EXCO Resources, Inc.
2 0 1 4
A N N U A L R E P O R T
Dear Fellow Shareholders,
We appreciate your decision to invest in EXCO Resources and are committed to being good stewards of your capital. While the current commodity
environment is challenging, we have taken steps in 2014 and 2015 to improve EXCO’s position and manage through this commodity cycle. We have
enhanced our liquidity, reduced our headcount, and demonstrated that we are an efficient operator, as we manage our capital and expense spending and
leverage our technical expertise to opportunities across our portfolio.
In March 2015, we entered into an agreement with Bluescape Resources Company LLC (“Bluescape”) whereby John Wilder, Executive Chairman of
Bluescape, will become Executive Chairman of EXCO’s Board of Directors. EXCO and Bluescape are currently developing a strategic business plan focused on
four key areas:
1.
2.
3.
4.
Liability management,
Portfolio repositioning,
Cost leadership, and
Risk management.
We are excited to be partnering with John and his team from Bluescape as we leverage their experiences and insights and develop a plan to lead EXCO
forward and create shareholder value.
We continue to monitor commodity prices, adjusting levers around our operations to maximize returns and manage our capital structure and cash flow. We
believe this cycle brings with it opportunities to build long term value for our investors. We are committed to this objective.
EXCO is focused on leveraging the experience of our technical and operations team. EXCO currently operates more than 840 shale wells and has significant
acreage positions in three strategic shale plays in the United States. We have great optionality and upside in our drilling location inventory and the Company
will benefit from long term macro improvements in commodity prices.
During 2014, your Company achieved significant accomplishments. Through a combination of efficient development of our asset base, strategic divestitures
and financing transactions, we exited the year with lower leverage and significant liquidity that together help position EXCO for future growth. Highlights of
these accomplishments include:
Asset Base Development
•
•
•
Drilled 122 gross wells and turned to sales 98 gross wells,
Improved the efficiency of our drilling and completion operations and reduced well costs, and
Positively impacted reserves with the results of our successful drilling and completion program in the Shelby area of East Texas.
Strategic Divestitures
•
•
Sold non-operated asset in the Permian Basin for $68 million, and
Sold remaining interest in Compass Production Partners and received $119 million and removed $83 million of Compass’ debt from our balance
sheet.
Finance Activities
•
•
•
Raised $273 million through a common stock rights offering with the support of our broad shareholder base, including our largest investors,
Issued $500 million of senior unsecured notes due in 2022, and
Suspended the common stock dividend.
We have recently executed other operational initiatives to unlock upside in our asset base, despite the current commodity price environment. In North
Louisiana, we have completed six Haynesville refracture stimulations of various designs with positive results. We have a large pool of wells that are
candidates for potential refracture stimulations as we further refine the techniques and costs to improve our returns. We recently turned to sales a Bossier
shale well
is
performing in-line with our expectations and based on the enhanced completion methods, existing in-place infrastructure, and our ability to reduce drilling
and completion costs, we believe we can develop as many as 300 Bossier shale drilling locations in North Louisiana in the future. In South Texas, we drilled
two operated Buda wells that had initial production rates in excess of 500 barrels of oil per day and plan to drill additional Buda wells during the remainder
of 2015.
in North Louisiana using our restricted flowback methodology focused on pressure maintenance instead of production rate. The well
For 2015, we continue to focus on efficiently developing our asset base and reducing costs throughout the organization. Managing our balance sheet,
maintaining ample liquidity and simplifying our organization remain top priorities. We are demonstrating fiscal discipline with a focus on projects that:
•
•
•
Produce attractive returns in the current commodity price environment,
Add proved reserves to our portfolio, and
Increase or maintain high value acreage positions.
Our East Texas Shelby asset is our natural gas focus area in 2015 and beyond as our drilling and completion activities add proved developed producing wells
that were not categorized as proved locations at year-end, and add proved undeveloped locations and reserves to our asset base as we continue to develop
this area. We also believe there is potential for additional upside in our Shelby reserves based on our current drilling and completion designs.
In February 2015, we proactively worked with our banks and amended our credit agreement to provide financial flexibility to strategically develop our asset
base, while deferring a significant amount of our drilling inventory. We are highly confident in the quality of the credit agreement’s underlying collateral
asset base and thank our bank group for their continued support of EXCO.
