash
 

 
23,970

 

 

 
23,970

 Other current assets
 
110,145

 
150,346

 

 

 
260,491

         Total current assets
 
196,982

 
133,784

 

 

 
330,766

 Equity investments
 

 

 
55,985

 

 
55,985

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

 
276,025

 

 

 
276,025

Proved developed and undeveloped oil and natural gas properties
 
335,838

 
3,516,235

 

 

 
3,852,073

     Accumulated depletion
 
(330,771
)
 
(2,083,690
)
 

 

 
(2,414,461
)
     Oil and natural gas properties, net
 
5,067

 
1,708,570

 

 

 
1,713,637

 Gathering, office, field and other assets, net
 
1,269

 
23,375

 

 

 
24,644

 Investments in and advances to affiliates, net
 
1,746,931

 

 

 
(1,746,931
)
 

 Deferred financing costs, net
 
30,636

 

 

 

 
30,636

 Derivative financial instruments
 
2,138

 

 

 

 
2,138

 Goodwill
 
13,293

 
149,862

 

 

 
163,155

 Deferred income taxes
 
35,935

 

 

 

 
35,935

         Total assets
 
$
2,032,251

 
$
2,015,591

 
$
55,985

 
$
(1,746,931
)
 
$
2,356,896

 Liabilities and shareholders' equity
 
 
 
 
 
 
 
 
 
 
 Current liabilities
 
$
75,441

 
$
289,930

 
$

 
$

 
$
365,371

 Long-term debt
 
1,446,535

 

 

 

 
1,446,535

 Deferred income taxes
 

 

 

 

 

 Other long-term liabilities
 
271

 
34,715

 

 

 
34,986

 Payable to parent
 

 
2,058,683

 

 
(2,058,683
)
 

         Total shareholders' equity
 
510,004

 
(367,737
)
 
55,985

 
311,752

 
510,004

         Total liabilities and shareholders' equity
 
$
2,032,251

 
$
2,015,591

 
$
55,985

 
$
(1,746,931
)
 
$
2,356,896



106


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 assets, net
 
3,481

 
24,639

 
22,248

 

 
50,368

 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

         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

 
 
 
 
 
 
 
 
 
 
 


107


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the year ended December 31, 2014


(in thousands)
 
Resources
 
Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
3,649

 
$
614,889

 
$
41,731

 
$

 
$
660,269

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 
394

 
77,334

 
16,598

 

 
94,326

Gathering and transportation
 

 
97,784

 
3,790

 

 
101,574

Depletion, depreciation and amortization
 
3,174

 
244,761

 
15,634

 

 
263,569

Impairment of oil and natural gas properties
 

 

 

 

 

Accretion of discount on asset retirement obligations
 
16

 
2,107

 
567

 

 
2,690

General and administrative
 
(3,342
)
 
66,686

 
2,576

 

 
65,920

Other operating items
 
(134
)
 
5,459

 
(10
)
 

 
5,315

    Total costs and expenses
 
108

 
494,131

 
39,155

 

 
533,394

Operating income
 
3,541

 
120,758

 
2,576

 

 
126,875

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(92,049
)
 

 
(2,235
)
 

 
(94,284
)
Gain on derivative financial instruments
 
87,565

 

 
100

 

 
87,665

Other income
 
226

 

 
15

 

 
241

Equity income
 

 

 
172

 

 
172

Net earnings from consolidated subsidiaries
 
121,386

 

 

 
(121,386
)
 

    Total other income (expense)
 
117,128

 

 
(1,948
)
 
(121,386
)
 
(6,206
)
Income before income taxes
 
120,669

 
120,758

 
628

 
(121,386
)
 
120,669

Income tax expense
 

 

 

 

 

Net income
 
$
120,669

 
$
120,758

 
$
628

 
$
(121,386
)
 
$
120,669




108


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the year ended December 31, 2013
(in thousands)
 
Resources
 
Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
9,136

 
$
582,158

 
$
43,015

 
$

 
$
634,309

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 
2,440

 
63,716

 
17,092

 

 
83,248

Gathering and transportation
 

 
97,166

 
3,479

 

 
100,645

Depletion, depreciation and amortization
 
5,917

 
225,499

 
14,359

 

 
245,775

Impairment of oil and natural gas properties
 

 
108,546

 

 

 
108,546

Accretion of discount on asset retirement obligations
 
63

 
1,881

 
570

 

 
2,514

General and administrative
 
23,125

 
66,558

 
2,195

 

 
91,878

Gain on divestitures and other operating items
 
(25,950
)
 
(151,549
)
 
(19
)
 

 
(177,518
)
    Total costs and expenses
 
5,595

 
411,817

 
37,676

 

 
455,088

Operating income (loss)
 
3,541

 
170,341

 
5,339

 

 
179,221

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(99,815
)
 

 
(2,774
)
 

 
(102,589
)
Gain (loss) on derivative financial instruments
 
1,439

 
(177
)
 
(1,582
)
 

 
(320
)
Other income (loss)
 
(1,068
)
 
229

 
11

 

 
(828
)
Equity loss
 

 

 
(53,280
)
 

 
(53,280
)
Net earnings from consolidated subsidiaries
 
118,107

 

 

 
(118,107
)
 

    Total other income (expense)
 
18,663

 
52

 
(57,625
)
 
(118,107
)
 
(157,017
)
Income (loss) before income taxes
 
22,204

 
170,393

 
(52,286
)
 
(118,107
)
 
22,204

Income tax expense
 

 

 

 

 

Net income (loss)
 
$
22,204

 
$
170,393

 
$
(52,286
)
 
$
(118,107
)
 
$
22,204





109


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the year ended December 31, 2012

(in thousands)
 
Resources
 
Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
78,649

 
$
467,960

 
$

 
$

 
$
546,609

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas production
 
19,820

 
84,790

 

 

 
104,610

Gathering and transportation
 

 
102,875

 

 

 
102,875

Depletion, depreciation and amortization
 
7,767

 
295,389

 

 

 
303,156

Impairment of oil and natural gas properties
 

 
1,346,749

 

 

 
1,346,749

Accretion of discount on asset retirement obligations
 
526

 
3,361

 

 

 
3,887

General and administrative
 
14,394

 
69,424

 

 

 
83,818

Other operating items
 
(194
)
 
17,223

 

 

 
17,029

    Total costs and expenses
 
42,313

 
1,919,811

 

 

 
1,962,124

Operating income (loss)
 
36,336

 
(1,451,851
)
 

 

 
(1,415,515
)
Other income:
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(73,489
)
 
(3
)
 

 

 
(73,492
)
Gain on derivative financial instruments
 
62,812

 
3,321

 

 

 
66,133

Other income
 
238

 
731

 

 

 
969

Equity income
 

 

 
28,620

 

 
28,620

Net loss from consolidated subsidiaries
 
(1,419,182
)
 

 

 
1,419,182

 

    Total other income (expense)
 
(1,429,621
)
 
4,049

 
28,620

 
1,419,182

 
22,230

Income (loss) before income taxes
 
(1,393,285
)
 
(1,447,802
)
 
28,620

 
1,419,182

 
(1,393,285
)
Income tax expense
 

 

 

 

 

Net income (loss)
 
$
(1,393,285
)
 
$
(1,447,802
)
 
$
28,620

 
$
1,419,182

 
$
(1,393,285
)


110


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended December 31, 2014
 (in thousands)
 
 Resources
 
 Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
 Eliminations
 
 Consolidated
Operating Activities:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
(84,067
)
 
$
428,029

 
$
18,131

 
$

 
$
362,093

Investing Activities:
 
 
 
 
 
 
 
 
 
 
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
 
(2,531
)
 
(395,974
)
 
(4,061
)
 

 
(402,566
)
Restricted cash
 

 
(3,400
)
 

 

 
(3,400
)
Equity method investments
 

 
1,749

 

 

 
1,749

Proceeds from disposition of property and equipment
 
99,612

 
95,594

 
(7,551
)
 

 
187,655

Distributions received from Compass
 
5,856

 

 

 
(5,856
)
 

Net changes in advances to joint ventures
 

 
(5,026
)
 

 

 
(5,026
)
Advances/investments with affiliates
 
125,612

 
(125,612
)
 

 

 

Net cash provided by (used in) investing activities
 
228,549

 
(432,669
)
 
(11,612
)
 
(5,856
)
 
(221,588
)
Financing Activities:
 
 
 
 
 
 
 
 
 
 
Borrowings under credit agreements
 
100,000

 

 

 

 
100,000

Repayments under credit agreements
 
(959,874
)
 

 
(5,096
)
 

 
(964,970
)
Proceeds received from issuance of 2022 Notes
 
500,000

 

 

 

 
500,000

Proceeds from issuance of common shares, net
 
271,773

 

 

 

 
271,773

Payment of common share dividends
 
(41,060
)
 

 

 

 
(41,060
)
Compass cash distribution
 

 

 
(5,856
)
 
5,856

 

Deferred financing costs and other
 
(10,188
)
 

 
(102
)
 

 
(10,290
)
Payments of common shares repurchased
 
(136
)
 

 

 

 
(136
)
Net cash used in financing activities
 
(139,485
)
 

 
(11,054
)
 
5,856

 
(144,683
)
Net increase (decrease) in cash
 
4,997

 
(4,640
)
 
(4,535
)
 

 
(4,178
)
Cash at beginning of period
 
81,840

 
(35,892
)
 
4,535

 

 
50,483

Cash at end of period
 
$
86,837

 
$
(40,532
)
 
$

 
$

 
$
46,305



111


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended December 31, 2013
 (in thousands)
 
 Resources
 
 Guarantor Subsidiaries
 
 Non-Guarantor Subsidiaries
 
 Eliminations
 
 Consolidated
Operating Activities:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
(32,678
)
 
$
365,770

 
$
17,542

 
$

 
$
350,634

Investing Activities:
 
 
 
 
 
 
 
 
 
 
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
 
(15,767
)
 
(1,242,667
)
 
(38,818
)
 

 
(1,297,252
)
Restricted cash
 

 
49,515

 

 

 
49,515

Equity method investments
 

 
236,289

 

 

 
236,289

Proceeds from disposition of property and equipment
 
244,500

 
505,128

 

 

 
749,628

Distributions from Compass
 
3,825

 

 

 
(3,825
)
 

Net changes in advances to joint ventures
 

 
10,645

 

 

 
10,645

Advances/investments with affiliates
 
(59,575
)
 
59,575

 

 

 

Other
 
(1,303
)
 

 

 

 
(1,303
)
Net cash provided by (used in) investing activities
 
171,680

 
(381,515
)
 
(38,818
)
 
(3,825
)
 
(252,478
)
Financing Activities:
 
 
 
 
 
 
 
 
 
 
Borrowings under credit agreements
 
967,766

 

 
36,757

 

 
1,004,523

Repayments under credit agreements
 
(1,015,900
)
 

 
(6,885
)
 

 
(1,022,785
)
Proceeds from issuance of common shares, net
 
1,712

 

 

 

 
1,712

Payment of common share dividends
 
(43,214
)
 

 

 

 
(43,214
)
Compass cash distribution
 

 

 
(3,825
)
 
3,825

 

Deferred financing costs and other
 
(33,317
)
 

 
(236
)
 

 
(33,553
)
Net cash provided by (used in) financing activities
 
(122,953
)
 

 
25,811

 
3,825

 
(93,317
)
Net increase (decrease) in cash
 
16,049

 
(15,745
)
 
4,535

 

 
4,839

Cash at beginning of period
 
65,791

 
(20,147
)
 

 

 
45,644

Cash at end of period
 
$
81,840

 
$
(35,892
)
 
$
4,535

 
$

 
$
50,483



112


EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended December 31, 2012
 (in thousands)
 
 Resources
 
 Guarantor Subsidiaries
 
 Non-guarantor subsidiaries
 
 Eliminations
 
 Consolidated
Operating Activities:
 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
 
$
182,143

 
$
332,643

 
$

 
$

 
$
514,786

Investing Activities:
 
 
 
 
 
 
 
 
 
 
Additions to oil and natural gas properties, gathering assets and equipment
 
(77,006
)
 
(459,917
)
 

 

 
(536,923
)
Restricted cash
 

 
85,840

 

 

 
85,840

Equity method investments
 

 
(14,907
)
 

 

 
(14,907
)
Proceeds from disposition of property and equipment
 
15,161

 
22,884

 

 

 
38,045

Net changes in advances to joint ventures
 

 
851

 

 

 
851

Advances/investments with affiliates
 
(59,126
)
 
59,126

 

 

 

Net cash used in investing activities
 
(120,971
)
 
(306,123
)
 

 

 
(427,094
)
Financing Activities:
 
 
 
 
 
 
 
 
 
 
Borrowings under the credit agreements
 
53,000

 

 

 

 
53,000

Repayments under the credit agreements
 
(93,000
)
 

 

 

 
(93,000
)
Proceeds from issuance of common shares, net
 
1,968

 

 

 

 
1,968

Payment of common share dividends
 
(34,358
)
 

 

 

 
(34,358
)
Deferred financing costs and other
 
(1,655
)
 

 

 

 
(1,655
)
Net cash used in financing activities
 
(74,045
)
 

 

 

 
(74,045
)
Net increase (decrease) in cash
 
(12,873
)
 
26,520

 

 

 
13,647

Cash at beginning of period
 
78,664

 
(46,667
)
 

 

 
31,997

Cash at end of period
 
$
65,791

 
$
(20,147
)
 
$

 
$

 
$
45,644





113


17.
Quarterly financial data (unaudited)
    
The following are summarized quarterly financial data for the years ended December 31, 2014 and 2013 :
 
 
 
Quarter
(in thousands, except per share amounts)
 
1st
 
2nd
 
3rd
 
4th
2014
 
 
 
 
 
 
 
 
Oil and natural gas revenues
 
$
198,472

 
$
182,966

 
$
151,042

 
$
127,789

Operating income (loss)
 
57,423

 
43,312

 
22,799

 
3,341

Net income (loss)
 
$
(4,606
)
 
$
2,293

 
$
41,569

 
$
81,413

Basic earnings (loss) per share:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
(0.02
)
 
$
0.01

 
$
0.15

 
$
0.30

Weighted average shares
 
260,716

 
270,492

 
270,631

 
271,053

Diluted earnings (loss) per share:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
(0.02
)
 
$
0.01

 
$
0.15

 
$
0.30

Weighted average shares
 
260,716

 
271,226

 
272,066

 
271,053

 
 
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
 
 
Oil and natural gas revenues
 
$
138,223

 
$
150,332

 
$
165,314

 
$
180,440

Operating income (loss) (1)
 
209,075

 
33,883

 
15,594

 
(79,331
)
Net income (loss) (2) (3)
 
$
158,120

 
$
85,598

 
$
(98,651
)
 
$
(122,863
)
Basic earnings (loss) per share:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
0.74

 
$
0.40

 
$
(0.46
)
 
$
(0.57
)
Weighted average shares
 
214,784

 
214,788

 
215,056

 
215,410

Diluted earnings (loss) per share:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
0.74

 
$
0.40

 
$
(0.46
)
 
$
(0.57
)
Weighted average shares
 
214,861

 
216,023

 
215,056

 
215,410


(1)
Operating income (loss) for the first quarter and the fourth quarter of 2013 includes $10.7 million and $97.8 million , respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion.
(2)
Net income (loss) for the third quarter of 2013 includes a $91.5 million impairment to our investment in TGGT as a result of the carrying value exceeding the fair value. The impairment was reduced by $4.7 million in the fourth quarter of 2013 to $86.8 million as a result of final closing adjustments, fees and transaction expenses related to the sale of our equity investment in TGGT. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.
(3)
Net income (loss) for the first quarter of 2013 includes a gain of $187.0 million from our contribution of oil and natural gas properties to Compass. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.

18.
Supplemental information relating to oil and natural gas producing activities (unaudited)
    
The following supplemental information relating to our oil and natural gas producing activities for the years ended December 31, 2014 , 2013 and 2012 is presented in accordance with ASC 932, Extractive Activities, Oil and Gas.



114


Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities:
(in thousands, except per unit amounts)
  
Amount
2014:
 
 
Proved property acquisition costs
 
$
10,562

Unproved property acquisition costs
 

Total property acquisition costs
 
10,562

Development
 
354,199

Exploration costs (1)
 
5,906

Lease acquisitions and other
 
9,681

Capitalized asset retirement costs
 
576

Depletion per Boe
 
$
11.42

Depletion per Mcfe
 
$
1.90

2013:
  
 
Proved property acquisition costs
  
$
754,370

Unproved property acquisition costs
  
232,020

Total property acquisition costs (2)
  
986,390

Development
  
231,447

Exploration costs (3)
  
38,579

Lease acquisitions and other
  
14,835

Capitalized asset retirement costs
  
514

Depletion per Boe
  
$
8.82

Depletion per Mcfe
  
$
1.47

2012:
  
 
Proved property acquisition costs
  
$

Unproved property acquisition costs
  
3,349

Total property acquisition costs
  
3,349

Development
  
346,017

Exploration costs (4)
  
57,325

Lease acquisitions and other (5)
  
44,546

Capitalized asset retirement costs
  
971

Depletion per Boe
  
$
9.11

Depletion per Mcfe
  
$
1.52


(1)
Exploration costs in 2014 include $5.9 million in the Bossier shale in North Louisiana.
(2)
Acquisition costs in 2013 include the acquisition of properties in the Haynesville and Eagle Ford shales and our proportionate share of Compass's acquisition of shallow Cotton Valley assets.
(3)
Exploration costs in 2013 include $29.2 million in the Eagle Ford shale and $9.4 million in the Marcellus shale.
(4)
Exploration costs in 2012 include $40.1 million in the Haynesville shale $17.2 million in the Marcellus shale.
(5)
Lease acquisition costs in 2012 are net of acreage reimbursements from BG Group totaling $2.1 million .

We retain independent engineering firms to prepare or audit annual year-end estimates of our future net recoverable oil and natural gas reserves. The estimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves that we may recover through existing wells. Proved Undeveloped Reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations. All of our reserves are located onshore in the continental United States of America.
    
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of


115


our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.
 
 
  
Oil
(Mbbls)
 
Natural
Gas
(Mmcf)
 
Natural Gas Liquids (Mbbls)
 
Mmcfe (11)
December 31, 2011
  
6,354


1,291,464



 
1,329,588

Purchase of reserves in place
  





 

Discoveries and extensions (1)
  
492


96,615


424

 
102,111

Revisions of previous estimates:
  
 

 
 

 
 
 
 

Changes in price
  
(110
)

(466,238
)


 
(466,898
)
Other factors (2)
  
(463
)

199,784


6,724

 
237,350

Sales of reserves in place
  


(2,837
)


 
(2,837
)
Production
  
(703
)

(182,656
)

(509
)
 
(189,928
)
December 31, 2012
  
5,570


936,132


6,639

 
1,009,386

Purchase of reserves in place (3)
  
16,022


290,933


2,201

 
400,271

Discoveries and extensions (4)
  
5,960


46,834


513

 
85,672

Revisions of previous estimates:
  
 

 
 

 
 
 
 

Changes in price
  
457


272,614


686

 
279,472

Other factors (5)
  
(3,219
)

(106,695
)

(741
)
 
(130,455
)
Sales of reserves in place (6)
  
(8,224
)

(270,018
)

(6,472
)
 
(358,194
)
Production
  
(1,188
)

(153,321
)

(243
)
 
(161,907
)
December 31, 2013
  
15,378


1,016,479


2,583

 
1,124,245

Purchase of reserves in place (7)
 

 
7,316

 

 
7,316

Discoveries and extensions (8)
 
4,164

 
69,902

 
107

 
95,528

Revisions of previous estimates:
 
 
 
 
 
 
 
 
Changes in price
 
45

 
167,302

 
127

 
168,334

Other factors (9)
 
1,737

 
120,850

 
(8
)
 
131,224

Sales of reserves in place (10)
  
(1,401
)

(105,841
)

(2,144
)
 
(127,111
)
Production
  
(2,236
)
 
(120,980
)
 
(224
)
 
(135,740
)
December 31, 2014
 
17,687

 
1,155,028

 
441

 
1,263,796

Estimated Quantities of Proved Developed and Proved Undeveloped Reserves
 
  
Oil
(Mbbls)
 
Natural
Gas
(Mmcf)
  
Natural Gas Liquids (Mbbls)
 
Mmcfe
Proved developed:
  
 
 
 
  
 
 
 
December 31, 2014
  
14,429

 
502,314

 
387

 
591,210

December 31, 2013
  
11,274

 
657,116

  
2,088

 
737,291

December 31, 2012
  
4,371

 
917,326

  
4,784

 
972,256

Proved undeveloped:
  
 
 
 
  
 
 
 
December 31, 2014
  
3,258

 
652,714

 
54

 
672,586

December 31, 2013
  
4,104

 
359,363

  
495

 
386,954

December 31, 2012
  
1,199

 
18,806

  
1,855

 
37,130


(1)
New discoveries and extensions in 2012 include 25,626 Mmcfe in East Texas/North Louisiana, primarily in the Haynesville shale, 59,455 Mmcfe in the Marcellus shale and 17,027 Mmcfe in the Permian Basin.
(2)
Total revisions due to Other factors in 2012 include approximately 8,736 Mmcfe of Proved Undeveloped Reserves that were reclassified to unproved reserves as a result of a slower development schedule due to depressed natural gas prices,


116


which extended their scheduled development beyond a five-year development horizon. The change also includes a positive revision of 246,451 Mmcfe resulting from unproved performance and cost reductions.
(3)
Purchases of reserves in place include 115,718 Mmcfe in the Eagle Ford shale, 259,991 Mmcfe in the Haynesville shale, and 24,558 Mmcfe for our proportionate share of Compass's acquisition of shallow Cotton Valley assets in East Texas/North Louisiana.
(4)
New discoveries and extensions in 2013 include 36,501 Mmcfe in the Eagle Ford shale, 33,591 Mmcfe in the Marcellus shale, 10,211 Mmcfe in the Haynesville shale, 3,881 Mmcfe for conventional properties held by Compass in the Permian Basin, and 1,486 Mmcfe for shale properties in the Permian Basin.
(5)
Total revisions due to Other factors were downward revisions primarily in the Haynesville shale as a result of operational matters including scaling, liquid loading due to high-line pressure and the impact of drainage on new wells drilled directly offset to the unit wells.
(6)
Sales of reserves in place in 2013 include 327,608 Mmcfe as a result of our contribution of properties to Compass and 30,582 Mmcfe from the sale of undeveloped properties in the Eagle Ford in connection with the Participation Agreement.
(7)
Purchases of reserves in place in 2014 consist primarily of our acquisition of certain proved developed producing properties in the Shelby area of East Texas.
(8)
New discoveries and extensions in 2014 included 48,698 Mmcfe in the Haynesville shale, 26,148 Mmcfe in the Eagle Ford Shale and 19,664 in the Bossier shale. The discoveries and extensions within the Haynesville and Bossier shales primarily related to our development of properties within the Shelby area of East Texas.
(9)
Total revisions due to Other factors include upward revisions of approximately 67,095 Mmcfe in the Shelby area, approximately 45,878 Mmcfe in the Appalachia region, and approximately 5,836 Mmcfe in the Holly area. The upward revisions were primarily due to improved well performance resulting from enhanced well designs and completion techniques.
(10)
Sales of reserves in place in 2014 consist primarily of the sale of our entire interest in Compass.
(11)
The above reserves do not include our equity interest in OPCO, which was not significant in any period presented.
Standardized measure of discounted future net cash flows
    
We have summarized the Standardized Measure related to our proved oil, natural gas and NGL reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on prices as prescribed by the SEC, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, the information presented below should not be viewed as an estimate of the fair value of our oil and natural gas properties, nor should it be indicative of any trends.


117


(in thousands)
  
Amount
Year ended December 31, 2014:
 
 
Future cash inflows
 
$
6,097,207

Future production costs
 
2,094,796

Future development costs
 
1,124,873

Future income taxes
 

Future net cash flows
 
2,877,538

Discount of future net cash flows at 10% per annum
 
1,334,951

Standardized measure of discounted future net cash flows
 
$
1,542,587

Year ended December 31, 2013:
  
 

Future cash inflows
  
$
5,176,030

Future production costs
  
2,207,230

Future development costs
  
904,116

Future income taxes
  

Future net cash flows
  
2,064,684

Discount of future net cash flows at 10% per annum
  
812,411

Standardized measure of discounted future net cash flows
  
$
1,252,273

Year ended December 31, 2012:
  
 

Future cash inflows
  
$
3,187,480

Future production costs
  
1,824,702

Future development costs
  
266,726

Future income taxes
  

Future net cash flows
  
1,096,052

Discount of future net cash flows at 10% per annum
  
399,905

Standardized measure of discounted future net cash flows
  
$
696,147

    
During recent years, prices paid for oil and natural gas have fluctuated significantly. The reference prices at December 31, 2014 , 2013 and 2012 used in the above table, were $94.99 , $96.78 and $94.71 per Bbl of oil, respectively, and $4.35 , $3.67 and $2.76 per Mmbtu of natural gas, respectively. The reference price at December 31, 2014, 2013 and 2012 used in the above table was $33.03 $39.92 and $46.57 per Bbl for NGLs, respectively. Each of the reference prices for oil and natural gas were adjusted for quality factors and regional differentials. These prices reflect the SEC rules requiring the use of simple average of the first day of the month price for the previous 12 month period for natural gas at Henry Hub, West Texas Intermediate crude oil at Cushing, Oklahoma, and the trailing 12 month average of realized prices for NGLs.
 














118



The following are the principal sources of change in the Standardized Measure:
 
(in thousands)
  
Amount
Year ended December 31, 2014:
 
 
Sales and transfers of oil and natural gas produced
 
$
(464,369
)
Net changes in prices and production costs
 
279,944

Extensions and discoveries, net of future development and production costs
 
196,796

Development costs during the period
 
189,155

Changes in estimated future development costs
 
(254,737
)
Revisions of previous quantity estimates
 
412,296

Sales of reserves in place
 
(148,226
)
Purchase of reserves in place
 
13,507

Accretion of discount before income taxes
 
125,227

Changes in timing and other
 
(59,279
)
Net change in income taxes
 

Net change
 
$
290,314

Year ended December 31, 2013:
  
 

Sales and transfers of oil and natural gas produced
  
$
(450,415
)
Net changes in prices and production costs
  
582,725

Extensions and discoveries, net of future development and production costs
  
197,223

Development costs during the period
  
55,196

Changes in estimated future development costs
  
(251,484
)
Revisions of previous quantity estimates
  
98,283

Sales of reserves in place
  
(315,758
)
Purchase of reserves in place
  
604,366

Accretion of discount before income taxes
  
69,615

Changes in timing and other
  
(33,625
)
Net change in income taxes
  

Net change
  
$
556,126

Year ended December 31, 2012:
  
 

Sales and transfers of oil and natural gas produced
  
$
(339,125
)
Net changes in prices and production costs
  
(1,258,493
)
Extensions and discoveries, net of future development and production costs
  
90,633

Development costs during the period
  
204,929

Changes in estimated future development costs
  
404,414

Revisions of previous quantity estimates
  
(336,142
)
Sales of reserves in place
  
(3,604
)
Purchase of reserves in place
  

Accretion of discount before income taxes
  
165,755

Changes in timing and other
  
94,129

Net change in income taxes
  
247,189

Net change
  
$
(730,315
)



119


Costs not subject to amortization
    
The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within one to seven years.  
(in thousands)
  
Total
 
2014
 
2013
 
2012
 
2011 and
prior
Property acquisition costs
  
$
228,553


$
9,737


$
71,524


$
3,038


$
144,254

Exploration and development
  
16,366


10,797


73


524


4,972

Capitalized interest
  
31,106


11,871


8,737


6,796


3,702

Total
  
$
276,025


$
32,405


$
80,334


$
10,358


$
152,928


Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A.     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 December 31, 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.

Management's report on internal control over financial reporting.     EXCO's management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) or 15d-15(f) of the Exchange Act). Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2014 , using criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of an internal control system in future periods can change with conditions. Management's annual report of internal control over financial reporting and the audit report on our internal control over financial reporting of our independent registered public accounting firm, KPMG LLP, are included in Item 8 of this Annual Report on Form 10-K and are incorporated by reference herein.

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 December 31, 2014 that have materially affected, or are reasonably likely to materially affect, EXCO's internal control over financial reporting.

Item 9B.    Other Information
    
None.


120


PART III
 
Item 10.    Directors, Executive Officers and Corporate Governance
    
The information required in response to this Item 10 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

Item 11.     Executive Compensation
    
The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
    
The information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
 
Item 13.    Certain Relationships and Related Transactions and Director Independence
    
The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
 
Item 14.     Principal Accountant Fees and Services
    
The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.


PART IV


Item 15.     Exhibits and Financial Statement Schedules
(a)(1)    See Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.
(a)(2)    None.
(a)(3)     See "Index to Exhibits" for a description of our exhibits.
(b)    See "Index to Exhibits" for a description of our exhibits.
(c)    None.


121


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.

        
Date:
February 25, 2015
 
EXCO RESOURCES, INC.
 
 
 
(Registrant)
            


122


            
 
 
EXCO RESOURCES, INC.
 
 
(Registrant)
 
 
 
 
Date:
February 25, 2015
 
/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
 
 
 
 
 
 
 
/s/ Jeffrey D. Benjamin
 
 
 
Jeffrey D. Benjamin
 
 
 
Non-Executive Chairman
 
 
 
 
 
 
 
/s/ B. James Ford
 
 
 
B. James Ford
 
 
 
Director
 
 
 
 
 
 
 
/s/ Samuel A. Mitchell
 
 
 
Samuel A. Mitchell
 
 
 
Director
 
 
 
 
 
 
 
/s/ Boone Pickens
 
 
 
Boone Pickens
 
 
 
Director
 
 
 
 
 
 
 
/s/ Wilbur L. Ross, Jr.
 
 
 
Wilbur L. Ross, Jr.
 
 
 
Director
 
 
 
 
 
 
 
/s/ Jeffrey S. Serota
 
 
 
Jeffrey S. Serota
 
 
 
Director
 
 
 
 
 
 
 
/s/ Robert L. Stillwell
 
 
 
Robert L. Stillwell
 
 
 
Director


123


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
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.
4.5
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.
4.6
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.        


124


4.5
First Amended and Restated Registration Rights Agreement dated 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-l (File No. 333-129935), filed on January 6, 2006 and incorporated by reference herein.
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 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 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.        
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.*        
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 on 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.*        


125


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
Amendment to Joint Development Agreement, dated October 14, 2014, by and among BG US Production Company, LLC and EXCO Operating Company, LP, filed herewith.
10.18
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.
10.19
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.
10.20
Amendment to Joint Development Agreement, dated October 14, 2014, 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 herewith.
10.21
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.
10.22
Amendment to Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated October 14, 2014, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed herewith.
10.23
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.
10.24
Amendment to Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC (n/k/a EXCO Appalachia Midstream, LLC), dated October 14, 2014, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Appalachia Midstream, LLC, filed herewith.


126


10.25
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.
10.26
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.        
10.27
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.        
10.28
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.        
10.29
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.        
10.30
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.*
10.31
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.
10.32
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 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.
10.33
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.
10.34
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.
10.35
Fourth Amendment to Amended and Restated Credit Agreement, dated as of February 6, 2015, 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 February 6, 2015 and filed on February 12, 2015 and incorporated by reference herein.
10.36
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.
10.37
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.


127


10.38
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.        
10.39
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.        
10.40
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.        
10.41
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.
10.42
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.
10.43
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.
10.44
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.*
10.45
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.*
10.46
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.*
10.47
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.*
10.48
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.
10.49
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.*
10.50
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.*
14.1
Code of Ethics for the Chief Executive Officer and Senior Financial Officers, filed as an Exhibit to EXCO's Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.


128


14.2
Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO's Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
14.3
Amendment No. 1 to EXCO Resources, Inc. Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated November 8, 2006 and filed on November 9, 2006 and incorporated by reference herein.
21.1
Subsidiaries of registrant, filed herewith.
23.1
Consent of KPMG LLP, filed herewith.
23.2
Consent of Lee Keeling and Associates, Inc., filed herewith.
23.3
Consent of Netherland, Sewell & Associates, Inc., filed herewith.
23.4
Consent of Ryder Scott Company, L.P., filed herewith.
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.
99.1
2014 Report of Lee Keeling and Associates, Inc., filed herewith.
99.2
2014 Report of Netherland, Sewell & Associates, Inc., filed herewith.
99.3
2014 Report of Ryder Scott Company, L.P., filed herewith.
99.4
2014 Report of Lee Keeling and Associates, Inc. (OK) 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.



129
Exhibit 10.17

Execution Version

AMENDMENT TO THE JOINT DEVELOPMENT AGREEMENT
(EAST TEXAS/NORTH LOUISIANA)
This Amendment to the Joint Development Agreement (the “ Amendment ”) is entered into on October 14, 2014 (the “ Execution Date ”) between BG US Production Company, LLC, a Delaware limited liability company (“ BG ”), and EXCO Operating Company, LP, a Delaware limited partnership (“ EOC ”). BG and EOC are referred to herein collectively as the “ Parties ” and each individually as “ Party .”
RECITALS
WHEREAS, the Parties and EXCO Production Company, LP (which entity merged into EOC and terminated its separate existence) entered into that certain Joint Development Agreement dated August 14, 2009, which covers the joint development of certain oil and gas assets, as amended by amendment dated May 19, 2010, by amendment dated February 1, 2011, and by amendment dated February 14, 2013 (as so amended, the “ JDA ”); and
WHEREAS, the Parties desire to amend the JDA in accordance with the provisions of this Amendment;
NOW, THEREFORE, in consideration of the mutual promises contained in this Amendment and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:
1.
Definitions and References. Capitalized terms used in this Amendment and not otherwise defined herein have the meanings given such terms in the JDA. Sections, Articles, Appendices, Exhibits, Schedules and subsections referred to herein refer to such Sections, Articles, Appendices, Exhibits, Schedules and subsections of the JDA unless the context expressly states otherwise.
2.
JDA Amendment . The JDA is hereby amended as follows:
(a)
Section 3.5(b)(iii) shall be deleted in its entirety and replaced with the following:
“(iii)
solely with respect to those After Acquired Units for which EXCO or any Affiliate of EXCO serves as Party Operator under the relevant Joint Development Operating Agreement, upon a change in Control of the ultimate parent company of EXCO (but excluding a change in Control resulting from a management-led buyout of the public share ownership of such Person and the conversion of such Person to a privately-held Person). Party Operator will be required to resign with respect to operatorship of After Acquired Units within ten (10) days from the election of BG to acquire operatorship or to nominate a third party to serve as operator, effective as of the date BG or such third party actually acquires or assumes operatorship. BG’s election to acquire operatorship or to nominate a third party to serve as operator of After

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Acquired Units must be made within six (6) months following the applicable change in Control, with operatorship to transfer on a date elected by BG no later than twelve (12) months following BG’s election (i.e., within a total maximum time period of eighteen (18) months following the applicable change in Control). Party Operator shall support BG or its nominee in the election of the new Party Operator following Party Operator’s resignation.”
(b)
Section 3.6(c) shall be amended by deleting such section in its entirety and replacing it with the following:
“(c)
Joint Development Operator may be removed under the following circumstances:
(i)
by the affirmative vote of the Development Parties, other than Joint Development Operator and its Affiliates, holding a majority of the Participating Interest held by such Development Parties: (A) if there is a Change in Control of Joint Development Operator, provided that such vote is taken by the latter of (I) ninety (90) days after such Change in Control, or (II) ninety (90) days following the delivery of notice to such Development Parties of such Change in Control, such notice to be delivered only after the Change in Control has occurred; or (B) for good cause, provided that in the case of removal for good cause, such vote shall not be deemed effective until a written notice has been delivered to Joint Development Operator by another Party detailing the alleged default and Joint Development Operator has failed to cure the default within thirty (30) days from its receipt of the notice or, if the default concerns an operation then being conducted, within forty-eight (48) hours of its receipt of the notice; or
(ii)
by the affirmative vote of the Development Parties holding a majority of the Participating Interest in the event that Joint Development Operator’s and its Affiliates’ aggregate Participating Interest falls below twelve and a half percent (12.5%), provided that such vote is taken by the latter of (A) ninety (90) days after the decrease in the Participating Interest held by such Joint Development Operator and its Affiliates’ past such threshold has occurred or (B) ninety (90) days following the delivery of notice to such Development Parties of such decrease past such threshold, such notice to be delivered only after such decrease past such threshold has occurred.
For purposes hereof, “good cause” shall mean not only gross negligence and willful misconduct, but also the material breach of or inability to meet the standards of operation contained in Section 3.3, or a material failure or inability of a Party Operator to perform its obligations under the relevant Joint Development Operating Agreement. As used herein, “gross negligence” and “willful misconduct” shall include material unlawful acts committed by an operator of which such operator had actual knowledge

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at the time in question. Notwithstanding anything to the contrary herein, (I) if there is a dispute as to whether a condition resulting in good cause to remove a Party Operator has occurred, or whether such condition has been cured, such Party Operator shall continue to serve and discharge its duties in such capacity until the dispute has been resolved in accordance with Section 13.2, and (II) a change of a corporate name or structure of a Party Operator or Transfer of a Party Operator’s interest to another direct or indirect Wholly-Owned Affiliate of the same ultimate parent company shall not be the basis for removal of such Party Operator.