In March 2015, we entered into a four-year services and investment agreement with Bluescape. John Wilder and his team at Bluescape have a
demonstrated track record of increasing shareholder value and proven successful experiences in commercial and turnaround work, which complement
EXCO’s strong oil and gas operating capabilities. Bluescape’s agreement with EXCO encompasses both an investing aspect and strategic advisory services,
with their compensation heavily weighted towards building equity value, aligning them with your interests. Bluescape has agreed to invest $50 million in
EXCO, which demonstrates a strong commitment to our company and an understanding of the quality of our people and assets, as well as optimism toward
our future opportunities. This partnership is a strategic step toward working through the current commodity cycle, enhancing the value of our corporation
and preparing EXCO for the future.
With the review of 2014 and our recent 2015 efforts, EXCO has significantly enhanced its liquidity as we have reduced debt from third quarter 2013 levels.
We are focused in three strong positions (East Texas/North Louisiana, South Texas and Appalachia) with significant upside opportunities. We have built a
solid platform supported by an experienced operating team with a demonstrated ability to continuously drive down costs and improve efficiencies. Our
balance sheet and liquidity have been strengthened to protect against market fluctuations and allow us to opportunistically pursue growth opportunities.
We firmly believe that as we continue to execute during this commodity cycle our stakeholders will be rewarded.
Thank you for your support of EXCO Resources.
Sincerely,
Jeffrey D. Benjamin
Chairman of the Board
Harold L. Hickey
Chief Executive Officer and President
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K/A
Amendment No. 1
(Mark One)
(cid:95) 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
(cid:133) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 001-32743
EXCO RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Texas
(State or other jurisdiction of
incorporation or organization)
12377 Merit Drive, Suite 1700, LB 82, Dallas, Texas
(Address of principal executive offices)
74-1492779
(I.R.S. Employer
Identification No.)
75251
(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
Common Stock, $0.001 par value
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act: Yes (cid:133) No (cid:95)
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 (cid:133) No (cid:95)
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 (cid:95) No (cid:133)
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files.) Yes (cid:95) No (cid:133)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (S229.405 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 Form 10-K or
any amendment to this Form 10-K. (cid:95)
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
definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)
Large accelerated filer
(cid:95)
Non-accelerated filer
(cid:133) (Do not check if a smaller reporting company)
Accelerated filer
(cid:133)
Smaller reporting company (cid:133)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes (cid:133) No (cid:95)
As of March 31, 2015, the registrant had 273,702,116 outstanding shares of common stock, par value $0.001 per share, which is its only class of common
stock. 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
stock held by non-affiliates was approximately $897,416,000.
EXCO RESOURCES, INC.
TABLE OF CONTENTS
PART III.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Part IV.
Item 15.
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Exhibits and Financial Statement Schedules
1
1
6
30
33
35
36
36
EXPLANATORY NOTE
EXCO Resources, Inc. is filing this Amendment No. 1 on Form 10-K/A (this “Amendment”) to its Annual Report on
Form 10-K for the fiscal year ended December 31, 2014, filed on February 25, 2015 (the “Form 10-K”), solely for the purpose of
amending Items 10 through 14 in Part III and Item 15 in Part IV. The information in Part III was previously omitted from the
Form 10-K in reliance on General Instruction G(3) to Form 10-K, which permits such information to be incorporated in the Form 10-
K by reference to a definitive proxy statement if such proxy statement is filed no later than 120 days after our fiscal year end.
We are filing this Amendment to include the Part III information in the Form 10-K because we no longer expect to file a
definitive proxy statement containing this information before the date that is 120 days after our fiscal year end. Part IV is being
amended to include as exhibits certain new certifications required of the principal executive officer and principal financial officer
under Section 302 of the Sarbanes-Oxley Act of 2002, as amended. This Amendment hereby amends Part III, Items 10 through 14,
and Part IV, Item 15 of the Form 10-K. Additionally, the reference on the cover page of the Form 10-K to the Definitive Proxy
Statement for the 2015 Annual Meeting of Shareholders is hereby deleted.
Except as described above, no other changes have been made to the Form 10-K. Other than the information specifically
amended and restated herein, this Amendment does not reflect events occurring after February 25, 2015, the date the Form 10-K was
filed, or modify or update those disclosures that may have been affected by subsequent events.