During the term of this Agreement, for avoidance of doubt, as between the Parties, the provisions of this Section 3.5(b) and Section 3.5(c) shall be in lieu of any provisions in any Joint Development Operating Agreement for the removal or resignation of the operator thereunder.”
(c)
Section 3.8 shall be deleted in its entirety and replaced with the following:
Secondees. Notwithstanding the terms of any Applicable Operating Agreement to the contrary, BG shall have the right to place Secondees within the organization of EXCO and/or its Affiliates while any such Persons are serving as Joint Development Operator or Party Operator hereunder, all as set forth in Exhibit “C” attached to the Appalachia LLC Agreement and subject to the terms of such agreement. Notwithstanding anything in the Appalachia LLC Agreement to the contrary, the terms of (i) Section 2.11(g), Section 2.11(h) and Section 2.11(i) of the Appalachia LLC Agreement, (ii) Exhibit “C” attached to the Appalachia LLC Agreement, (iii) the Secondment Agreements (as defined in the Appalachia LLC Agreement), and (iv) any defined terms used in the foregoing Sections or Exhibit “C” of the Appalachia LLC Agreement (A) shall survive the dissolution of EXCO Resources (PA), LLC and the termination of the Appalachia LLC Agreement and (B) shall continue to apply with respect to EXCO and BG, regardless of whether BG possesses any Percentage Interest (as defined in the Appalachia LLC Agreement), in each case, for so long as EXCO and/or its Affiliates are serving as Joint Development Operator or Party Operator hereunder.”
(d)
Section 3.10(a) shall be amended by:
(1) changing the Section references of Sections 3.10(a)(xiii) and 3.10(a)(xiv) to Sections 3.10(a)(xix) and 3.10(xx), respectively, and adding the phrase “without being limited by the duplication, specificity or limitations of any other items listed in this Section 3.10(a),” at the beginning of new Section 3.10(a)(xix),
(2) adding the following Sections 3.10(a)(xiii), 3.10(a)(xiv), 3.10(a)(xv), 3.10(a)(xvi), 3.10(a)(xvii) and 3.10(a)(xviii):
“(xiii)
within three (3) weeks from the end of each Calendar Quarter, a schedule showing the working interest and net revenue interests (including net working interest, royalty, overriding royalty, etc.) of

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BG (and its Affiliates) in each well (showing separately any percentage interest held indirectly by BG (and its Affiliates) as a member of some other Person) as of the end of such Calendar Quarter;
(xiv)
on or before the 15 th of each month preceding an obligation or expiration month, the monthly lease maintenance calendars (payments, extensions and expirations) with land recommendations;
(xv)
copies of all raw microseismic and seismic data, including reprocessing and interpretative data, analysis and reports for the East Texas/North Louisiana Area that (A) are in the possession of the Joint Development Operator or Party Operator, as applicable, (B) are not subject to Third Party confidentiality restrictions that have not been waived and (C) have been generated by EXCO or by a Third Party on behalf of the Joint Development Operator or Party Operator;
(xvi)
geographic information system data and shape files for the East Texas/North Louisiana Area that (A) are in the possession of the Joint Development Operator or Party Operator, as applicable, (B) are not subject to Third Party confidentiality restrictions that have not been waived and (C) have been generated by EXCO or by a Third Party on behalf of the Joint Development Operator or Party Operator, including any data layers or points associated with shape files such as lease expirations, depth severances and competitor drilling locations;
(xvii)
at the reasonable request of a Participating Party, a copy of general land data (as currently produced or compiled in the general course of business), inclusive of budget projections data, division of interest calculations, quarterly acreage reports or title curative for the East Texas/North Louisiana Area that are in the possession of Joint Development Operator or Party Operator, as applicable, are not subject to Third Party confidentiality restrictions that have not been waived and have been generated by EXCO or by a Third Party on behalf the Joint Development Operator or Party Operator;
(xviii)
at the reasonable request of a Participating Party that includes the applicable data query or queries, Joint Development Operator shall, within 30 days after receiving such request, provide such Participating Party with the results of specific data queries on Joint Development Operator’s land systems and databases; provided that the result of such queries provided to such Participating Party shall be limited to only those properties in which such Participating Party and Joint Development Operator own an interest under this Agreement.”     

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(e)
Section 3.10(b)(iv) shall be amended by replacing the phrase “for the purpose of conducting HSSE and asset integrity audits” with the phrase “for the purpose of conducting general audit activities, including conducting EHS and asset integrity audits”.
(f)
Section 3.10(c) shall be amended by adding the following to the end of the provision:
“In addition, Joint Development Operator (and any applicable Party Operator) shall provide each Development Party with notice of any written disputes which affect, or reasonably may affect, such Development Party’s leasehold or other property interest in the Subject Oil and Gas Assets or Special Shallow Rights Assets. Development Party shall be kept informed of material changes in the progress of any such disputes and, at the request of a Development Party, Joint Development Operator (and any applicable Party Operator) shall provide Development Party with copies of all pleadings, demand letters, or other material correspondence relating to any such dispute and make available personnel familiar with such disputes to assist with Development Party’s analysis and understanding of the dispute and to reasonably consider any views Development Party may have on the handling of such dispute.”
(g)
Section 3.10(d) shall be deleted in its entirety and replaced with the following:
“(d)
In addition to the other reports to be provided under this Section 3.10 and to the rights of a Development Party to request information under this Agreement or an Applicable Operating Agreement, for so long as EXCO or an Affiliate of EXCO is the Joint Development Operator and BG or an Affiliate of BG is a Development Party, EXCO shall provide employees and contractors of BG or its Affiliates with unrestricted, on-demand, on-site access during regular business hours to EXCO’s (and its Affiliates’) physical land records and electronic land management system (as of the 2014 Amendment Effective Date, such system is Excalibur and the applicable computer terminals accessing such system are located in Dallas, Texas) for the purposes of manipulating, reviewing and working with land records (including running queries and producing reports and summaries) related to Subject Oil and Gas Assets and Special Shallow Rights Assets owned by BG or its Affiliates. At BG’s cost and expense, EXCO shall cooperate with efforts by BG to remotely access EXCO’s (and its Affiliates’) land data and information to the extent related to such Subject Oil and Gas Assets and Special Shallow Rights Assets. Notwithstanding the foregoing, EXCO shall only be required to provide access to any such electronic land management system to the extent that (i) providing such access would not violate the provisions of any applicable software or other license (if necessary, after reasonable inquiry by EXCO to the licensor seeking permission for such access), (ii) BG obtains any applicable software or other license that may be required in connection with such access (and BG acknowledges that none of EXCO or its Affiliates will be responsible for obtaining any such license for

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BG), and (iii) such land data and information held in electronic form related to such Subject Oil and Gas Assets or Special Shallow Rights Assets is capable of being separated from land data and information held in electronic form that is related to other assets of EXCO or its Affiliates; provided that in each case of (i), (ii) and (iii), EXCO shall use its reasonable efforts to assist in accomplishing such requirement, but in no event shall EXCO or its Affiliates be required to incur any third party costs or pay any fees in connection therewith that BG is unwilling to reimburse.”
(h)
Section 3.10 shall be amended by adding the following subsections (e), (f) and (g):
“(e)
For so long as EXCO or an Affiliate of EXCO is acting as Joint Development Operator or Party Operator, EXCO (or such Affiliate) shall actively involve BG in operations and activities which support Development Operations, including, without limitation, by providing a representative of BG the opportunity to participate in (or send another available BG representative to) organized pre-scheduled meetings relating to the Subject Oil and Gas Assets (and, if applicable, Special Shallow Rights Assets) and/or Development Operations, including management team meetings, supply-chain meetings, organization or functional meetings, EHS meetings and contractor committee meetings.
(f)
To assist BG with any asset disposition analysis or efforts relating to its disposition of Subject Oil and Gas Assets (and, if applicable, Special Shallow Rights Assets), for so long as EXCO or an Affiliate of EXCO is Joint Development Operator, EXCO shall, at BG’s sole cost and expense and without any liability of EXCO or its Affiliates whatsoever (except for liabilities arising due to the willful misconduct of EXCO or its Affiliates), provide support services for any such asset disposition analysis or efforts including, without limitation, assisting with data presentation, providing responses to data requests by BG, providing access to records and data for third party due diligence, and gathering data for purchase and sale agreement representation and warranties; provided that no employee of EXCO or its Affiliates shall be required to make any presentations to potential purchasers. BG shall indemnify EXCO and its Affiliates and their respective employees and representatives for any and all claims and liabilities arising out of or related to any services provided pursuant to this Section in connection with any such proposed asset disposition, except for claims arising due to the willful misconduct of EXCO or its Affiliates.
(g)
To the extent the applicable information has not previously been provided to BG pursuant to a request under this Section 3.10(g) or prior to the 2014 Amendment Effective Date, Joint Development Operator shall deliver to BG, within a reasonable time period, not to exceed ninety (90) days following a request from BG (which date shall be extended if reasonably requested by

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Joint Development Operator considering the scope of the request), copies of any files, records, maps, information, and data, whether written or electronically stored, in its possession that relate to Subject Oil and Gas Assets and Special Shallow Rights Assets in which BG or an Affiliate of BG holds an interest, including (i) land and title records (including leases, abstracts of title, title opinions and title curative documents); (ii) contract files; (iii) correspondence; (iv) operations, environmental, production and accounting records; and (v) production, facilities and well records and data (including logs and cores); provided that if provision of such copies costs the Joint Development Operator an amount in excess of fifty thousand dollars ($50,000), then BG shall pay all the costs and expenses related to the provision of such copies which exceed fifty thousand dollars ($50,000).”
(i)
Section 3.12(a) shall be amended by deleting the phrase “change in Control of its ultimate parent company,” and replacing it with the phrase “change in Control of its ultimate parent company (but excluding a change in Control resulting from a management-led buyout of the public share ownership of such Person and the conversion of such Person to a privately-held Person),”.
(j)
Section 3.12(b) shall be amended by deleting it in its entirety and replacing it with the following:
“(b)
The allocation of Technical Services Costs by Joint Development Operator to Development Operations, and the incurrence thereof by Joint Development Operator and its Affiliates, shall be equitable and commercially reasonable, and Joint Development Operator shall furnish details of its allocation procedures to a Development Party upon request. The Joint Development Operator shall not be entitled to receive duplicate payments for such Technical Services Costs. All Technical Services Costs chargeable with respect to Development Operations shall be chargeable to the Development Parties on a Calendar Month basis by Joint Development Operator and each Development Party shall pay its Participating Interest share thereof in accordance with Section 2.2. If any third party participates in a Development Operation for which Technical Services Costs are incurred, and such Technical Services Costs are properly chargeable to such third party, Joint Development Operator (or the applicable Party Operator) shall bill such third party for its working interest share of such Technical Services Costs and not pass such share of such costs on to the Development Parties; and any such amounts collected from third parties in connection therewith will be shared by the Development Parties in accordance with their respective Participating Interests (and Joint Development Operator or Party Operator, as applicable, shall credit to each such other Development Party the proportionate share to which such Development Party is entitled with respect to such amount received by such Joint Development Operator or Party Operator).”

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(k)
Section 4.1(p) shall be amended by deleting it in its entirety and replacing it with the following:
“(p)
All notices and communications required or permitted to be given under Section 3.10 or Article 4 to the Development Parties or a Party Operator or the members of the Operating Committee shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission (provided any such facsimile transmission is confirmed either orally or by written confirmation), or sent by pdf via e-mail, addressed to the appropriate Party at the address for such Party shown below or at such other address as such Party shall have theretofore designated by written notice delivered to the Party giving such notice:

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If to EXCO:
 
EXCO Resources, Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: William L. Boeing, Vice President,
                     General Counsel, and Secretary
Telephone: (214) 368-2084
Fax: (214) 706-3409
E-mail: lboeing@EXCOResources.com
 
With a copy to:
 
Attention Harold L. Hickey
Telephone: (214) 368-2084
Fax: (214) 368-8754
E-mail: hhickey@excoresources.com
 
 
If to BG:
 
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
Attention: Roger Coe
Telephone: (713) 599-4000
Fax: (713) 599-4250
E-mail: roger.coe@bg-group.com
 
 
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
Attention: Chris Migura, Principal Counsel
Telephone: (713) 599-4000
Fax: (713) 599-4250
E-mail: chris.migura@bg-group.com
 

Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile transmission or email during normal business hours (or, if not sent transmitted during normal business hours, on the next business day), or upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or deposited in the United States Mail, as the case may be. The Parties may change the address, telephone numbers, facsimile numbers and email addresses to which such communications are to be

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addressed by giving written notice to the other Parties in the manner provided in this Section 4.1(p).”

(l)
Section 4.1 shall be amended by adding the following subsection (q):
“(q)
Effective as of the 2014 Amendment Effective Date, at least ten (10) days prior to each meeting of the Operating Committee, Joint Development Operator shall deliver to the Development Parties (i) an organization chart for the organization supporting Joint Development Operator’s activities, (ii) a proposed allocation of employee or Secondee time for Joint Development Operator activities during the upcoming Calendar Quarter, (iii) an assessment of whether the preceding Calendar Quarter’s allocation of employee or Secondee time for Joint Development Operator activities should be modified, and (iv) a general listing of any significant activities performed or to be performed by employees or Secondees during the current Calendar Quarter which are not Development Operations or otherwise conducted for the benefit of both BG and EXCO or the benefit of Affiliates of both of them pursuant to this Agreement (such as efforts of EXCO or its Affiliates to support new business development or asset dispositions in which BG does not participate; provided, however, that proprietary information of EXCO and/or its Affiliates in which BG or its Affiliates does not also have a proprietary interest shall not be required to be included in such general listings), together with an estimate of the amount of time spent or to be spent by each individual on such activities during such Calendar Quarter. At a meeting of the Operating Committee each Calendar Quarter, Joint Development Operator shall be prepared to explain and discuss how the various operational departments of Joint Development Operator are resourced and whether such allocation of resources should be modified.”
(m)
Section 4.7 shall be amended by adding the following subsection (g):
“(g)
Within ten (10) days after the end of each Calendar Month, Joint Development Operator or Party Operator shall provide each Development Party with a list of Development Operations Contracts relating to Development Operations that can reasonably be expected to result in aggregate payment to the counterparty of more than two hundred fifty thousand dollars (US$250,000), together with the status of any negotiations or tender processes relating to any unexecuted Development Operations Contracts as of the end of the Calendar Month.”
(n)
Section 9.2(a) shall be amended by adding the following sentence to the end of the subsection:
“Within fifteen (15) days of the delivery of an Offer Notice, the Acquiring Development Party shall provide the Non-Acquiring Development Parties with access to complete

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well files and all geological and geophysical, title, environmental, contract and other information about the applicable Oil and Gas Assets (and if applicable, the entity holding them) to which the Acquiring Development Party has access.”
(o)
Section 9.2(b) shall be amended by deleting the phrase “a period of sixty (60) days after receipt of the Offer Notice” and replacing it with the phrase “until the end of the AMI Election Period”.
(p)
Section 9.2(e) shall be amended by deleting the phrase “within thirty (30) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Development Party’s statement of the Cash Value” and replacing it with the phrase “within twenty (20) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Development Party’s statement of the Cash Value”.
(q)
Section 9.2 shall be amended by adding the following subsections (k) and (l):
“(k)
The Development Parties agree to use good faith efforts to keep each other informed of any prospective Acquired Interest being pursued by each Development Party or its Affiliates within the East Texas/North Louisiana Area prior to the time that an Offer Notice is required under Section 9.2(a). Such obligation shall be subject to confidentiality agreements entered into with third parties; provided that each Development Party shall use its good faith efforts to (i) provide notice of the prospective opportunity prior to entering into any confidentiality agreement and (ii) have an exception included in such agreement allowing disclosure to the other Development Parties and their Affiliates subject to their execution of a substantially similar confidentiality agreement.
(l)
The area of mutual interest described in Section 9.1 and the applicable area of mutual interest procedures set out in Section 9.2(a) through (k) shall be extended until August 14, 2016, for any Acquired Interest that is located within the Core AMI Area, but only with respect to that portion of any Acquired Interest that is located within such area.”
(r)
Section 14.2 shall be amended by deleting such section in its entirety and replacing it with the following:
Notices. All notices and communications required or permitted to be given hereunder, excluding any notices under Section 3.10 and Article 4 hereof (which notices shall be governed by the provisions of Section 4.1(p) hereof), shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission (provided any such facsimile transmission is confirmed either orally or by written confirmation), addressed to the appropriate Party at the address for such Party shown below or at such other address

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as such Party shall have theretofore designated by written notice delivered to the Party giving such notice:
 
If to EXCO:
 
 
EXCO Operating Company, LP
 
12377 Merit Drive, Suite 1700
 
Dallas, Texas 75251
 
Attention: President
 
Telephone: (214) 368-2084
 
Fax: (214) 368-8754
 
 
 
With a copy to:
 
 
 
EXCO Operating Company, LP
 
12377 Merit Drive, Suite 1700
 
Dallas, Texas 75251
 
Attention: William L. Boeing, Vice President,
 
                       General Counsel, and Secretary
 
Telephone: (214) 368-2084
 
Fax: (214) 706-3409
 
 
 
If to BG:
 
 
BG US Production Company, LLC
 
811 Main Street, Suite 3400
 
Houston, Texas 77002
 
Attention: Roger Coe
 
Telephone: (713) 599-4000
 
Fax: (713) 599-4250
 
 
 
 
with a copy to:
 
 
 
BG US Production Company, LLC
 
811 Main Street, Suite 3400
 
Houston, Texas 77002
 
Attention: Chris Migura, Principal Counsel
 
Telephone: (713) 599-4000
 
Fax: (713) 599-4250
 
 



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Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile transmission during normal business hours (or, if not sent transmitted during normal business hours, on the next business day), or upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or deposited in the United States Mail, as the case may be. The Parties may change the address, telephone numbers, and facsimile numbers to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 14.2.”
(s)
Each use of the term “HSSE” throughout the JDA shall be deleted and replaced with the term “EHS”. The defined terms in Appendix I previously beginning with the term “HSSE” and now beginning with the term “EHS” shall be reordered in the appropriate alphabetic locations.
(t)
Appendix I shall be amended by deleting the definition for “HSSE” in its entirety.
(u)
Appendix I shall be amended by deleting the definition for “Secondee” and replacing it with the following:
Secondee ” means any employee of a Party or an Affiliate of a Party seconded into the organization of Joint Development Operator or any of its Affiliates in accordance with this Agreement, but shall exclude any GDP Member.
(v)
Appendix I shall be amended by adding the following definitions in their correct alphabetic locations:
AMI Election Period ” shall mean (a) for Offered Interests with a value (in any one or related series of transactions) of less than five hundred thousand dollars ($500,000), from receipt of the Offer Notice until thirty (30) days from receipt of the Offer Notice and a fully completed and accurate Transaction Information Sheet for all such Offered Interests, extended for a period of five (5) days following determination of the Cash Value (if applicable), and (b) for all other Offered Interests, the sixty (60) days from receipt of the Offer Notice and determination of the Cash Value (if applicable).
Appalachia LLC Agreement ” means that certain Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC dated June 1, 2010, between EXCO Resources (PA), LLC, BG US Production Company, LLC, and EXCO Holding (PA), Inc., as amended from time to time, including pursuant to that certain Amendment to the Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC dated as of even date herewith between EXCO Resources (PA), LLC, BG US Production Company, LLC, and EXCO Holding (PA), Inc.
Core AMI Area ” shall mean Sections 5,6,7,8,9,10 and 16 in 15N-15W Gloria’s ranch related sections.

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EHS ” shall mean Environmental, Health and Safety.
GDP Member ” shall mean a BG graduate development program member, as identified by BG as such.
2014 Amendment Effective Date ” means October 14, 2014.
Transaction Information Sheet ” shall mean a description of property in the form attached hereto as Exhibit “J”.
(w)
The JDA shall be amended by attaching Exhibit “J” attached hereto as Exhibit “J” to the JDA.
3.
Application of Certain Provisions. The terms of Sections 13.1, 13.2, 14.1, 14.2, 14.3, 14.4, 14.6, 14.7, 14.8, 14.9, 14.10, 14.11, 14.12(a), 14.13 and 14.14 of the JDA are incorporated herein by reference as if set out in full herein.
4.
Ratification. Except as amended herein, the terms and conditions of the JDA shall remain in full force and effect. Any and all references to the JDA shall hereafter refer to the JDA as amended by this Amendment.
[ Signature page follows ]


IN WITNESS WHEREOF, the Parties have executed this Amendment on the Execution Date.

 
 
EXCO OPERATING COMPANY, LP
 
 
By: EXCO Partners OLP GP, LLC,
   Its general partner


 
 
By: /s/ WILLIAM L. BOEING         
Name: William L. Boeing
Title: Vice President and General Counsel

 
 
 
 
 
 
 
 
BG US PRODUCTION COMPANY, LLC

 
 
By: /s/ ROGER COE
Name: Roger Coe
Title: Vice President
 
 
 
SOLELY FOR THE PURPOSES OF AMENDMENTS TO SECTION 3.8:
 
EXCO RESOURCES (PA), LLC
 
 


 
 
By: /s/ WILLIAM L. BOEING         
Name: William L. Boeing
Title: Vice President and General Counsel



Page 14

Exhibit 10.20

Execution Version

AMENDMENT TO THE JOINT DEVELOPMENT AGREEMENT
(APPALACHIA)
This Amendment to the Joint Development Agreement (the “ Amendment ”) is entered into on October 14, 2014 (the “ Execution Date ”) between BG Production Company (PA), LLC, a Delaware limited liability company (“ BGPA ”), BG Production Company (WV), LLC, a Delaware limited liability company (“ BGWV ” and, together with BGPA, “ BG ”), EXCO Production Company (PA), LLC, a Delaware limited liability company (“ EXCOPA ”), EXCO Production Company (WV), LLC, a Delaware limited liability company (“ EXCOWV ” and, together with EXCOPA, “ EXCO ”), and EXCO Resources (PA), LLC, a Delaware limited liability company (the “ Company ”). BG, EXCO and the Company are referred to herein collectively as the “ Parties ” and each individually as “Party.”
RECITALS
WHEREAS, the Parties entered into that certain Joint Development Agreement dated June 1, 2010, which covers the joint development of certain oil and gas assets (as so amended, the “ JDA ”); and
WHEREAS, the Parties desire to amend the JDA in accordance with the provisions of this Amendment;
NOW, THEREFORE, in consideration of the mutual promises contained in this Amendment and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:
1.
Definitions and References. Capitalized terms used in this Amendment and not otherwise defined herein have the meanings given such terms in the JDA. Sections, Articles, Appendices, Exhibits, Schedules and subsections referred to herein refer to such Sections, Articles, Appendices, Exhibits, Schedules and subsections of the JDA unless the context expressly states otherwise.
2.
JDA Amendment . The JDA is hereby amended as follows:
(a)
Section 3.5 shall be amended by adding the following subsection (i):
“(i)
To the extent the applicable information has not previously been provided to BG pursuant to a request under this Section 3.5(i) or prior to the 2014 Amendment Effective Date, Joint Development Operator shall deliver to BG, within a reasonable time period, not to exceed ninety (90) days following request from BG (which date shall be extended if reasonably requested by Joint Development Operator considering the scope of the request), copies of any files, records, maps, information, and data, whether written or electronically stored, in its possession that relate to Subject Oil and Gas Assets in which BG or an Affiliate of BG holds an interest, including (A)

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land and title records (including leases, abstracts of title, title opinions and title curative documents); (B) contract files; (C) correspondence; (D) operations, environmental, production and accounting records; and (E) production, facilities and well records and data (including logs and cores); provided that if, in Joint Development Operator’s reasonable opinion, such provision of such copies would require more than (40) hours to complete or would otherwise cost the Joint Development Operator an amount in excess of $50,000, then BG shall pay all the costs and expenses related to the provision of such copies.”
(b)
Section 3.6(b) shall be amended by deleting it in its entirety and replacing it with the following:
“(b)
The allocation of Technical Services Costs to Development Operations, and the incurrence thereof by a Development Party and its Affiliates, shall be equitable and commercially reasonable, and such Development Party shall furnish details of its allocation procedures to a Development Party upon request. The Development Party providing Technical Services shall not be entitled to receive duplicate payments for such Technical Services Costs.”
(c)
Section 3.7(c) shall be amended by deleting it in its entirety and replacing it with the following:
“(c)
If any Technical Services Costs or overhead chargeable under Article III of Exhibit C to any Joint Development Operating Agreement or any similar provision of any Third Party Operating Agreement are properly chargeable by the Joint Development Operator or any Party Operator to (i) any Participating Party in a Sole Risk Development Operation, (ii) any Development Party, Entity Member or Joint Entity undertaking a Sole Risk Entity Operation, or (iii) any Person other than a Development Party, Entity Member or Joint Entity; then (A) such amounts shall be charged to such applicable Persons and not to any Development Parties, Entity Members or Joint Entities that do not otherwise owe such amounts, and (B) such amounts received by Joint Development Operator or a Party Operator in connection therewith will be shared by the Development Parties in accordance with their respective JDA Interests (and Joint Development Operator or the Party Operator, as applicable, shall credit to each Development Party the proportionate share to which such Development Party is entitled with respect to such amount received by such Joint Development Operator or Party Operator).”
(d)
Section 4.1(o) shall be amended by deleting it in its entirety and replacing it with the following:
“(o)
All notices and communications required or permitted to be given under this Article 4 to the Development Parties or a Party Operator or the members of

Page 2


the Operating Committee shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission or by pdf via email (provided any such facsimile or email transmission is confirmed either orally or by written confirmation), addressed to the appropriate Person at the address for such Person shown below or at such other address as such Party shall have theretofore designated by written notice delivered to the Party giving such notice:
        
 
If to EXCO or any EXCO Member:
 
 
EXCO Holding (PA), Inc.
 
12377 Merit Drive, Suite 1700
 
Dallas, Texas 75251
 
Attention: Harold L. Hickey
 
Telephone: (214) 368-2084
 
Fax: (214) 368-8754
 
Email: hhickey@excoresources.com
 
 
 
With a copy to:
 
 
 
EXCO Resources, Inc.
 
12377 Merit Drive, Suite 1700
 
Dallas, Texas 75251
 
Attention: William L. Boeing, Vice President
 
                     General Counsel, and Secretary
 
Telephone: (214) 368-2084
 
Fax : (214) 706-3409
 
Email : lboeing@EXCOResources.com
 
 
 
If to BG or any BG Member:
 
 
 
BG US Production Company, LLC
 
811 Main Street, Suite 3400
 
Houston, Texas 77002
 
Attention: Roger Coe
 
Telephone: (713) 599-4000
 
Fax: (713) 599-4250
 
E-mail: roger.coe@bg-group.com
 
 

Page 3


 
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
Attention: Chris Migura, Principal Counsel
Telephone: (713) 599-4000
Fax: (713) 599-4250
E-mail: chris.migura@bg-group.com
 
 
 
If to the Company or any Joint Entity:
 
 
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President and General Manager
Telephone: (214) 368-2084
Fax: (214) 368-8754
 
With a copy to:
 
Attention: Vice President, Legal
Telephone: (724) 720-2500
Fax: (724) 720-2505
 
Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile transmission or email during normal business hours (or, if not sent transmitted during normal business hours, on the next business day), or upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or deposited in the United States Mail, as the case may be. The Parties may change the address, telephone numbers, facsimile numbers and email addresses to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 4.1(o).”
(e)
Section 4.4(a)(iii) shall be amended by deleting it in its entirety and replacing it with the following:
“(iii)    [omitted].”
(f)
Section 4.4(c) shall be amended by deleting it in its entirety and replacing it with the following:
“(c)    [omitted].”

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(g)
Section 9.2(a) shall be amended by deleting the phrase “the expiration of the sixty (60) day election period in Section 9.2(b)” and replacing it with “the end of the AMI Election Period”.
(h)
Section 9.2(b) shall be amended by deleting the phrase “a period of sixty (60) days after receipt of the Offer Notice” and replacing it with the phrase “until the end of the AMI Election Period”.
(i)
Section 9.2(e) shall be amended by deleting the phrase “within thirty (30) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Development Party’s statement of the Cash Value” and replacing it with the phrase “within twenty (20) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Development Party’s statement of the Cash Value”.
(j)
Section 14.2 shall be amended by deleting such section in its entirety and replacing it with the following:
Notices. All notices and communications required or permitted to be given hereunder, excluding any notices under Article 4 hereof (which notices shall be governed by the provisions of Section 4.1(o) hereof), shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission (provided any such facsimile transmission is confirmed either orally or by written confirmation), addressed to the appropriate Party at the address for such Party shown below or at such other address as such Party shall have theretofore designated by written notice delivered to the Party giving such notice:
If to EXCO:
 
EXCO Holding (PA), Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President
Telephone: (214) 368-2084
Fax: (214) 368-8754

 
with a copy to:

EXCO Resources, Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: William L. Boeing, Vice President,
      General Counsel, and Secretary
Telephone: (214) 368-2084
Fax: (214) 706-3409

If to BG:

Page 5


 
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
Attention: Roger Coe
Telephone: (713) 599-4000
Fax: (713) 599-4250

 
with a copy to:

BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
Attention: Chris Migura, Principal Counsel
Telephone: (713) 599-4000
Fax: (713) 599-4250

If to the Company:

 
EXCO Resources (PA), LLC
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President and General Manager
Telephone: (214) 368-2084
Fax: (214) 368-8754

With a copy to:

Attention: Vice President, Legal
Telephone: (724) 720-2500
Fax: (724) 720-2505


Any notice given in accordance herewith (including any notice given to a Credit Facility Secured Party) shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile transmission during normal business hours (or, if not sent transmitted during normal business hours, on the next business day), or upon actual receipt by the addressee after such notice has been deposited in the United States Mail, as the case may be. The Parties may change the address, telephone numbers, and facsimile numbers to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 14.2. Notice given to a Development Party shall be deemed to be notice to its affiliated Entity Members for all purposes under this Agreement. Notice to any Joint Entity shall be accomplished by notice to each of its Entity Members.”
(k)
The definition of “ Technical Services ” in Appendix I shall be amended by deleting the term “HSSE” therefrom and replacing it with the term “EHS”.
(l)
The definition of “ Technical Services Costs ” in Appendix I shall be amended by deleting the term “HSSE” therefrom and replacing it with the term “EHS”.

Page 6


(m)
Appendix I shall be amended by deleting the definition for “Secondee”.
(n)
Appendix I shall be amended by adding the following definitions in their correct alphabetic locations:
AMI Election Period ” shall mean (a) for Offered Interests with a value (in any one or related series of transactions) of less than five hundred thousand dollars ($500,000), from receipt of the Offer Notice until thirty (30) days from receipt of the Offer Notice and a fully completed and accurate Transaction Information Sheet for all such Offered Interests, extended for a period of five (5) days following determination of the Cash Value (if applicable), and (b) for all other Offered Interests, the sixty (60) days from receipt of the Offer Notice and determination of the Cash Value (if applicable).
“2014 Amendment Effective Date” means October 14, 2014.
Company Agreement ” means that certain Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC dated June 1, 2010, between EXCO Resources (PA), LLC, BG US Production Company, LLC, and EXCO Holdings (PA), Inc., as amended from time to time, including pursuant to that certain Amendment to the Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC dated as of even date herewith between EXCO Resources (PA), LLC, BG US Production Company, LLC, and EXCO Holding (PA), Inc.
EHS ” shall mean Environmental, Health and Safety.
Transaction Information Sheet ” shall mean a description of property in the form attached hereto as Exhibit “K”.
(o)
The JDA shall be amended by attaching Exhibit “K” attached hereto as Exhibit “K” to the JDA.
3.
Application of Certain Provisions. The terms of Sections 13.1, 13.2, 14.1, 14.2, 14.3, 14.4, 14.6, 14.7, 14.8, 14.9, 14.10, 14.11, 14.12(a), 14.13 and 14.14 of the JDA are incorporated herein by reference as if set out in full herein.
4.
Ratification. Except as amended herein, the terms and conditions of the JDA shall remain in full force and effect. Any and all references to the JDA shall hereafter refer to the JDA as amended by this Amendment.
[ Signature page follows ]

IN WITNESS WHEREOF, the Parties have executed this Amendment on the Execution Date.

 
 
EXCO PRODUCTION COMPANY (PA), LLC
 
 
By: /s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
 
 
 
 
 
EXCO PRODUCTION COMPANY (WV), LLC
 
 
By: /s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
 
 
 
 
 
BG PRODUCTION COMPANY (PA), LLC

 
 
By: /s/ ROGER COE
Name: Roger Coe
Title: Vice President
 
 
 
 
 
BG PRODUCTION COMPANY (WV), LLC
 
 
By: /s/ ROGER COE
Name: Roger Coe
Title: Vice President

 
 
 
 
 
EXCO RESOURCES (PA), LLC
 
 
By: /s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
 
 
 



Page 7
Exhibit 10.22

Execution Version

AMENDMENT TO THE SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF EXCO RESOURCES (PA), LLC
This Amendment to the Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC (this “ Amendment ”) is entered into on October 14, 2014 (the “ Execution Date ”) between EXCO Resources (PA), LLC, a Delaware limited liability company (the “ Company ”), BG US Production Company, LLC, a Delaware limited liability company (“ BG Member ”) and EXCO Holding (PA), Inc., a Delaware corporation (“ EXCO Member ”). BG Member, EXCO Member and Company are referred to herein collectively as the “ Parties ” and each individually as a “ Party .”
RECITALS
WHEREAS, the Parties entered into that certain Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC dated June 1, 2010 (the “ LLC Agreement ”); and
WHEREAS, the Parties desire to amend the LLC Agreement in accordance with the provisions of this Amendment;
NOW, THEREFORE, in consideration of the mutual promises contained in this Amendment and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:
1.
Definitions and References. Capitalized terms used in this Amendment and not otherwise defined herein have the meanings given such terms in the LLC Agreement. Sections, Articles, Appendices, Exhibits, Schedules and subsections referred to herein refer to such Sections, Articles, Appendices, Exhibits, Schedules and subsections of the LLC Agreement unless the context expressly states otherwise.
2.
LLC Agreement Amendment . The LLC Agreement is hereby amended as follows:
(a)
Section 1.1 shall be amended by adding the following definitions in their correct alphabetical locations:
2014 Amendment Effective Date ” means October 14, 2014.
AMI Acquisition ” means an acquisition of an interest in Oil and Gas Assets by the Company, as may be required pursuant to Section 9.2(h) of the Joint Development Agreement.
BG ” means BG US Production Company, LLC, a limited liability company organized and existing under the Laws of Delaware.
East Texas/North Louisiana Area ” shall have the meaning given to it in the ET/NL JDA.