References to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” in this report refer to EXCO Resources,
Inc. together with its consolidated subsidiaries.
PART III
Item 10.
Directors, Executive Officers and Corporate Governance
The board of directors is currently comprised of six directors. Our directors serve until the next annual meeting of shareholders
or until their respective successors have been duly elected and qualified. Pursuant to a letter agreement that the Company entered into
with funds managed by Oaktree Capital Management, LP (“Oaktree” and together with the managed funds, the “Oaktree Funds”) in
March 2007, Oaktree has the right to nominate one director for election at any annual meeting of shareholders so long as Oaktree
beneficially owns at least 10,000,000 shares of common stock. As of the record date for the 2014 annual meeting of shareholders,
Oaktree owned in excess of 10,000,000 shares of common stock. As a result, Mr. Ford was nominated by Oaktree, as well as by our
board of directors, for election at the 2014 annual meeting of shareholders.
The following table sets forth the name, age and positions of each director currently serving on our board of directors:
Name
Age
Position
Jeffrey D. Benjamin(1)(2)(3)
B. James Ford(2)(3)
Samuel A. Mitchell (1)(2)(3)
Wilbur L. Ross, Jr.(2)(3)
Jeffrey S. Serota (1)(2)(3)
Robert L. Stillwell(1)(2)(3)
53 Director; Non-Executive Chairman
46 Director
71 Director
77 Director
49 Director
78 Director
(1) Member of the audit committee.
(2) Member of the compensation committee.
(3) Member of the nominating and corporate governance committee.
The biographies of our directors are as follows:
1
Jeffrey D. Benjamin became non-executive chairman of our board of directors in November 2013 and has been serving as one
of our directors since October 2005. Mr. Benjamin previously served as a director from August 1998 through July 2003 and a director
of our parent holding company from July 2003 through its merger into us. Since June 2008, Mr. Benjamin has been a Senior Advisor
to Cyrus Capital Partners, LP (“Cyrus Capital Partners”). Mr. Benjamin also serves as a Consultant to Apollo Management, LP
(“Apollo Management”) and from September 2002 until June 2008, Mr. Benjamin served as a Senior Advisor to Apollo Management.
With his service at Apollo Management and Cyrus Capital Partners, Mr. Benjamin has extensive financial, capital markets and
strategic experience. Mr. Benjamin is currently a director of American Airlines Group Inc., Caesars Entertainment Corporation and
Chemtura Corporation and Chairman of the Board of Directors of A-Mark Precious Metals, Inc. During the past five years,
Mr. Benjamin also served on the board of directors of Virgin Media Inc. and Spectrum Group International, Inc. In connection with
his service as a director of nine public companies other than EXCO over the past ten years, Mr. Benjamin has served on five
compensation committees (including two as chairman), five audit committees and five nominating and corporate governance
committees (including two as chairman), all of which provide him with important insights into corporate governance, financial
reporting and oversight, executive compensation and board functions. In addition, Mr. Benjamin has deep knowledge of the Company
and its business, having served on our and our affiliates’ boards since October 2005 and prior to that from 1998 through 2003.
Mr. Benjamin holds a Master of Science (MBA) in Management from the Sloan School of Management at Massachusetts Institute of
Technology, with a concentration in Finance, and has 28 years of investment banking and investment management experience.
B. James Ford became one of our directors in December 2007. Mr. Ford is a Managing Director of Oaktree where he has
worked since 1996. Mr. Ford is a portfolio manager of Oaktree’s global principal group, which invests in controlling and minority
positions in private and public companies. Mr. Ford serves on the board of directors of Contango Oil & Gas Company, Oaktree
Capital Group, LLC and Townsquare Media, LLC as well as a number of private companies and not-for-profit entities, and formerly
served on the board of directors of Dial Global, Inc. and Crimson Exploration, Inc. prior to its merger with Contango Oil & Gas
Company. Prior to becoming a portfolio manager, Mr. Ford led the group’s efforts in the media and energy sectors. Mr. Ford’s
background and experience provide him with extensive investment, capital markets and strategic experience, as well as important
insights into corporate governance and board functions. He is also an active member of the Children’s Bureau Board of Directors and
serves as a trustee for the Stanford Graduate School of Business Trust. Mr. Ford received a B.A. degree in Economics from the
University of California at Los Angeles and a Masters of Business Administration degree from the Stanford Graduate School of
Business.