Page 1


EHS ” means Environmental, Health and Safety.
ET/NL JDA ” means the Joint Development Agreement, dated August 14, 2009 between BG Member, EXCO and EXCO Production Company, LP (which entity merged into EXCO and terminated its separate existence) as amended by amendment dated May 19, 2010, by amendment dated February 1, 2011, by amendment dated February 14, 2013 and by amendment date October 14, 2014.
ET/NL Joint Development Operator ” shall have the meaning given to the term “Joint Development Operator” in the ET/NL JDA.
ET/NL OpCom ” shall have the meaning given to the term “Operating Committee” in the ET/NL JDA.
ET/NL Operations ” shall have the meaning given to the term “Development Operations” in the ET/NL JDA.
EXCO ” means EXCO Operating Company, LP, a Delaware limited partnership.
GDP Member ” means a BG graduate development program member, as identified by BG as such.
Participating Interest ” shall have the meaning given to it in the ET/NL JDA.
Primary Departments ” means the subsurface, operations, drilling, completions engineering, portfolio optimization, EHS, land or finance departments, or any successor department exercising substantially the same function.
Secondee ” or “ secondee ” means any employee of a Party or an Affiliate of a Party seconded into the organization of Company or Service Provider in accordance with this Agreement.
Service Provider ” means EXCO when EXCO and/or its Affiliates provide substantial personnel services toward conducting Development Operations in the Appalachian Area either pursuant to Services Agreement(s) with the Company and/or secondment agreement(s) with the Company, which, in the case of secondment agreement(s) with the Company, means that such secondment agreement(s) entitle EXCO and/or its Affiliates to place Persons with the Company as secondees to the extent that the responsibilities of such Persons, when viewed as a whole, entitle such Persons to exert substantial management or control over the Company.
(b)
Section 1.1 shall be amended by deleting the definition of “Budgeted Acquisition.”
(c)
Section 2.2(x) shall be amended by deleting it in its entirety and replacing it with the following:

Page 2


“(x)
any acquisition of Oil and Gas Assets (other than Operating Assets in the ordinary course of business) for consideration in excess of five hundred thousand dollars (US$500,000) in any transaction or series of related transactions, but excluding any AMI Acquisition (for which no vote of the Management Board is required);”
(d)
Section 2.3(c) shall be amended by deleting it in its entirety and replacing it with the following:
“(c)
delegation of authority to the officers of the Company to enter into certain Company Contracts (including Hydrocarbons sales agreements);”
(e)
Section 2.3(k) shall be amended by inserting the phrase “except as provided in Sections 2.11(g) and 2.11(h)” immediately following the reference to “Section 2.11(f).”
(f)
Section 2.3(p) shall be amended by deleting it in its entirety and replacing it with the following:
“(p)
[omitted];”
(g)
Section 2.3(s) shall be amended by deleting the phrase “and 2.11(b)(iii)”.
(h)
Section 2.3(y) shall be amended by deleting the phrase “established by the Vice President of Finance and Business Services” and replacing it with the phrase “established by the officer of the Company principally responsible for the Company’s financial matters”.
(i)
Section 2.4(a) shall be amended by deleting the first two sentences and replacing them with the following:
“The Management Board shall consist of four (4) Board Members. Each of BG Affiliate Group and EXCO Affiliate Group shall be entitled to appoint two (2) Board Members and two (2) alternate Board Members.”
(j)
Section 2.5(d) shall be amended by deleting it in its entirety and replacing it with the following:
“(d)    [omitted];”
(k)
Section 2.5(e) shall be amended by deleting it in its entirety and replacing it with the following:
“(e)    [omitted];”
(l)
Section 2.5(f) shall be amended by deleting it in its entirety and replacing it with the following:

Page 3


“The Management Board shall meet (i) upon at least fifteen (15) days advance notice by either BG Affiliate Group or EXCO Affiliate Group or (ii) whenever at least one of the Board Members or alternate Board Members from each of the BG Affiliate Group and the EXCO Affiliate Group are present and agree to hold such a meeting, without any requirement for advance notice or delivery of an agenda. If any Member or Board Member so requests, any meeting of the Management Board, or the consideration of any proposal by the Management Board at a meeting, shall be deferred for up to fifteen (15) days from the date on which such meeting is requested or such proposal tendered, if the meeting is held or proposal tendered with less than fifteen (15) days notice to all Members. So long as both the BG Affiliate Group and the EXCO Affiliate Group hold interests in the ET/NL JDA, the Management Board will use commercially reasonable efforts to hold its meetings immediately following meetings of the ET/NL OpCom. All meetings of the Management Board and each subcommittee shall be held in the principal offices of the Company, or elsewhere as the Management Board or such subcommittee may mutually decide which alternate location may be within or outside the State of Delaware.”
(m)
Section 2.5(g) shall be amended by deleting it in its entirety and replacing it with the following:
“(g)    [omitted];”
(n)
Section 2.5(i) shall be amended by deleting the first sentence and replacing it with the following:
“The secretary of the Management Board shall provide each Member with a copy of the Management Board meeting minutes relating to each decision made by the Management Board during a Management Board meeting within fifteen (15) Business Days after the end of the meeting.”
(o)
Section 2.5(o) shall be amended by deleting it in its entirety and replacing it with the following:
“(o)
All notices and communications required or permitted to be given to the Board Members and the President and General Manager pursuant to this Article 2 shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission, or by pdf via e-mail (provided that any such facsimile or email transmission is confirmed either orally or by written confirmation), addressed to the appropriate Group at the address for such Group shown below or at such other address as such Member shall have theretofore designated by written notice delivered to the Member giving such notice:

Page 4


If to the President and General Manager:
 
EXCO Resources (PA), LLC
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President and General Manager
Telephone: (214) 368-2084
Fax: (214) 368-8754


If to the EXCO Affiliate Group:
 
EXCO Holding (PA), Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President
Telephone: (214) 368-2084
Fax: (214) 368-8754
With a copy to:

EXCO Resources, Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: William L. Boeing, General Counsel
Telephone: (214) 368-2084
Fax: (214) 706-3409
E-mail: lboeing@excoresources.com

If to the BG Affiliate Group:
 
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
 
Attention: Roger Coe
Telephone: (713) 599-4000
Fax: (713) 599-4250
E-mail: roger.coe@bg-group.com

BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
 
Attention: Chris Migura, Principal Counsel
Telephone: (713) 599-4000
Fax: (713) 599-4250
E-mail: chris.migura@bg-group.com

Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person or by courier, or transmitted by facsimile transmission or email during normal business hours (or, if not sent transmitted during normal business hours, on the next business day), or upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or

Page 5


deposited in the United States Mail, as the case may be. Each Group may change the address, telephone numbers, facsimile numbers and email addresses to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 2.5(o).”
(p)
Section 2.5 shall be amended by adding the following subsections (p) and (r):
“(p)
In lieu of a vote taken at a meeting or a proposal distributed in accordance with Section 2.5(j), a written resolution of the Management Board will be effective to evidence the approval of the Management Board upon the signature of at least one of the Board Members or alternate Board Members from each Group.
(r)
Effective as of the 2014 Amendment Effective Date, at least ten (10) days prior to each meeting of the Management Board, the Company (or EXCO, to the extent that EXCO is acting as Service Provider) shall deliver to the Members (i) an organization chart for the organization supporting Company’s activities, (ii) a proposed allocation of employee or Secondee time for Company activities during the upcoming Calendar Quarter, (iii) an assessment of whether the preceding Calendar Quarter’s allocation of employee or Secondee time for Company activities should be modified, and (iv) a general listing of any significant activities performed or to be performed by employees or Secondees during the current Calendar Quarter which are not Development Operations or otherwise conducted for the benefit of both BG Member and EXCO Member pursuant to this Agreement or the benefit of Affiliates of both of them pursuant to the Joint Development Agreement (such as efforts of EXCO or its Affiliates to support new business development or asset dispositions in which BG does not participate; provided, however, that proprietary information of EXCO and/or its Affiliates in which BG or its Affiliates do not also have a proprietary interest shall not be required to be included in such general listings), together with an estimate of the amount of time spent or to be spent by each individual on such activities during such Calendar Quarter. At each meeting of the Management Board, Company (or EXCO, to the extent that EXCO is acting as Service Provider) shall be prepared to explain and discuss how the various operational departments of Company (or EXCO, to the extent EXCO is acting as Service Provider) are resourced and whether such allocation of resources should be modified.”
(q)
Section 2.11(a)(i) shall be amended by deleting it in its entirety and replacing it with the following:
“(i)
The Management Board shall have the power to elect, delegate authority to, and remove such officers of the Company as the Management Board may from time to time deem appropriate; provided, however, that each officer appointee of the Company shall serve a three (3) year term commencing as

Page 6


of the date of the appointment of such officer, subject to each officer’s appointment being subject to an annual ratification vote by the Management Board. After any Management Board vote not to ratify the appointment of any officer, the Management Board shall, as soon as reasonably practicable thereafter, appoint a replacement officer, which replacement officer shall serve a three (3) year term (subject to annual ratification votes as described in this Section 2.11(a)(i)).”
(r)
Section 2.11(a)(ii) shall be amended by deleting it in its entirety and replacing it with the following:
“(ii)
[omitted].”
(s)
Section 2.11(b)(i) shall be amended by deleting the first sentence and replacing it with the following:
“The Company shall have a President and General Manager and such other officers as may be determined by the Management Board from time to time.”
(t)
Section 2.11(b)(ii) shall be amended by deleting the second sentence of such Section.
(u)
Section 2.11(b)(iii) shall be amended by deleting it in its entirety and replacing it with the following:
“(iii)    [omitted].”
(v)
Section 2.11(c) shall be amended by deleting it in its entirety and replacing it with the following:
“(c)
Unless otherwise agreed by the Management Board, (i) all Secondees of the Company that are employees of a member of the EXCO Affiliate Group shall be seconded to the Company by the Members pursuant to a secondment agreement substantially in the form of Exhibit “A” attached hereto; and (ii) all Secondees of the Company that are employees of a member of the BG Affiliate Group shall be seconded to the Company by the Members pursuant to a secondment agreement substantially in the form of Exhibit “A-1” attached hereto. Simultaneously with the execution of this Agreement, each initial Member and the Company entered into a secondment agreement substantially in the form of Exhibit “A”. On the 2014 Amendment Effective Date, BG Member, Company and a certain member of the EXCO Affiliate Group shall enter into an amended and restated secondment agreement substantially in the form of Exhibit “A-1”, which such agreement shall be the Secondment Agreement for the BG Member. Each Affiliated Member Group with a Percentage Interest greater than twenty five percent (25%) shall have the right but not the obligation to second its or its Affiliates’ employees to the Company; provided, however, that the officers of the Company must

Page 7


be approved by the Management Board pursuant to Section 2.3(s) and except as provided in Sections 2.11(g) and 2.11(h) all employees and secondees of the Company that are not officers must be approved by the President and General Manager (provided that the President and General Manager shall not unreasonably withhold consent and shall, in the exercise of his or her consent, give significant consideration to BG’s interest in placing secondees within the organization; provided that: (i) the secondment rights of the BG Affiliate Group shall be subject to Sections 2.11(g) and (h); and (ii) if the EXCO Affiliate Group possesses a Percentage Interest greater than twenty five percent (25%), the EXCO Affiliate Group shall have the right but not the obligation to second one or more of its or its Affiliates' employees to the Company in each of the Primary Departments of the Company.”
(w)
Section 2.11 shall be amended by adding the following subsection (g):
“(g)
If the BG Affiliate Group possesses a Percentage Interest greater than 25% and a Participating Interest of greater than 25% under the ET/NL JDA, the following provisions apply:
(i)
Subject to the terms of its Secondment Agreement, BG has the right but not the obligation to place Secondees in the positions identified on Exhibit “C” attached hereto (or to fill any Secondee vacancies of such positions) within the Company and/or EXCO (in its capacity as ET/NL Joint Development Operator in the East Texas/North Louisiana Area or Service Provider in the Appalachian Area) for the primary purpose of supporting ET/NL Operations in the East Texas/North Louisiana Area and/or Development Operations in the Appalachian Area. Notwithstanding the foregoing, upon the prior written approval of BG (such approval not to be unreasonably withheld), the Company and/or EXCO, as applicable, shall each have the right in its reasonable discretion, to reallocate the Persons so dedicated to other similar positions with Company or EXCO, as applicable. Any such placement of Secondees by BG in such positions or filling of Secondee vacancies in such positions shall be made promptly by BG and in any event such Secondee shall be available for commencing work at the Company or EXCO, as applicable, within sixty (60) days after such positions become vacant. If such placement or filling of vacancy, and the availability of such Secondee for such work, is not made within such time, then (subject to Section 2.11(i)), EXCO shall have the right to fill such vacant position with a Secondee available for commencing work.

(ii)
If a position becomes available within any of the Primary Departments of the Company or EXCO (in its capacity as ET/NL Joint Development Operator in the East Texas/North Louisiana Area

Page 8


or Service Provider in the Appalachian Area) and the time spent by the Person holding such position was at least 50% allocable to activities relating to Development Operations in the Appalachian Area or to ET/NL Operations in the East Texas/North Louisiana Area, and BG does not then have a Secondee within the relevant Primary Department whose time is at least 50% allocated to such activities in the relevant area(s), BG will have a right to propose that a Secondee be placed into the available position before EXCO fills the position (and, if EXCO determines that such candidate is unsuitable, to propose a replacement candidate); provided, however the ultimate hiring decision for such position shall be made by EXCO in its sole discretion (provided that EXCO shall not unreasonably withhold consent to appoint the secondee recommended by BG and shall, in the exercise of its consent, give significant consideration to BG’s interest in placing secondees within the organization).

(iii)
At any one time, BG may place up to three (3) GDP Members for training purposes within the Company and/or EXCO (in its capacity as ET/NL Joint Development Operator in the East Texas/North Louisiana Area or Service Provider in the Appalachian Area) in support of Development Operations in the Appalachian Area or ET/NL Operations in the East Texas/North Louisiana Area, in each case within the Primary Department designated by BG. EXCO will reasonably consider requests by BG for additional GDP Members. BG will be responsible for salary, wages and other direct employment costs of GDP Members. Each GDP Member will be placed in accordance with the BG Secondment Agreement.

(iv)
At the request of BG or EXCO, if the ET/NL Operations in the East Texas/North Louisiana Area or the Development Operations in the Appalachian Area materially change from the applicable operations in existence on March 1, 2013, BG and EXCO will meet to discuss amendments to the secondment rights of this Section 2.11(g) given such change in circumstances.”
(x)
Section 2.11 shall be amended by adding the following subsection (h):
“(h)
If at any time the BG Affiliate Group possesses a Percentage Interest greater than 25% but does not possess a Participating Interest greater than 25% under the ET/NL JDA, then BG will have the right but not the obligation to maintain each Secondee position filled pursuant to Section 2.11(g)(i) where the time of such Secondee has been more than 50% allocable to activities relating to Development Operations in the Appalachian Area during the 12 months preceding a reduction in the Participating Interest of the BG Affiliate Group to 25% or less and BG shall have the continuing general right, subject to

Page 9


EXCO’s approval (such approval not to be unreasonably withheld) to second one or more of its or its Affiliates’ employees to the Company in each of the Primary Departments of the Company. If at any time the BG Affiliate Group possesses a Participating Interest greater than 25% under the ET/NL JDA but does not possess a Percentage Interest greater than 25%, then BG will have the right but not the obligation to maintain each Secondee position filled pursuant to Section 2.11(g)(i) where the time of such Secondee has been more than 50% allocable to activities relating to ET/NL Operations in the East Texas/North Louisiana Area during the 12 months preceding a reduction in the Participating Interest of the BG Affiliate Group to 25% or less.”
(y)
Section 2.11 shall be amended by adding the following subsection (i):
“(i)
Subject to Section 2.11(g)(i) and Section 2.11(g)(ii), if a position becomes available in one of the Primary Departments that predominantly supports Development Operations in the Appalachia Area and/or ET/NL Operations in the East Texas/North Louisiana Area and (i) the available position is at or above the level of supervisor or manager (but excluding officers and directors) within the Company or EXCO (in its capacity as ET/NL Joint Development Operator in the East Texas/North Louisiana Area or Service Provider in the Appalachian Area) or (ii) such position relates to an area in which BG has a vacancy in one of the positions described on Exhibit “C” (either because the position is described as ‘VACANT’ or because the identified individual vacated the position), then the Company or EXCO, as applicable, shall involve BG in the hiring decision regarding such position (or reallocation of an existing employee to such position) by submitting resumes of potential candidates to BG, by giving BG the opportunity to interview the candidate either (at BG’s option) in person in Dallas or remotely by phone or videoconference (provided that any such interview is conducted reasonably promptly by BG), and by involving BG in such other manner as BG may reasonably request; provided that BG shall not unreasonably delay or hinder the hiring process by EXCO. EXCO will reasonably consider BG requests for the placement of Secondees by BG into any such position (and, if EXCO determines that a candidate is unsuitable, to consider replacement candidates requested by BG) in addition to any rights that BG may have pursuant to Section 2.11(g)(i) and Section 2.11(g)(ii).”
(z)
Section 2.12 shall be amended by adding the following subsections (c), (d) and (e):
“(c)
For so long as EXCO is acting as Service Provider, EXCO shall actively involve BG in operations and activities which support Development Operations, including, without limitation, by providing a representative of BG the opportunity to participate in (or send another available BG representative to) organized pre-scheduled meetings relating to the Subject Oil and Gas Assets and/or Development Operations, including management

Page 10


team meetings, supply-chain meetings, organization or functional meetings, EHS meetings and contractor committee meetings.
(d)
For so long as EXCO is acting as Service Provider, EXCO shall provide employees and contractors of BG and its Affiliates with unrestricted, on-demand, on-site access during regular business hours to EXCO’s (and its Affiliates’) physical land records and electronic land management system (as of the 2014 Amendment Effective Date, such system is Excalibur and the applicable computer terminals accessing such system are located in Dallas, Texas) for the purposes of manipulating, reviewing and working with land records (including running queries and producing reports and summaries) related to Subject Oil and Gas Assets owned by BG or its Affiliates. At BG’s cost and expense, EXCO shall cooperate with efforts by BG to remotely access EXCO’s (and its Affiliates’) land data and information to the extent related to such Subject Oil and Gas Assets. Notwithstanding the foregoing, EXCO shall only be required to provide access to any such electronic land management system to the extent that (i) providing such access would not violate the provisions of any applicable software or other license (if necessary, after reasonable inquiry by EXCO to the licensor seeking permission for such access), (ii) BG obtains any applicable software or other license that may be required in connection with such access (and BG acknowledges that none of EXCO or its Affiliates will be responsible for obtaining any such license for BG), and (iii) such land data and information held in electronic form related to such Subject Oil and Gas Assets is capable of being separated from land data and information held in electronic form that is related to other assets of EXCO or its Affiliates; provided that in each case of (i), (ii) and (iii), EXCO shall use its reasonable efforts to assist in accomplishing such requirement, but in no event shall EXCO or its Affiliates be required to incur any third party costs or pay any fees in connection therewith that BG is unwilling to reimburse.
(e)
To assist BG with any asset disposition analysis or efforts relating to its disposition of Subject Oil and Gas Assets, for so long as EXCO is acting as Service Provider, EXCO shall, at BG’s sole cost and expense and without any liability of EXCO or its Affiliates whatsoever (except for liabilities arising due to the willful misconduct of EXCO or its Affiliates), provide support services for any such asset disposition analysis or efforts including, without limitation, assisting with data presentation, providing responses to data requests by BG, providing access to records and data for third party due diligence, and gathering data for purchase and sale agreement representation and warranties; provided that no employee of EXCO or its Affiliates shall be required to make any presentations to potential purchasers. BG shall indemnify EXCO and its Affiliates and their respective employees and representatives for any and all claims and liabilities arising out of or related to any services provided pursuant to this Section in connection with any such

Page 11


proposed asset disposition, except for claims arising due to the willful misconduct of EXCO or its Affiliates.”
(aa)
Section 2.13(f) shall be amended by deleting the phrase “the Vice President of EHS shall establish” and replacing it with the phrase “the officer of the Company principally responsible for the Company’s EHS functions shall establish”.
(bb)     Section 2.15(a) shall be amended by:
(1) changing the Section references of Sections 2.15(a)(xiv) and 2.15(a)(xv) to Sections 2.15(a)(xx) and 2.15(a)(xxi), respectively, and adding the phrase “without being limited by the duplication, specificity or limitations of any other items listed in this Section 2.15(a),” at the beginning of Section 2.15(a)(xx),
(2) adding the following Sections 2.15(a)(xiv), 2.15(a)(xv), 2.15(a)(xvi), 2.15(a)(xvii), 2.15(a)(xviii) and 2.15(a)(xix):
“(xiv)
within three (3) weeks from the end of each Calendar Quarter, a schedule showing the working interest and net revenue interests (including net working interest, royalty, overriding royalty, etc.) of BG (and its Affiliates) in each well (showing separately any percentage interest held indirectly by BG (and its Affiliates) as a Member of the Company or member of some other Person) as of the end of such Calendar Quarter;
(xv)
on or before the 15th of each month preceding an obligation or expiration month, the monthly lease maintenance calendars (payments, extensions and expirations) with land recommendations;
(xvi)
copies of all raw microseismic and seismic data, including reprocessing and interpretative data, analysis and reports for the Appalachia Area that (A) are in the possession of the Company or Service Provider, as applicable, (B) are not subject to Third Party confidentiality restrictions that have not been waived and (C) have been generated by EXCO or by a Third Party on behalf of the Company or Service Provider;
(xvii)
geographic information system data and shape files for the Appalachia Area that (A) are in the possession of the Company or Service Provider, as applicable, (B) are not subject to Third Party confidentiality restrictions that have not been waived and (C) have been generated by EXCO or by a Third Party on behalf of the Company or Service Provider, including any data layers or points associated with shape files such as lease expirations, depth severances and competitor drilling locations;