Samuel A. Mitchell became one of our directors in June 2013. Mr. Mitchell has served as a director of Overstock.com, Inc.
since October 2010. Mr. Mitchell was formerly a director of International Coal Group, Inc. from 2006 until its acquisition in 2011.
Since 2004, Mr. Mitchell has been a Managing Director of Hamblin Watsa Investment Counsel (“Hamblin Watsa”), a wholly-owned
subsidiary of Fairfax Financial Holdings, Inc. (“Fairfax Financial”), a Toronto-based property and casualty insurance holding
company. Hamblin Watsa is responsible for managing the investments of Fairfax Financial. From 2005 to 2007, Mr. Mitchell was a
director of Odyssey Re Holdings Corp., a majority-owned subsidiary of Fairfax Financial that is an underwriter of property and
casualty treaty and facultative reinsurance. Prior to joining Hamblin Watsa, Mr. Mitchell was Managing Director and co-founder in
1993 of Marshfield Associates, a Washington, D.C.-based investment counsel firm. Mr. Mitchell also has experience in the healthcare
industry, having served as a Director of Research and Federal Relations for the Federation of American Health Systems from 1983 to
1993, and as Director of Research for the Health Industry Manufacturers Association from 1977 to 1981. In 1973, he co-founded
Research from Washington, which advised large institutional investors on the outlook and economic impact of legislation and federal
government initiatives. Mr. Mitchell started his career in 1968 with the Washington, D.C.-based investment counsel firm, Davidge and
Co. He has a B.A. from Harvard College and an M.B.A. from Harvard Business School. Mr. Mitchell’s experience as Managing
Director of Hamblin Watsa, and his four decades of business experience provide him with extensive investment, capital markets and
financial experience as well as important insights into financial reporting, oversight and Board functions.
Wilbur L. Ross, Jr. became one of our directors in March 2012. Mr. Ross is the Founder, Chairman and Chief Strategy Officer
of WL Ross & Co. LLC (“WL Ross”), a private equity firm. Mr. Ross was also formerly the Chief Executive Officer of WL Ross
prior to April 30, 2014 when he became its Chairman and Chief Strategy Officer. In March 2014, Mr. Ross became the Chairman and
Chief Executive Officer of WL Ross Holding Corp, a special purpose acquisition company. Mr. Ross is currently a member of the
board of directors of ArcelorMittal, the world’s largest steel and mining company; DSS Holdings LP, a shipping transportation
company; Sun Bancorp, Inc.; and the Bank of Cyprus. Mr. Ross formerly served as a member of the board of directors of many banks,
financial and other companies, including but not limited to, The Governor and Company of the Bank of Ireland, a commercial bank in
Ireland until June 2014, BankUnited, Inc. until March 2014; Talmer Bancorp., Assured Guaranty, an insurance company, International
Textile Group, NBNK Investments PLC, PB Materials Holdings, Inc., Ohizumi Manufacturing, Ocwen Financial Corp., Navigator
Holdings, a marine transport company, and International Automotive Components until November 2014; Plascar Participacoes SA, a
manufacturer of automotive interiors, until January 2014 and Air Lease Corporation, an aircraft leasing company from 2010 to
December, 2013; International Coal Group from April 2005 to June 2011, Montpelier Re Holdings Ltd., a reinsurance company, from
2006 to March 2010; The Greenbrier Companies, a supplier of transportation equipment and services to the railroad industry from
2
June 2009 until January 2013. Mr. Ross was Executive Managing Director of Rothschild Inc. for 24 years before acquiring that firm’s
private equity partnerships in 2000. Mr. Ross is a graduate of Yale University and of Harvard Business School. Through the course of
Mr. Ross’ career, he has served as a principal financial adviser to, investor in, and director of various companies across the globe
operating in diverse industries, and he has assisted in restructuring more than $400 billion of corporate liabilities. Mr. Ross possesses
unique skills, qualities and experience, as evidenced by his background, which we believe adds significant value to board discussions
and to our success.
Jeffrey S. Serota became one of our directors in March 2007. Mr. Serota previously served as a director of EXCO Resources
and EXCO Holdings from July 2003 until October 2005. He served as a Senior Partner of Ares, an alternative asset investment firm,
from September 1997 until his retirement in December 2012. Mr. Serota subsequently served as a Senior Advisor to Ares until
December 31, 2013. Prior to joining Ares, Mr. Serota worked at Bear Stearns Companies, Inc. from March 1996 to September 1997,
where he specialized in providing investment banking services to financial sponsor clients of the firm. He currently serves on the
board of directors of SandRidge Energy, Inc. and CIFC Corp., and previously served on the boards of directors of Lyondell Basell
Industries N.V. from May 2010 to May 2011, Douglas Dynamics, Inc. from 2004 until October 2010 and WCA Waste Corporation
from September 2006 until March 2012. Mr. Serota has over 20 years of experience managing investments in, and serving on the
boards of directors of, companies operating in various industries, including in the oil and natural gas exploration and production
industry. Mr. Serota’s background and experience provide him with extensive investment, capital markets and strategic experience, as
well as important insights into corporate governance, financial reporting and oversight, executive compensation and board functions.
Mr. Serota received a Bachelor of Science degree in Economics from the University of Pennsylvania’s Wharton School of Business
and received a Master of Business Administration degree from UCLA’s Anderson School of Management.
Robert L. Stillwell became one of our directors in October 2005. Mr. Stillwell served as the General Counsel of BP Capital,
L.P., Mesa Water, Inc. and affiliated companies engaged in the petroleum business from 2001 until he retired in March 2013.
Mr. Stillwell was a lawyer and Senior Partner at Baker Botts LLP in Houston, Texas from 1961 to 2001. He also served as a director
of Mesa Petroleum Co. and Pioneer Natural Resources Company from 1969 to 2001. Mr. Stillwell’s background and experience
provide him with extensive knowledge of the oil and natural gas industry as well as significant legal experience and important insights
into corporate governance, executive compensation and board functions.
There are no family relationships between any of our directors or executive officers.
Audit Committee
The audit committee of our board of directors recommends the appointment of our independent registered public
accountants, reviews our internal accounting procedures and financial statements and consults with and reviews the services provided
by our independent registered public accountants, including the results and scope of their audit. The audit committee is currently
comprised of Messrs. Benjamin (chair), Mitchell, Serota and Stillwell, each of whom is independent within the meaning of applicable
SEC and NYSE rules. The board of directors has designated Messrs. Benjamin and Mitchell as audit committee financial experts, as
currently defined under the SEC rules implementing the Sarbanes-Oxley Act of 2002. See Item 13. Certain Relationships and Related
Transactions, and Director Independence— Director Independence.” We believe that the composition and functioning of our audit
committee complies with all applicable requirements of the Sarbanes-Oxley Act of 2002, as amended, as well as NYSE and SEC rules
and regulations.
Codes of Business Conduct and Ethics
We have adopted Corporate Governance Guidelines, a Code of Business Conduct and Ethics, and a Code of Ethics for the
Chief Executive Officer and Senior Financial Officers. Copies of the codes can be obtained free of charge from our website,
www.excoresources.com, or by contacting us at the address appearing on the first page of this Annual Report on Form 10-K to the
attention of Secretary or by telephone at (214) 368-2084. We intend to post any amendments to, or waivers from, our Code of Ethics
that apply to our chief executive officer or senior financial officers on our website at www.excoresources.com.
3
Executive Officers
The following table sets forth certain information with respect to our current executive officers.
Name
Harold L. Hickey
William L. Boeing
Richard A. Burnett
Age Position
59 Chief Executive Officer and President
60 Vice President, General Counsel and Secretary
41 Vice President, Chief Financial Officer and Chief Accounting Officer
Harold L. Hickey became our Chief Executive Officer in March 2015 and President in February 2013. Mr. Hickey previously
served as Chief Operating Officer from October 2005 until March 2015. From October 2005 until February 2013, Mr. Hickey served
as our Vice President and from January 2004 until October 2005, Mr. Hickey served as President of our wholly-owned subsidiary,
North Coast Energy, Inc. Mr. Hickey was our Production and Asset Manager from February 2001 to January 2004. From April 2000
until he joined us, Mr. Hickey was Chief Operating Officer of Inca Natural Resources Group, L.P., an independent oil and natural gas
exploration company. Prior to that, Mr. Hickey worked at Mobil Oil Corporation from 1979 to March 2000.