Page 12


(xviii)
at the reasonable request of a Participating Member, a copy of general land data (as currently produced or compiled in the general course of business), inclusive of budget projections data, quarterly updates of activities associated with spending under land AFEs, division of interest calculations, quarterly acreage reports or title curative for the Appalachian Area that are in the possession of the Company or Service Provider, as applicable, are not subject to Third Party confidentiality restrictions that have not been waived and have been generated by EXCO or by a Third Party on behalf of the Company or Service Provider;
(xix)
at the reasonable request of a Participating Member that includes the applicable data query or queries, EXCO shall, within 30 days after receiving such request, provide such Participating Member with the results of specific data queries on EXCO’s land systems and databases, provided that the result of such queries provided to such Participating Member shall be limited to only those properties in which such Participating Member and EXCO own an interest under this Agreement;”
(cc)
Section 2.15(b)(i) shall be amended by deleting the phrase “within 24 hours of the Vice President of HSSE receiving notice thereof” and replacing it with the phrase “within 24 hours of the officer of the Company principally responsible for the Company’s EHS functions receiving notice thereof”.
(dd)     Section 2.15(c) shall be amended by adding the following to the end of the provision:
In addition, Company shall provide each Member with notice of any written disputes which affect, or reasonably may affect, with respect to any Development Party that is an Affiliate of such Member, such Development Party’s leasehold or other property interest in the Subject Oil and Gas Assets. Such Member shall be kept informed of material changes in the progress of any such disputes and, at the request of a Member, Company (or Service Provider, as applicable) shall provide Member with copies of all pleadings, demand letters, or other material correspondences relating to any such dispute and make available personnel familiar with such disputes to assist with Member’s analysis and understanding of the dispute and to reasonably consider any views Member may have on the handling of such dispute.
(ee)
Section 2.16(b) shall be amended by replacing the phrase “for the purpose of observing operations or conducting HSSE and asset integrity audits” with the phrase “for the purpose of observing operations and conducting general audit activities, including conducting EHS and asset integrity audits”.
(ff)     Section 3.1 shall be amended by adding the following subsection (f):

Page 13


“(f)
Within ten (10) days after the end of each Calendar Month, Company shall provide each Member with a list of Development Operations Contracts relating to Development Operations entered into during the preceding Calendar Month that can reasonably be expected to result in aggregate payment to the counterparty of more than two hundred fifty thousand dollars (US$250,000), together with the status of any negotiations or tender processes relating to any unexecuted Development Operations Contracts as of the end of the Calendar Month.”
(gg)
Section 13.3 shall be amended by deleting it in its entirety and replacing it with the following:
Notices . All notices and communications required or permitted to be given hereunder shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission (provided any such facsimile transmission is confirmed either orally or by written confirmation), addressed to the appropriate Party at the address for such Party shown below or at such other address as such Party shall have theretofore designated by written notice delivered to the Party giving such notice:
If to the Company:
EXCO Resources (PA), LLC
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President and General Manager
Telephone: (214) 368-2084
Fax: (214) 368-8754

If to EXCO:
EXCO Holding (PA), Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention:    President
Telephone:    (214) 368-2084
Fax:    (214) 368-8754

with a copy to:
EXCO Resources, Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention:     William L. Boeing, Vice President,
General Counsel and Secretary

Page 14


Telephone:    (214) 368-2084
Fax:    (214) 706-3409

If to BG:
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002

Attention: Roger Coe
Telephone: (713) 599-4000
Fax: (713) 599-4250
with a copy to:
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
Attention:    Chris Migura, Principal Counsel
Telephone:    (713) 599-4000
Fax:    (713) 599-4250
Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile transmission during normal business hours (or, if not sent transmitted during normal business hours, on the next business day), or upon actual receipt by the addressee after such notice has been deposited in the United States Mail, as the case may be. Any notice given to a Credit Facility Secured Party in accordance with the notice information supplied with respect to such Credit Facility Secured Party shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile transmission during normal business hours, or upon actual receipt by the addressee after such notice has been deposited in the United States Mail, as the case may be. The Parties may change the address, telephone numbers, and facsimile numbers to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 13.3.”
(hh)
Each use of the term “HSSE” throughout the LLC Agreement shall be deleted and replaced with the term “EHS”. The defined terms in Appendix I previously beginning with the term “HSSE” and now beginning with the term “EHS” shall be reordered in the appropriate alphabetic locations.
(ii)
The LLC Agreement shall be amended by adding Exhibit “A-1” attached hereto immediately following Exhibit “A” of the LLC Agreement, as Exhibit “A-1” to the LLC Agreement.
(jj)
The LLC Agreement shall be amended by attaching Exhibit “C” attached hereto as Exhibit “C” to the LLC Agreement.

Page 15


3.
Land Leasing Protocol. Without determining whether or not such protocol was ever in effect, but for the avoidance of doubt, the “EXCO Resources (PA), LLC Land Leasing Protocol,” shall be void and without effect as of the Effective Date. Accordingly, the Company shall not make land or oil and gas asset acquisitions without the approval of the BG Member and the EXCO Member; provided, however, that the approval of any such acquisition by the Management Board in accordance with the Management Board voting provisions and applicable Board Member voting thresholds, in each case as contained in the LLC Agreement, shall be considered approval by the BG Member and the EXCO Member, respectively, for the purposes of this provision.
4.
Application of Certain Provisions. The terms of Sections 12.1, 12.2, 13.2, 13.3, 13.4, 13.5, 13.7, 13.8, 13.9, 13.10, 13.11, 13.12, 13.13(a), 13.14, 13.15 and 13.20 of the LLC Agreement are incorporated herein by reference as if set out in full herein.
5.
Ratification. Except as amended herein, the terms and conditions of the LLC Agreement shall remain in full force and effect. Any and all references to the LLC Agreement shall hereafter refer to the LLC Agreement as amended by this Amendment.
[ Signature page follows ]


Page 16

Exhibit 10.22

Execution Version


IN WITNESS WHEREOF, the Parties have executed this Amendment on the Execution Date.

COMPANY:
 
EXCO RESOURCES (PA), LLC
 
 


 
 
By: /s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel

 
 
 
 
 
 
MEMBERS:
 
BG US PRODUCTION COMPANY, LLC

 
 
 
 
 
By: /s/ ROGER COE
Name: Roger Coe
Title: Vice President
 
 
 
 
 
EXCO HOLDING (PA), INC

 
 
 
 
 
By: /s/ ROGER COE
Name: Roger Coe
Title: Vice President
 
 
 
SOLELY FOR THE PURPOSES OF AMENDMENTS TO SECTION 2.11:
 
EXCO OPERATING COMPANY, LP
 
 
By: EXCO Partners OLP GP, LLC,
   Its general partner


 
 
By: /s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel



Exhibit 10.24

Execution Version

AMENDMENT TO THE SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF APPALACHIA MIDSTREAM, LLC (N/K/A EXCO APPALACHIA MIDSTREAM, LLC)
This Amendment to the Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC (the “ Amendment ”) is entered into on October 14, 2014 (the “ Execution Date ”) between EXCO Appalachia Midstream, LLC (f/k/a Appalachia Midstream, LLC), a Delaware limited liability company (the “ Company ”), BG US Production Company, LLC, a Delaware limited liability company (“ BG Member ”) and EXCO Holding (PA), Inc., a Delaware corporation (“ EXCO Member ”). BG Member, EXCO Member and Company are referred to herein collectively as the “ Parties ” and each individually as “ Party .”
RECITALS
WHEREAS, the Parties entered into that certain Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC (n/k/a EXCO Appalachia Midstream, LLC), LLC dated June 1, 2010 (the “ LLC Agreement ”); and
WHEREAS, the Parties desire to amend the LLC Agreement in accordance with the provisions of this Amendment;
NOW, THEREFORE, in consideration of the mutual promises contained in this Amendment and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:
1.
Definitions and References. Capitalized terms used in this Amendment and not otherwise defined herein have the meanings given such terms in the LLC Agreement. Sections, Articles, Appendices, Exhibits, Schedules and subsections referred to herein refer to such Sections, Articles, Appendices, Exhibits, Schedules and subsections of the LLC Agreement unless the context expressly states otherwise.
2.
LLC Agreement Amendment . The LLC Agreement is hereby amended as follows:
(a)
Section 5.1(c)(ii) shall be amended by deleting the phrase “(the Management Board shall use commercially reasonable efforts to make such delegations within thirty (30) days of the Closing Date)” in its entirety.
(b)
Section 5.1(c)(xx) shall be amended by deleting the phrase “established by the Vice President of Finance and Business Services” and replacing it with the phrase “established by the officer of the Company principally responsible for the Company’s financial matters”.
(c)
Section 5.2 shall be amended by deleting the first two sentences and replacing them with the following:

Page 1


“The Management Board shall consist of four (4) Board Members. Each of BG Affiliate Group and EXCO Affiliate Group shall be entitled to appoint two (2) Board Members and two (2) alternate Board Members.”
(d)
Section 5.3(d) shall be amended by deleting it in its entirety and replacing it with the following:
“(d)    [omitted];”
(e)
Section 5.3(e) shall be amended by deleting it in its entirety and replacing it with the following:
“(e)    [omitted];”
(f)
Section 5.3(f) shall be amended by deleting it in its entirety and replacing it with the following:
“The Management Board shall meet (i) upon at least fifteen (15) days advance notice by either BG Affiliate Group or EXCO Affiliate Group or (ii) whenever at least one of the Board Members or alternate Board Members from each of the BG Affiliate Group and the EXCO Affiliate Group are present and agree to hold such a meeting, without any requirement for advance notice or delivery of an agenda. If any Member or Board Member so requests, any meeting of the Management Board, or the consideration of any proposal by the Management Board at a meeting, shall be deferred for up to fifteen (15) days from the date on which such meeting is requested or such proposal tendered, if the meeting is held or proposal tendered with less than fifteen (15) days notice to all Member. So long as both the BG Affiliate Group and the EXCO Affiliate Group hold interests in the ET/NL JDA, the Management Board will use commercially reasonable efforts to hold its meetings immediately following meetings of the ET/NL OpCom. All meetings of the Management Board and each subcommittee shall be held in the principal offices of the Company, or elsewhere as the Management Board or such subcommittee may mutually decide which alternate location may be within or outside the State of Delaware.”
(g)
Section 5.3(g) shall be amended by deleting it in its entirety and replacing the following:
“(g)    [omitted];”
(h)
Section 5.3(i) shall be amended by deleting the first sentence and replacing it with the following:
“The secretary of the Management Board shall provide each Member with a copy of the Management Board meeting minutes relating to each decision made by the Management Board during a Management Board meeting within fifteen (15) Business Days after the end of the meeting.”

Page 2


(i)
Section 5.3(o) shall be amended by deleting it in its entirety and replacing it with the following:
“(o)
All notices and communications required or permitted to be given to the Board Members and the President and General Manager pursuant to this Article 5 shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission, or by pdf e-mail (provided that any such facsimile transmission or e-mail transmission is confirmed either orally or by written confirmation), addressed to the appropriate Member at the address for such Member shown below or at such other address as such Member shall have theretofore designated by written notice delivered to the Member giving such notice:

Page 3


If to the President and General Manager:
 
Appalachia Midstream, LLC
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President and General Manager
Telephone: (214) 368-2084
Fax: (214) 368-8754

If to the EXCO Affiliate Group:
 
EXCO Holding (PA), Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President
Telephone: (214) 368-2084
Fax: (214) 368-8754
With a copy to:

EXCO Resources, Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: William L. Boeing, General Counsel
Telephone: (214) 368-2084
Fax: (214) 706-3409
E-mail: lboeing@excoresources.com

If to the BG Affiliate Group:
 
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
 
Attention: Roger Coe
Telephone: (713) 599-4000
Fax: (713) 599-4250
E-mail: roger.coe@bg-group.com

BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
 
Attention: Chris Migura, Principal Counsel
Telephone: (713) 599-4000
Fax: (713) 599-4250
E-mail: chris.migura@bg-group.com


Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile transmission or email during normal business hours (or, if not sent transmitted during normal business hours, on the next business day), or upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or

Page 4


deposited in the United States Mail, as the case may be. The Members may change the address, telephone numbers, facsimile numbers and email addresses to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 5.3(o).”
(j)
Section 5.3 shall be amended by adding the following subsection (p):
“(p)
In lieu of a vote taken at a meeting or to a proposal distributed in accordance with Section 5.3(j), a written resolution of the Management Board will be effective to evidence the approval of the Management Board upon the signature of at least one of the Board Members or alternate Board Members from each Group.”
(k)
Section 5.9(a)(i) shall be amended by deleting it in its entirety and replacing it with the following:
“(i)
The Management Board shall have the power to elect, delegate authority to, and remove such officers of the Company and the other Company Group Members as the Management Board may from time to time deem appropriate; provided, however, that each officer appointee of the Company shall serve a three (3) year term commencing as of the date of the appointment of such officer, subject to each officer’s appointment being subject to an annual ratification vote by the Management Board. After any Management Board vote not to ratify the appointment of any officer, the Management Board shall, as soon as reasonably practicable thereafter, appoint a replacement officer, which replacement officer shall serve a three (3) year term (subject to annual ratification votes as described in this Section 5.9(a)(i)).”
(l)
Section 5.9(a)(ii) shall be amended by deleting it in its entirety and replacing it with the following:
“(ii)
[omitted].”
(m)
Section 5.9(b)(i) shall be amended by deleting the second sentence of such Section.
(n)
Section 5.9(b)(ii) shall be amended by deleting it in its entirety and replacing it with the following:
“(ii)    [omitted].”
(o)
Section 5.9(b)(iii) shall be amended by deleting it in its entirety and replacing it with the following:
“(iii)    [omitted].”
(p)
Section 5.9(b)(iv) shall be amended by deleting it in its entirety and replacing it with the following:

Page 5


“(iv)    [omitted].”
(q)
Section 5.9(b)(v) shall be amended by deleting it in its entirety and replacing it with the following:
“(v)    [omitted].”
(r)
Section 5.9(b)(vi) shall be amended by deleting it in its entirety and replacing it with the following:
“(vi)    [omitted].”
(s)
Section 5.9(b)(vii) shall be amended by deleting it in its entirety and replacing it with the following:
“(vii)    [omitted].”
(t)
Section 5.9(c) shall be amended by deleting the first sentence of such section.
(u)
Section 5.10 shall be amended by adding the following subsections (d) and (e):
“(d)    For so long as EXCO is acting as Service Provider, EXCO shall actively involve BG Member in operations and activities which support Midstream Activities, including, without limitation, by providing a representative of BG Member the opportunity to participate in (or send another available BG Member representative to) organized pre-scheduled meetings relating to the Midstream Assets and/or Midstream Activities, including management team meetings, supply-chain meetings, organization or functional meetings, EHS meetings and contractor committee meetings.
(e)    To assist BG Member with any asset disposition analysis or efforts relating to its disposition of Midstream Assets, for so long as EXCO is acting as Service Provider, EXCO shall, at BG Member’s sole cost and expense and without any liability of EXCO or its Affiliates whatsoever (except for liabilities arising due to the willful misconduct of EXCO or its Affiliates), provide support services for any such asset disposition analysis or efforts including, without limitation, assisting with data presentation, providing responses to data requests by BG Member, providing access to records and data for third party diligence, and gathering data for purchase and sale agreement representation and warranties; provided that no employee of EXCO or its Affiliates shall be required to make any presentation to potential purchasers. BG Member shall indemnify EXCO and its Affiliates, employees and representatives for any and all claims and liabilities arising out of or related to any services provided pursuant to this Section in connection with any such proposed asset disposition, except for claims arising due to the willful misconduct of EXCO or its Affiliates.”
(v)
Section 5.12(b)(i) shall be amended by deleting the phrase “within 24 hours of the Vice President of HSSE receiving notice thereof” and replacing it with the phrase

Page 6


“within 24 hours of the officer of the Company principally responsible for the Company’s EHS functions receiving notice thereof”.
(w)
Section 5.12(b)(iv) shall be amended by replacing the phrase “for the purpose of observing operations or conducting HSSE and asset integrity audits” with the phrase “for the purpose of observing operations and conducting general audit activities, including conducting EHS and asset integrity audits”.
(x)
Section 6.4 shall be amended by adding the following subsection (e):
“(e)    Within ten (10) days after the end of each Calendar Month, Company shall provide each Member with a list of Company Group O&M Contracts that can reasonably be expected to result in aggregate payment to the counterparty of more than two hundred and fifty thousand dollars (US$250,000), together with the status of any negotiations or tender process relating to any unexecuted Company Group O&M Contracts as of the end of the Calendar Month.”
(y)
Section 13.1(a) shall be amended by deleting the phrase “Each Non-Acquiring Member shall have a period of sixty (60) days after receipt of the Offer Notice” and replacing it with the phrase “Each Non-Acquiring Member shall have until the end of the AMI Election Period”.
(z)
Section 13.1(f) shall be amended by deleting the phrase “within thirty (30) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Member’s statement of the Cash Value” and replacing it with the phrase “within twenty (20) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Member’s statement of the Cash Value”.
(aa)
Section 16.2 shall be amended by deleting it in its entirety and replacing it with the following:
Notices . All notices and communications required or permitted to be given hereunder shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission (provided any such facsimile transmission is confirmed either orally or by written confirmation), addressed to the appropriate Party at the address for such Party shown below or at such other address as such Party shall have theretofore designated by written notice delivered to the Party giving such notice:
If to the Company:
Appalachia Midstream, LLC
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President and General Manager

Page 7


Telephone: (214) 368-2084
Fax: (214) 368-8754

If to BG Member:
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002

Attention: Roger Coe
Telephone: (713) 599-4000
Fax: (713) 599-4250
with a copy to:
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
Attention:    Chris Migura, Principal Counsel
Telephone:    (713) 599-4000
Fax:    (713) 599-4250

If to EXCO Member:
EXCO Holding (PA), Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention:    President
Telephone:    (214) 368-2084
Fax:    (214) 368-8754

with a copy to:
EXCO Resources, Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention:     William L. Boeing, Vice President,
General Counsel, and Secretary
Telephone:    (214) 368-2084
Fax:    (214) 706-3409
Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile transmission during normal business hours (or, if not sent transmitted during normal business hours, on the next business day), or upon actual receipt by the addressee after such notice has been deposited in the United States Mail, as the case may be. Any

Page 8


notice given to a Credit Facility Secured Party in accordance with the notice information supplied with respect to such Credit Facility Secured Party shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile transmission during normal business hours, or upon actual receipt by the addressee after such notice has been deposited in the United States Mail, as the case may be. The Parties may change the address, telephone numbers, and facsimile numbers to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 16.2.”
(bb)
Each use of the term “HSSE” throughout the LLC Agreement shall be deleted and replaced with the term “EHS”. The defined terms in Appendix I previously beginning with the term “HSSE” and now beginning with the term “EHS” shall be reordered in the appropriate alphabetic locations.
(cc)
Appendix I shall be amended by deleting the following defined terms in their entirety:
HSSE ”;
Vice President of Finance and Business Services ”;
Vice President of Asset Integrity ”;
Vice President of Commercial Operations and Business Development ”;
Vice President of Engineering and Construction ”;
Vice President of HSSE ”; and
Vice President of Operations and Maintenance ”.
(dd)
Appendix I shall be amended by adding the following definitions in their correct alphabetic location:
AMI Election Period ” shall mean (a) for Offered Interests with a value (in any one or related series of transactions) of less than five hundred thousand dollars (US$500,000), from receipt of the Offer Notice until thirty (30) days from receipt of the Offer Notice, extended for a period of five (5) days following determination of the Cash Value (if applicable), and (b) for all other Offered Interests, the sixty (60) days from receipt of the Offer Notice and determination of the Cash Value (if applicable).
EHS ” means Environmental, Health and Safety.
ET/NL JDA ” means the Joint Development Agreement, dated August 14, 2009 between BG Member, EXCO and EXCO Production Company, LP (which entity merged into EXCO and terminated its separate existence) as amended by amendment

Page 9


dated May 19, 2010, by amendment dated February 1, 2011, by amendment dated February 14, 2014 and by amendment date October 14, 2014.
ET/NL OpCom ” shall have the meaning given to the term “Operating Committee” in the ET/NL JDA.
EXCO ” means EXCO Operating Company, LP, a Delaware limited partnership.
Secondee ” or “ secondee ” means any employee of a Member or an Affiliate of a Member seconded into the organization of Company or Service Provider in accordance with this Agreement.
Service Provider ” means EXCO when EXCO and/or its Affiliates provide substantial personnel services toward conducting Midstream Activities in the AMI Area either pursuant to Services Agreement(s) with the Company and/or secondment agreement(s) with the Company, which, in the case of secondment agreement(s) with the Company, means that such secondment agreement(s) entitle EXCO and/or its Affiliates to place Persons with the Company as secondees to the extent that the responsibilities of such Persons, when viewed as a whole, entitle such Persons to exert substantial management or control over the Company.
3.
Application of Certain Provisions. The terms of Sections 15.1, 15.2, 16.1, 16.2, 16.3, 16.4, 16.6, 16.7, 16.8, 16.9, 16.10, 16.11, 16.12(a), 16.13 and 16.14 of the LLC Agreement are incorporated herein by reference as if set out in full herein.
4.
Ratification. Except as amended herein, the terms and conditions of the LLC Agreement shall remain in full force and effect. Any and all references to the LLC Agreement shall hereafter refer to the LLC Agreement as amended by this Amendment.
[ Signature page follows ]

Page 10



IN WITNESS WHEREOF, the Parties have executed this Amendment on the Execution Date.

COMPANY:
 
EXCO APPALACHIA MIDSTREAM, LLC
 
 


 
 
By: /s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel

 
 
 
 
 
 
MEMBERS:
 
BG US PRODUCTION COMPANY, LLC

 
 
 
 
 
By: /s/ ROGER COE
Name: Roger Coe
Title: Vice President
 
 
 
 
 
EXCO HOLDING (PA), INC

 
 
 
 
 
By: /s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel

 
 
 


Signature Page to LLC Agreement Amendment


EXHIBIT 21.1

LIST OF SUBSIDIARIES OF
EXCO RESOURCES, INC.

Name of Subsidiary

 
State of    
Incorporation

EXCO Services, Inc.
 
Delaware
EXCO Equipment Leasing, LLC
 
Delaware
EXCO Partners GP, LLC
 
Delaware
EXCO GP Partners Old, LP
 
Delaware
EXCO Partners OLP GP, LLC
 
Delaware
EXCO Operating Company, LP
 
Delaware
EXCO Mid-Continent MLP, LLC
 
Delaware
EXCO Holding (PA), Inc.
 
Delaware
EXCO Production Company (PA), LLC
 
Delaware
EXCO Production Company (WV), LLC
 
Delaware
EXCO Resources (XA), LLC
 
Delaware
EXCO Holding MLP, Inc.
 
Texas
EXCO Land Company, LLC
 
Delaware





Exhibit 23.1


Consent of Independent Registered Public Accounting Firm
The Board of Directors
EXCO Resources, Inc.:
We consent to the incorporation by reference in the registration statement on Form S-8 (Nos. 333-177900, 333-159930, 333-156086, 333-132551, 333-146376 and 333-189262) and Form S-3 (Nos. 333-169253, 333-192898, 333-193660 and 333-195126) of EXCO Resources, Inc. and subsidiaries (the Company) of our report dated February 25, 2015, with respect to the consolidated balance sheets of EXCO Resources, Inc. and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, cash flows, and changes in shareholders’ equity for each of the years in the three-year period ended December 31, 2014, and the effectiveness of internal control over financial reporting as of December 31, 2014, which report appears in the December 31, 2014 annual report on Form 10‑K of EXCO Resources, Inc.
/s/ KPMG LLP
KPMG LLP
Dallas, Texas
February 25, 2015



Exhibit 23.2

LEE KEELING AND ASSOCIATES, INC.
PETROLEUM CONSULTANTS
 
 
TULSA OFFICE
First Place Tower
15 East Fifth Street • Suite 3500
Tulsa, Oklahoma 74103-4350
(918) 587-5521 • Fax: (918) 587-2881
www.lkaengineers.com
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
As independent petroleum engineers, Lee Keeling and Associates, Inc. hereby consents to all references to our firm included in or made part of this EXCO Resources, Inc. Annual Report on Form 10-K for the year ended December 31, 2014 and further consents to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-159930, 333-156086, 333-132551, 333-146376, 333-177900 and 333-189262) and on Form S-3 (Nos. 333-169253, 333-192898, 333-193660 and 333-195126) of EXCO Resources, Inc. of information from our reserve reports dated January 6, 2015, January 8, 2014 and January 10, 2013 on the estimated proved oil and natural gas reserve quantities of EXCO Resources, Inc. and certain of its consolidated subsidiaries presented as of December 31, 2014, 2013 and 2012.
 
/s/ Lee Keeling and Associates, Inc.        
LEE KEELING AND ASSOCIATES, INC.
Tulsa, Oklahoma
February 25, 2015


Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the incorporation by reference in the Registration Statements (Nos. 333-159930, 333-156086, 333-132551, 333-146376, 333-177900 and 333-189262) on Form S-8 and on Form S-3 (Nos. 333-169253, 333-192898, 333-193660 and 333-195126) of EXCO Resources, Inc. (the “Company”) of the reference to Netherland, Sewell & Associates, Inc. and the inclusion of our reports dated January 19, 2015, January 9, 2014 and February 21, 2013 in the Annual Report on Form 10-K for the year ended December 31, 2014, of the Company and its subsidiaries, filed with the Securities and Exchange Commission.

 
 
NETHERLAND, SEWELL & ASSOCIATES, INC.
 
 
 
 
 
By:
/s/ C.H. (Scott) Rees III
 
 
 
C.H. (Scott) Rees III, P.E.
 
 
 
Chairman and Chief Executive Officer
 
 
 
 
 
Dallas, Texas
 
 
 
February 25, 2015
 
 
 
 
 
 
 
 
 
 
 


 Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.







TBPE REGISTERED ENGINEERING FIRM F-1580
FAX (713) 651-0849
1100 LOUISIANA STREET SUITE 4600 HOUSTON, TEXAS 77002-5294
TELEPHONE (713) 651-9191

Exhibit 23.4



CONSENT OF RYDER SCOTT COMPANY, L.P.

We have issued our report dated January 19, 2015 on estimates of proved reserves, future production and income attributable to certain leasehold interest of EXCO Resources, Inc. (“EXCO”) as of December 31, 2014. As independent oil and gas consultants, we hereby consent to the inclusion of our report and the information contained therein and information from our prior reserve reports referenced in this Annual Report on Form 10-K of EXCO (this “Annual Report”) and to all references to our firm in this Annual Report. We hereby also consent to the incorporation by reference of such reports and the information contained therein in the Registration Statements of EXCO on Forms S-8 (File Nos. 333-159930, 333-156086, 333-132551, 333-146736, 333-177900 and 333-189262) and on Form S-3 (File Nos. 333-169253, 333-192898, 333-193660 and 333-195126).
 
 
 
 
 
 
 
 
 
 
/s/ Ryder Scott Company, L.P.
 
 
 
 
 
 
 
RYDER SCOTT COMPANY, L.P.
 
 
 
TBPE Firm Registration No. F-1580

Houston, Texas
February 25, 2015

SUITE 600, 1015 4TH STREET, S.W.
CALGARY, ALBERTA T2R 1J4
TEL (403) 262-2799
FAX (403) 262-2790
 621 17TH STREET, SUITE 1550
 DENVER, COLORADO 80293-1501
TEL (303) 623-9147
FAX (303) 623-4258



Exhibit 31.1
CERTIFICATION
I, Harold L. Hickey, the Principal Executive Officer of EXCO Resources, Inc., certify that:
1.
I have reviewed this Annual Report on Form 10-K of EXCO Resources, Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.  

Date:
February 25, 2015
/s/ Harold L. Hickey
 
 
Harold L. Hickey
 
 
President and Chief Operating Officer






Exhibit 31.2
CERTIFICATION
I, Richard A. Burnett, the Principal Financial Officer of EXCO Resources, Inc., certify that:
1.
I have reviewed this Annual Report on Form 10-K of EXCO Resources, Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:
February 25, 2015
/s/ Richard A. Burnett
 
 
Richard A. Burnett
 
 
Vice President, Chief Financial Officer and Chief Accounting Officer






Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), each of the undersigned officers of EXCO Resources, Inc. (the “Company”) in their capacity as Principal Executive Officer and Principal Financial Officer, respectively, does hereby certify, to such officer’s knowledge, that:
The Annual Report on Form 10-K for the year ended December 31, 2014 (the “Form 10-K”) of the Company fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended, and the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company as of, and for, the periods presented in the Form 10-K.

Date:
February 25, 2015
/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

The foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.





Exhibit 99.1
L EE K EELING AND A SSOCIATES , I NC .
P ETROLEUM C ONSULTANTS
First Place Tower
15 East Fifth Street Suite 3500
Tulsa, Oklahoma 74103-4350
(918) 587-5521 Fax: (918) 587-2881
www.lkaengineers.com


January 5, 2015


EXCO Resources (PA), LLC
EXCO Resources (WV), LLC
12377 Merit Drive, Suite 1700
Dallas, Texas 75251

Attention: Mr. Harold L. Hickey
 
 
Re:
Estimated Proved Reserves and
 
 
 
 
Future Net Cash Flow
 
 
 
 
Constant Pricing
Gentlemen:

In accordance with your request, we have prepared an estimate of the proved reserves and future net cash flow attributable to the interests owned by EXCO Resources (PA), LLC and EXCO Resources (WV), LLC (hereinafter collectively referred to as “EXCO”) located in the states of Kentucky, Pennsylvania, Virginia, and West Virginia. The reserves estimated by us for EXCO represent four per cent (4%) of EXCO Resources, Inc. reserves. This report was prepared according to the Securities and Exchange Commission (SEC) guidelines as published in the Federal Register January 14, 2009. The effective date of our estimate is December 31, 2014, and the results are summarized as follows:

 
 
ESTIMATED REMAINING
FUTURE NET CASH FLOW
 
 
NET RESERVES
 
 
Present Worth
 
 
 
Oil
 
Gas
 
Net Equiv.
 
 
Total
 
Disc. @ 10%
RESERVE CLASSIFICATION
 
 
(MBBL)
 
(MMCF)
 
(MMCFE) (1)
 
 
(M$)
 
(M$)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved Developed
 
 
 
 
 
 
 
 
 
 
 
 
 
Producing
 
 
129.753
 
43,980.523

 
44,759.047
 
 
90,601.125
 
46,456.309
 
Non-Producing
 
 
0.269
 
294.931

 
296.544
 
 
465.693
 
232.158
 
Behind-Pipe
 
 
-
 
1,135.394

 
1,135.394
 
 
3,804.779
 
527.946
 
Sub-Total
 
 
130.022
 
45,410.848

 
46,190.985
 
 
94,871.597
 
47,216.413
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved Undeveloped
 
 
-
 
-
 
-
 
 
-
 
-
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL PROVED RESERVES
 
 
130.022
 
45,410.848

 
46,190.985
 
 
94,871.597
 
47,216.413
 
Notes:
 
 
 
 
 
 
 
 
 
 
 
 
 
(1)MMCFE-one million cubic feet equivalent, calculated by converting one barrel of oil to six MCF of natural gas.
 
 
 
 
 
 
 
 
 
 






Future net cash flow is the amount, exclusive of federal and state income taxes, which will accrue to the subject interests from continued operation of the properties to depletion. It should not be construed as a fair market or trading value. No provision has been made for the cost of plugging and abandoning the properties.

No attempt has been made to quantify or otherwise account for any accumulative gas production imbalances that may exist. Likewise, no attempt has been made to determine whether the wells and facilities are in compliance with various governmental regulations. Accordingly, no costs have been included in the event the wells and facilities are not in compliance.

CLASSIFICATION OF RESERVES

Reserves assigned to the various leases and/or wells have been classified as either “proved developed” or “proved undeveloped” in accordance with the definitions of the proved reserves as promulgated by the Securities and Exchange Commission. These are as follows:

Proved Developed Oil and Gas Reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Oil and Gas Reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Proved Developed Oil and Gas Reserves attributed to the subject leases have been further classified as “proved developed producing,” “proved developed non-producing” and “proved developed behind-pipe.”

Proved Developed Producing Reserves are those reserves expected to be recovered from currently producing zones under continuation of present operating methods.

Proved Developed Non-Producing Reserves are those reserves expected to be recovered from zones that have been completed and tested but are not yet producing due to situations including, but not limited to, lack of market, minor completion problems that are expected to be corrected, or reserves expected from future stimulation treatments based on analogy to nearby wells.

Proved Developed Behind-Pipe Reserves are those reserves currently behind the pipe in existing wells that are considered proved by virtue of successful testing or production in offsetting wells.


ESTIMATION OF RESERVES

The majority of the subject properties have been producing for a considerable length of time. The estimation of reserves for these wells has been based on the extrapolation of the existing historic production decline curves and/or pressure decline trends to economic limits or abandonment pressures.






Reserves anticipated from recently completed or new wells were based upon volumetric calculations or analogy with similar properties, which are producing from the same horizons in the respective areas. Structural position, net pay thickness, well productivity, gas-oil ratios, water production, pressures, and other pertinent factors were considered in the estimations of these reserves.

Reserves assigned to behind-pipe zones have been estimated based on volumetric calculations and/or analogy with other wells in the area producing from the same horizon.

FUTURE NET CASH FLOW

Oil Income and Prices

Income from the sale of oil was estimated based on the unweighted average price for West Texas Intermediate Cushing Oil, for the first day of each month for January through December of 2014, as provided by the staff of EXCO. That computed reference price of $94.99 per barrel was held constant throughout the life of each lease. The reference price was adjusted for historical differentials between posted prices and actual field prices to reflect quality, transportation fees and regional price differences. The weighted average price for oil over the life of the properties was $90.506 per barrel.

Gas Income and Prices

Income from the sale of gas was estimated based on the unweighted average price for natural gas sold at Henry Hub, the first day of each month for January through December of 2014, as provided by staff of EXCO. That computed reference price of $4.35 per MMBTU was held constant throughout the life of each lease. The reference price was adjusted for BTU content, basis differentials, marketing, and transportation costs. The weighted average price for natural gas over the life of the properties was $4.217 per MMBTU.

Operating Expenses

Operating expenses were based upon actual operating costs, including appropriate overhead expenses, charged by EXCO or the respective operators, as supplied by the staff of EXCO. All expenses were held constant throughout the life of each lease.

Future Expenses

Provisions have been made for future expenses required for recompletion and drilling. These costs are forecast based upon current estimates, regardless of the time they are incurred.




GENERAL

Information upon which this estimate has been based was furnished by the staff of EXCO or was obtained by us from outside sources we consider to be reliable. This information is assumed correct. No attempt has been made to verify title or ownership of the subject properties.

Leases were not inspected by a representative of this firm, nor were the wells tested under our supervision; however, the performance of the majority of the wells was discussed with employees of EXCO.

This report has been prepared utilizing methods and procedures regularly used by petroleum engineers to estimate oil and gas reserves for properties of this type and character. The recovery of oil and gas reserves and projection of producing rates are dependent upon many variable factors including prudent operation, compression of gas when needed, market demand, installation of lifting equipment, and remedial work when





required. The reserves included in this report have been based upon the assumption that the wells will continue to be operated in a prudent manner under the same conditions existing at the present time. Actual production results and future well data may yield additional facts, not presently available to us, which will require an adjustment to our estimates.

The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and, if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. As in all aspects of oil and gas estimation, there are uncertainties inherent in the interpretation of engineering data and, therefore, our conclusions necessarily represent only informed professional judgments.

It should be pointed out that regulatory authorities could, in the future, change the allocation of reserves allowed to be produced from a particular well in any reservoir, thereby altering the material premise upon which our reserve estimates may be based.

The projection of cash flow has been made assuming constant prices. There is no assurance that prices will not vary. For this reason and those listed in the previous paragraph, the future net cash from the sale of production from the subject properties may vary from the estimates contained in this report.

It is our opinion that based upon our knowledge of current facts and conditions, the reserves presented in this report are a reasonable measure of EXCO’s reserves considered by us.

The information developed during the course of this investigation, basic data, maps and worksheets showing recovery determinations can be made available for inspection in our office.

This report is to be used only in its entirety.

We appreciate this opportunity to be of service to you.

                        
 
 
 
Very truly yours,
 
 
 
 
 
 
 
LEE KEELING AND ASSOCIATES, INC.
 