William L. Boeing became our Vice President, General Counsel and Secretary in April 2006. From October 1980 to March
2006, Mr. Boeing was initially an associate and later a partner at one of our outside law firms, Haynes and Boone, LLP, in Dallas,
Texas.
Richard A. Burnett became our Vice President and Chief Accounting Officer in March 2014 and our Chief Financial Officer in
September 2014. Mr. Burnett previously served as our Vice President of Special Projects from the time he joined EXCO in November
2013 until March 2014. From April 2001 until joining EXCO, Mr. Burnett served in various capacities at KPMG LLP, including as a
Partner in their energy transactions service practice advising a number of clients in the oil and natural gas exploration and production,
oil field services, manufacturing, midstream, refining and utilities industries on, among other things, their financial reporting and
securities filing requirements. Mr. Burnett also spent five years at Arthur Andersen LLP prior to joining KPMG LLP. Mr. Burnett is a
certified public accountant and received a Bachelor’s degree in Accounting from Texas Tech University.
Other Officers and Divisional Managers of Our Company
Michael R. Chambers Sr., age 59, became our Vice President of Operations in February 2007 and also currently serves as the
Vice President and General Manager of our East Texas/North Louisiana Division. Prior to joining EXCO, Mr. Chambers was the
Operations General Manager for Anadarko Petroleum Corporation’s Eastern Region Operations from August 2006 to February 2007
and Rockies Production Manager from August 2000 to August 2006. Mr. Chambers joined Anadarko in January 2000. Mr. Chambers
worked at Mobil Oil Corporation from 1979 to January 2000.
W. Justin Clarke, age 39, became our Assistant General Counsel and Chief Compliance Officer in January 2007. From
September 2001 until January 2007, Mr. Clarke served as an associate at one of our outside law firms, Haynes and Boone, LLP, in
Dallas, Texas.
Ronald G. Edelen, age 57, joined EXCO in October 2011 as our Vice President of Supply Chain Management. Prior to then,
Mr. Edelen was Director of Supply Chain at Devon Energy Corporation. From September 2008 until October 2010, he was Director of
Supply Chain Management for Matrix Services Inc. Prior to working for Matrix Services Inc., Mr. Edelen held various positions at
DCP Midstream LLC from 1999 to September 2008, including Director of Materials Management and Office Administration. Prior to
DCP Midstream LLC, Mr. Edelen spent his career in various Purchasing, Materials Management and Corporate Travel positions with
CH2M Hill and Total Petroleum, Inc. Mr. Edelen has over 30 years of experience in the oil and natural gas industry with over 20 of
those years directly involved in Supply Chain related positions in upstream, midstream and downstream companies in the U.S. and
Canada. Mr. Edelen is a certified purchasing manager.
Steven L. Estes, age 60, became our Vice President of Marketing in June 2010. Prior to then, Mr. Estes served as Director of
Marketing for us since July 2007. Mr. Estes held several positions with Union Pacific Resources and Anadarko Petroleum Corporation
before joining us, most recently as Regional Manager of Gas Marketing from 2002 until 2007. Mr. Estes has over 30 years of
experience in the oil and natural gas industry with over 20 of those years directly involved in marketing in all regions of the country.
4
Joe D. Ford, age 67, became our Vice President of Human Resources in November 2007. Prior to joining EXCO, Mr. Ford was
the Director of Human Resources for CARBO Ceramics Inc. from June 2002 to November 2007. CARBO Ceramics Inc. supplies
ceramic proppant for fracturing natural gas and oil wells and also provides well fracture diagnostic services. Prior to working for
CARBO Ceramics Inc., Mr. Ford spent his career in various human resource management capacities including a subsidiary of General
Dynamics as Manager of Human Resources and Comdial Corporation as Vice President of Human Resources.
Robert Gessner, age 62, became our Corporate Controller in 2014. Mr. Gessner previously served as the Controller of our
Appalachia division and Controller of our wholly-owned subsidiary, North Coast Energy, Inc. Prior to joining North Coast, Mr.
Gessner served in a variety of financial positions at both Belden and Blake Corporation and M.A. Hanna Company. Mr. Gessner has
over 30 years of industry experience. He is a CPA and a member of the Ohio Society of CPA’s.