 
 
 
LKA7489-EXCO (PA) & (WV)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


                        





Exhibit 99.2

January 19, 2015


Mr. Harold L. Hickey
EXCO Resources, Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251

Dear Mr. Hickey:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2014, to the EXCO Resources, Inc. (EXCO) interest in certain gas properties located in Louisiana, Pennsylvania, Texas, and West Virginia. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 87 percent of all proved reserves owned by EXCO. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for EXCO's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the EXCO interest in these properties, as of December 31, 2014, to be:

 
 
Net Reserves
 
Future Net Revenue (M$)
 
 
Gas
 
Condensate
 
 
 
Present Worth
Category
 
(MMCF)
 
(MBBL)
 
Total
 
at 10%
 
 
 
 
 
 
 
 
 
Proved Developed Producing
 
439,024.3
 
0.0
 
926,651.4
 
570,348.4
Proved Developed Non-Producing
 
12,681.4
 
2.6
 
25,379.9
 
13,564.9
Proved Undeveloped
 
651,502.4
 
0.0
 
900,412.6
 
387,478.5
 
 
 
 
 
 
 
 
 
Total Proved
 
1,103,208.1
 
2.6
 
1,852,443.8
 
971,391.7

Totals may not add because of rounding.

Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Condensate volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons.

The estimates shown in this report are for proved reserves. As requested, probable or possible reserves that exist for these properties have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.




Gross revenue is EXCO's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for EXCO's share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014. For gas volumes, the average Henry Hub spot price of $4.350 per MMBTU is adjusted by area for energy content and market differentials. For condensate volumes, the price used is the average West Texas Intermediate spot price of $94.99 per barrel. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $3.881 per MCF of gas and $94.99 per barrel of condensate.

Operating costs used in this report are based on operating expense records of EXCO. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of EXCO are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by EXCO and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the EXCO interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on EXCO receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by EXCO, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been



prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from EXCO, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Robert C. Barg, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1989 and has over 6 years of prior industry experience. William J. Knights, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

    
 
 
 
Sincerely,
 
 
 
 
 
 
 
 
 
NETHERLAND, SEWELL & ASSOCIATES, INC.
 
 
 
 
Texas Registered Engineering Firm F-2699
 
 
 
 
 
 
 
 
 
 
 
 
 
 
By: /s/ C.H. (Scott) Rees III
 
 
 
 
      C.H. (Scott) Rees III, P.E.
 
 
 
 
      Chairman and Chief Executive Officer
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
By: /s/ Robert C. Barg
 
 
By: /s/ William J. Knights
 
      Robert C. Barg, P.E. 71656
 
 
      William J. Knights, P.G. 1532
 
      Senior Vice President
 
 
      Vice President
 
 
 
 
 
 
Date Signed: January 19, 2015
 
 
Date Signed: January 19, 2015
 
 
 
 
 
 


MTD:CAS

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.





DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir . Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii)
Same environment of deposition;
(iii)
Similar geological structure; and
(iv)
Same drive mechanism.

Instruction to paragraph (a)(2) : Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen . Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate . Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate . The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves . Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Supplemental definitions from the 2007 Petroleum Resources Management System:
Developed Producing Reserves - Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves - Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical



reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii)
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii)
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv)
Provide improved recovery systems.

(8) Development project . A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well . A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible . The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR) . Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs . Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii)
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii)
Dry hole contributions and bottom hole contributions.
(iv)
Costs of drilling and equipping exploratory wells.
(v)
Costs of drilling exploratory-type stratigraphic test wells.




(13) Exploratory well . An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well . An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)
Oil and gas producing activities include:

(A)
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
(B)
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C)
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1)
Lifting the oil and gas to the surface; and
(2)
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D)
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i) : The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b.
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)
Oil and gas producing activities do not include:

(A)
Transporting, refining, or marketing oil and gas;
(B)
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C)
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D)
Production of geothermal steam.




(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi)
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii)
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii)
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv)
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and



maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)
Costs of labor to operate the wells and related equipment and facilities.
(B)
Repairs and maintenance.
(C)
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D)
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E)
Severance taxes.

(ii)
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)
The area of the reservoir considered as proved includes:

(A)
The area identified by drilling and limited by fluid contacts, if any, and
(B)
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii)
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)
The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending



date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26) : Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a.      Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.      Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a.      Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.      Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.      Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d.      Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.



e.      Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.      Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects - such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations - by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
The company's historical record at completing development of comparable long-term projects;
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such



techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.










EXCO RESOURCES, INC.





Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests





SEC Parameters





As of

December 31, 2014










/s/ Michael F. Stell
Michael F. Stell, P.E.
TBPE License No. 56416
Advising Senior Vice President
[SEAL]
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580


RYDER SCOTT COMPANY PETROLEUM CONSULTANTS



Exhibit 99.3
TBPE REGISTERED ENGINEERING FIRM F-1580
FAX (713) 651-0849
1100 LOUISIANA STREET SUITE 4600 HOUSTON, TEXAS 77002-5294
TELEPHONE (713) 651-9191



January 19, 2015



EXCO Resources, Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251


Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of EXCO Resources, Inc. (EXCO) as of December 31, 2014. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 6, 2015 and presented herein, was prepared for public disclosure by EXCO in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of EXCO’s total net proved reserves as of December 31, 2014. Based on information provided by EXCO, the third party estimate conducted by Ryder Scott addresses 99.1 percent of the total proved developed net liquid hydrocarbon reserves and 0.9 percent of the total proved developed net gas reserves or 15.64 percent of the total proved developed net reserves on a barrel of oil equivalent, BOE basis, (wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent) and 100.0 percent of the total proved undeveloped net liquid hydrocarbon reserves and 0.11 percent of the total proved undeveloped net gas reserves or 3.07 percent of the total proved undeveloped net reserves on a barrel of oil equivalent, BOE basis, of EXCO.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2014, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.



    
SUITE 600, 1015 4TH STREET, S.W.
CALGARY, ALBERTA T2R 1J4
TEL (403) 262-2799
FAX (403) 262-2790
 621 17TH STREET, SUITE 1550
 DENVER, COLORADO 80293-1501
TEL (303) 623-9147
FAX (303) 623-4258
            
             

EXCO Resources, Inc.
January 19, 2015
Page 2



SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold Interests of
EXCO Resources, Inc.
As of December 31, 2014

 
 
Proved
 
 
Developed
 
 
 
Total
 
 
Producing
 
Non-Producing
 
Undeveloped
 
Proved
Net Remaining Reserves
 
 
 
 
 
 
 
 
Oil/Condensate – Barrels
 
14,285,273

 
358

 
3,257,560

 
17,543,191

Plant Products – Barrels
 
387,035

 
0

 
54,260

 
441,295

Gas – MMCF
 
4,389

 
0

 
748

 
5,137

 
 
 
 
 
 
 
 
 
Income Data (M$)
 
 
 
 
 
 
 
 
Future Gross Revenue
 

$1,248,839

 

$31

 

$282,765

 

$1,531,635

Deductions
 
346,371

 
1

 
147,056

 
493,428

Future Net Income (FNI)
 
$
902,468

 

$30

 

$135,709

 

$1,038,207

 
 
 
 
 
 
 
 
 
Discounted FNI @ 10%
 
$
512,711

 

$28

 
$
50,783

 
$
563,522



Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used at the request of EXCO. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. Other costs include salt water disposal expenses and gas and oil transportation expenses. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 99 percent and gas reserves account for the remaining 1 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EXCO Resources, Inc.
January 19, 2015
Page 3




 
 
Discounted Future Net Income (M$)
 
 
As of December 31, 2014
Discount Rate
 
Total
 
Percent
 
Proved
 
 
 
 
 
5
 
$723,978
 
15
 
$467,471
 
20
 
$403,584
 
25
 
$357,916
 


The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At EXCO’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EXCO Resources, Inc.
January 19, 2015
Page 4



may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

EXCO’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which EXCO owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EXCO Resources, Inc.
January 19, 2015
Page 5



in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties that we evaluated were estimated by performance methods or the analogy method. All of the proved producing reserves attributable to producing wells and/or reservoirs that we evaluated were estimated by decline curve analysis which utilized extrapolations of historical production data available through mid-December 2014, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by EXCO or obtained from public data sources and were considered sufficient for the purpose thereof. All of the proved developed non-producing and undeveloped reserves that we evaluated were estimated by the analogy method. The data utilized from the analogues incorporated into our analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

EXCO has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by EXCO with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, salt water disposal expenses, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by EXCO. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EXCO Resources, Inc.
January 19, 2015
Page 6




Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by EXCO. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

EXCO furnished us with the above mentioned average prices in effect on December 31, 2014. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by EXCO. The differentials furnished by EXCO were reviewed by us for their reasonableness using information furnished by EXCO for this purpose.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.


Geographic Area
Product
Price
Reference
Average
Benchmark
Prices
Average
Realized
Prices
North America
 
 
 
 
United States
Oil/Condensate
WTI Cushing
$94.99/Bbl
$89.97/Bbl
 
NGLs
Propane, Mont Belvieu
$44.84/Bbl
$33.03/Bbl
 
Gas
Henry Hub
$4.35/MMBTU
$2.60/MCF


RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EXCO Resources, Inc.
January 19, 2015
Page 7




The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by EXCO and are based on the operating expense reports of EXCO and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. Other costs include salt water disposal expenses and transportation and/or processing fees. The operating costs furnished by EXCO were reviewed by us for their reasonableness using information furnished by EXCO for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by EXCO and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. EXCO’s estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for EXCO’s estimate.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with EXCO’s plans to develop these reserves as of December 31, 2014. The implementation of EXCO’s development plans as presented to us and incorporated herein is subject to the approval process adopted by EXCO’s management. As the result of our inquiries during the course of preparing this report, EXCO has informed us that the development activities included herein have been subjected to and received the internal approvals required by EXCO’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to EXCO. Additionally, EXCO has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2014, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by EXCO were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EXCO Resources, Inc.
January 19, 2015
Page 8



authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to EXCO. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by EXCO.

EXCO makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, EXCO has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of EXCO of the references to our name as well as to the references to our third party report for EXCO, which appears in the December 31, 2014 annual report on Form 10-K of EXCO. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by EXCO.

We have provided EXCO with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by EXCO and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580


/s/ Michael F. Stell


Michael F. Stell, P.E.
TBPE License No. 56416
Advising Senior Vice President

[SEAL]
MFS (DPR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS







Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.

Mr. Stell, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13 hours of formalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalized in-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr. Stell attended an internally presented six hours of formalized training and ten hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, and ethics training. For each year starting 2011 through 2014, as of the date of this report, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.

Based on his educational background, professional training and over 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.



RYDER SCOTT COMPANY PETROLEUM CONSULTANTS






PETROLEUM RESERVES DEFINITIONS

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)


PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS
Page 2



centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.


RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).


PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS
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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.




RYDER SCOTT COMPANY PETROLEUM CONSULTANTS






PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)


Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).


DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
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Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In
Shut-in Reserves are expected to be recovered from:
(1)
completion intervals which are open at the time of the estimate, but which have not started producing;
(2)
wells which were shut-in for market conditions or pipeline connections; or
(3)
wells not capable of production for mechanical reasons.

Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.


UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.




RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Exhibit 99.4


L EE K EELING AND A SSOCIATES , I NC .
P ETROLEUM C ONSULTANTS
First Place Tower
15 East Fifth Street Suite 3500
Tulsa, Oklahoma 74103-4350
(918) 587-5521 Fax: (918) 587-2881
www.lkaengineers.com

January 6, 2015



EXCO Resources, LLC
12377 Merit Drive, Suite 1700
Dallas, Texas 75251

Attention: Mr. Harold L. Hickey
 
 
Re:
Estimated Proved Reserves and
 
 
 
 
Future Net Cash Flow
 
 
 
 
Constant Pricing

Gentlemen:

In accordance with your request, we have prepared an estimate of the proved reserves and future net cash flow attributable to the interests owned by EXCO Resources, LLC (“EXCO”) located in Oklahoma. The reserves estimated by us for EXCO represent zero point one per cent (0.1%) of EXCO Resources, Inc. reserves. This report was prepared according to the Securities and Exchange Commission (SEC) guidelines as published in the Federal Register January 14, 2009. The effective date of our estimate is December 31, 2014, and the results are summarized as follows:

 
ESTIMATED REMAINING
FUTURE NET CASH FLOW
 
NET RESERVES
 
 
Present Worth
 
 
Oil
 
Gas
 
Net Equiv.
 
Total
 
Disc. @ 10%
RESERVE CLASSIFICATION
 
(MBBL)
 
(MMCF)
 
(MMCFE) (1)
 
(M$)
 
(M$)
 
 
 
 
 
 
 
 
 
 
 
Proved Developed
 
 
 
 
 
 
 
 
 
 
Producing
 
0.803

 
630.190

 
635.008

 
1,612.827

 
1,149.005

Non-Producing
 

 
63.324

 
63.324

 
151.878

 
65.175

Behind-Pipe
 

 
87.008

 
87.008

 
316.289

 
114.364

Sub-Total
 
0.803

 
780.522

 
785.340

 
2,080.994

 
1,328.544

 
 
 
 
 
 
 
 
 
 
 
Proved Undeveloped
 

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
TOTAL PROVED RESERVES(2)
 
0.803

 
780.522

 
785.340

 
2,080.994

 
1,328.544

Notes:
 
 
 
 
 
 
 
 
 
 
(1)MMCFE-one million cubic feet equivalent, calculated by converting one barrel of oil to six MCF of natural gas.
(2)Totals may differ from schedules due to roundoff.
 
 
 
 
 
 

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Future net cash flow is the amount, exclusive of federal and state income taxes, which will accrue to the subject interests from continued operation of the properties to depletion. It should not be construed as a fair market or trading value. No provision has been made for the cost of plugging and abandoning the properties.

No attempt has been made to quantify or otherwise account for any accumulative gas production imbalances that may exist. Likewise, no attempt has been made to determine whether the wells and facilities are in compliance with various governmental regulations. Accordingly, no costs have been included in the event the wells and facilities are not in compliance.

CLASSIFICATION OF RESERVES

Reserves assigned to the various leases and/or wells have been classified as either “proved developed” or “proved undeveloped” in accordance with the definitions of the proved reserves as promulgated by the Securities and Exchange Commission. These are as follows:

Proved Developed Oil and Gas Reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Oil and Gas Reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Proved Developed Oil and Gas Reserves attributed to the subject leases have been further classified as “proved developed producing,” “proved developed non-producing” and “proved developed behind-pipe.”

Proved Developed Producing Reserves are those reserves expected to be recovered from currently producing zones under continuation of present operating methods.

Proved Developed Non-Producing Reserves are those reserves expected to be recovered from zones that have been completed and tested but are not yet producing due to situations including, but not limited to, lack of market, minor completion problems that are expected to be corrected, or reserves expected from future stimulation treatments based on analogy to nearby wells.

Proved Developed Behind-Pipe Reserves are those reserves currently behind the pipe in existing wells that are considered proved by virtue of successful testing or production in offsetting wells.



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ESTIMATION OF RESERVES

The majority of the subject properties have been producing for a considerable length of time. The estimation of reserves for these wells has been based on the extrapolation of the existing historic production decline curves and/or pressure decline trends to economic limits or abandonment pressures.

Reserves anticipated from recently completed or new wells were based upon volumetric calculations or analogy with similar properties, which are producing from the same horizons in the respective areas. Structural position, net pay thickness, well productivity, gas-oil ratios, water production, pressures, and other pertinent factors were considered in the estimations of these reserves.

Reserves assigned to behind-pipe zones have been estimated based on volumetric calculations and/or analogy with other wells in the area producing from the same horizon.

FUTURE NET CASH FLOW

Oil Income and Prices

Income from the sale of oil was estimated based on the unweighted average price for West Texas Intermediate Cushing Oil, for the first day of each month for January through December of 2014, as provided by the staff of EXCO. That computed reference price of $94.99 per barrel was held constant throughout the life of each lease. The reference price was adjusted for historical differentials between posted prices and actual field prices to reflect quality, transportation fees and regional price differences. The weighted average price for oil over the life of the properties was $90.506 per barrel.

Gas Income and Prices

Income from the sale of gas was estimated based on the unweighted average price for natural gas sold at Henry Hub, the first day of each month for January through December of 2014, as provided by staff of EXCO. That computed reference price of $4.35 per MMBTU was held constant throughout the life of each lease. The reference price was adjusted for BTU content, basis differentials, marketing, and transportation costs. The weighted average price for natural gas over the life of the properties was $4.217 per MMBTU.

Operating Expenses

Operating expenses were based upon actual operating costs, including appropriate overhead expenses, charged by EXCO or the respective operators, as supplied by the staff of EXCO. All expenses were held constant throughout the life of each lease.

Future Expenses

Provisions have been made for future expenses required for recompletion and drilling. These costs are forecast based upon current estimates, regardless of the time they are incurred.


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GENERAL

Information upon which this estimate has been based was furnished by the staff of EXCO or was obtained by us from outside sources we consider to be reliable. This information is assumed correct. No attempt has been made to verify title or ownership of the subject properties.

Leases were not inspected by a representative of this firm, nor were the wells tested under our supervision; however, the performance of the majority of the wells was discussed with employees of EXCO.

This report has been prepared utilizing methods and procedures regularly used by petroleum engineers to estimate oil and gas reserves for properties of this type and character. The recovery of oil and gas reserves and projection of producing rates are dependent upon many variable factors including prudent operation, compression of gas when needed, market demand, installation of lifting equipment, and remedial work when required. The reserves included in this report have been based upon the assumption that the wells will continue to be operated in a prudent manner under the same conditions existing at the present time. Actual production results and future well data may yield additional facts, not presently available to us, which will require an adjustment to our estimates.

The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and, if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. As in all aspects of oil and gas estimation, there are uncertainties inherent in the interpretation of engineering data and, therefore, our conclusions necessarily represent only informed professional judgments.

It should be pointed out that regulatory authorities could, in the future, change the allocation of reserves allowed to be produced from a particular well in any reservoir, thereby altering the material premise upon which our reserve estimates may be based.

The projection of cash flow has been made assuming constant prices. There is no assurance that prices will not vary. For this reason and those listed in the previous paragraph, the future net cash from the sale of production from the subject properties may vary from the estimates contained in this report.

It is our opinion that based upon our knowledge of current facts and conditions, the reserves presented in this report are a reasonable measure of EXCO’s reserves considered by us.

The information developed during the course of this investigation, basic data, maps and worksheets showing recovery determinations can be made available for inspection in our office.

This report is to be used only in its entirety.

We appreciate this opportunity to be of service to you.                
 
 
Very truly yours,
 
 
LEE KEELING AND ASSOCIATES, INC.
LKA7489-EXCO (OK)

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