Russell D. Griffin, age 51, joined EXCO in January 2008 and became our Vice President of Environmental, Health and Safety
in June 2010. Mr. Griffin was previously our Director of Environmental, Health and Safety and Vice President of Health Safety
Security and Environment for TGGT Holdings, LLC. Prior to joining EXCO, Mr. Griffin was the Senior Regulatory Representative
for Hunt Oil Company, an independent international oil and natural gas exploration and production company, from August 2005 until
January 2008. Mr. Griffin joined Hunt Oil Company in August of 1984 and held numerous positions in their Gulf Coast exploration
and production operations until August 2005.
Daniel W. Higdon, age 57, became our Vice President of Land in September 2013. Prior to joining EXCO, Mr. Higdon was
Vice President – Land for Devon Energy Corporation’s Southern Division from March 2006 to March 2013 and the Central Division
Land Manager from January 2002 to March 2006 overseeing the Barnett Shale asset during the advent of horizontal drilling in
unconventional shales. Mr. Higdon began his career with Mitchell Energy Corporation in 1983 and held various Land positions
culminating as Regional Land Manager coordinating the acquisition of the Barnett Shale asset until Devon acquired Mitchell in 2002.
Harold H. Jameson, age 47, became a Vice President in March 2011 and also serves as the General Manager of our East
Texas/North Louisiana joint venture. His primary focus is on the development of our Haynesville/Bossier shale assets. Prior to the
Haynesville shale project, Mr. Jameson served as General Manager of our Vernon Field. Prior to joining EXCO in April 2007, he was
employed at Anadarko Petroleum Corporation from 1991 to 2007 where he gained valuable experience in a variety of operating areas
including U.S. onshore, offshore and international businesses in both development and exploration roles. Since 2001, Mr. Jameson has
been responsible for Asset Management, Production Engineering, Reservoir Engineering and Field Development in the Central Texas,
East Texas and North Louisiana operating areas.
Christopher C. Peracchi, age 46, became our Treasurer and Director of Finance and Investor Relations in May 2013 and
became our Vice President of Finance and Investor Relations in September 2014. Mr. Peracchi served as the Associate Director of
Corporate Development and Investor Relations at Nabors Industries from April 2012 to April 2013 and Director of Finance and
Investor Relations at Superior Well Services from March 2009 to April 2012. Mr. Peracchi has over 11 years of experience in Energy
Investment Banking at KeyBanc Capital Markets and A.G. Edwards & Sons. Mr. Peracchi also spent four years at Coopers &
Lybrand. Mr. Peracchi is a certified public accountant and received a Master’s in Business Administration from the University of
Michigan and a Bachelor’s degree from Babson College.
Stephen E. Puckett, age 56, became our Vice President of Reservoir Engineering in December 2006. Mr. Puckett was our
Manager of Engineering and Operations from April 2000 until December 2006. From January 1998 until April 2000 he served as a
petroleum engineering consultant for Petra Resources, Inc. From March 1993 until January 1998 he worked for Enserch
Exploration, Inc. as a reservoir engineer. From May 1981 until January 1993 he was employed by Oryx Energy Company as an
operations engineer and reservoir engineer. He is a registered professional engineer in Texas and a member of the Society of
Petroleum Engineers.
Marcia Reeves Simpson, age 58, joined EXCO in March 2008 as our Vice President of Engineering. Ms. Simpson was
employed by J-W Operating Company—Cohort Energy as its Acquisition & Divestiture and Reservoir Engineering Manager from
September 2004 until March 2008. From January 2001 until September 2004, Ms. Simpson was a Vice President for Energy Virtual
Partners, a start-up exploration and production company. From September 1987 until January 2000, she worked for Mobil Oil
Corporation in various leadership positions including U.S. Technology Leader. From June 1978 to September 1987, she worked in
several engineering positions for Gulf Oil Corporation/Chevron Corporation. She is a registered professional engineer in Louisiana
and she has served in various leadership roles with the Gas Research Institute, the Society of Petroleum Engineers and the Society of
Women Engineers over her 30 year career.
5
Robert L. Thomas, age 55, became our Chief Information Officer in May 2008. Prior to joining EXCO, Mr. Thomas was the
Director of Strategy and Architecture in Global Information Services at ConocoPhillips. Prior to working for ConocoPhillips,
Mr. Thomas served Burlington Resources in the US, Canada and UK from 1994 to 2006 in various IT management capacities. Prior to
Burlington Resources, Mr. Thomas worked for Oryx Energy Company. He began his career in the seismic data processing center at
Sun Oil Company in 1981, and is an active member of the Society of Exploration Geophysicists.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our officers and directors, and persons who own more than 10% of a registered class
of our equity securities, to file reports of ownership and changes of ownership with the SEC. Our officers, directors and 10%
shareholders are required by SEC regulations to furnish us with copies of all Section 16(a) forms so filed. Based solely on review of
copies of such forms received, we believe that, during the last fiscal year, all filing requirements under Section 16(a) applicable to our
officers, directors and 10% shareholders were timely met.
Item 11. Executive Compensation
Compensation Discussion and Analysis
Executive Summary
Named Executive Officers. For purposes of disclosure in this Annual Report on Form 10-K, the “Named Executive Officers” for
the year ended December 31, 2014 include the following persons:
• Harold L. Hickey, our President and Chief Operating Officer as of December 31, 2014;
• Richard A. Burnett, our Vice President, Chief Financial Officer and Chief Accounting Officer as of December 31, 2014; and
• William L. Boeing, our Vice President, General Counsel and Secretary as of December 31, 2014.
Unless otherwise indicated, references in this Annual Report on Form 10-K to Named Executive Officers do not include Mark
F. Mulhern, our former Executive Vice President and Chief Financial Officer, who resigned from the Company effective
September 19, 2014. Mr. Mulhern forfeited all of his unvested shares of restricted stock, restricted stock units and stock options and
did not receive any severance or other benefits in connection with his resignation from the Company.
General Philosophy. We believe that the most effective compensation program is one that is designed to reward all of our
employees, including but not limited to, our Named Executive Officers, for the achievement of our short-term and long-term strategic
goals using a pay for performance system that ultimately drives toward the achievement of increased total shareholder return. Through
this strategy, we seek to closely align the interests of our Named Executive Officers with the interests of our shareholders. Our Named
Executive Officers’ total compensation is comprised of a mix of base salary, performance-based cash bonus, long-term incentive
compensation, retirement and other benefits and perquisites and other personal benefits intended to fulfill these objectives.
Our compensation committee annually reviews our executive compensation program to determine what changes should be made
to the individual components of the program in order to fulfill our objectives. Our compensation committee has taken several
significant steps to align our executive compensation program with these objectives over the past several years, including the
following:
• Eliminating an annual (end of year) executive compensation review and decision process by instead instituting
compensation reviews and decisions for various components of our executive compensation program at multiple points
during the course of a year in an effort to promote retention throughout the year;
•
•
conducting an annual review of base salary and cash bonuses (during the first fiscal quarter) and adopting annual
management incentive plans (beginning in 2013) that award annual cash bonuses based on a combination of the
Company’s achievement of performance-based metrics and the compensation committee’s discretion; and
conducting an annual review of equity compensation awards and making an annual grant of equity awards (during the
second or third fiscal quarter) with a combination of time-based and performance-based vesting conditions (e.g., stock
price and total shareholder return).
6
2014 Business Overview. In 2014, our primary strategy focused on the exploitation and development of our core Haynesville
and Eagle Ford shale assets through a disciplined development program that was primarily funded with cash flows from our
operations. We sought to improve our operating margins as a result of initiatives that were aimed to reduce costs in order to preserve
liquidity and capital resources in preparation for future growth. We also completed significant transactions to enhance our liquidity,
including the following:
• We closed a rights offering and related private placement of our common stock (the “Rights Offering”) on January 17,
2014 which resulted in the issuance of 54,574,734 shares of our common stock for gross proceeds of $272.9 million.
• 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.
• On April 16, 2014, we completed a public offering of $500.0 million in aggregate principal amount of senior unsecured
notes due April 15, 2022 (“2022 Notes”). We received net proceeds of approximately $490.0 million after offering fees and
expenses. The 2022 Notes bear interest at a rate of 8.5% per annum, payable in arrears on April 15 and October 15 of each
year.
• On October 31, 2014, we closed a purchase agreement with an affiliate of Harbinger Group, Inc. to sell our 25.5%
economic interest in Compass Production Partners, LP (“Compass”) for $118.8 million in cash.
Our Named Executive Officers were instrumental in arranging and carrying out each of these transactions. As a result of these
transactions, we enhanced our existing liquidity in order to maintain financial flexibility particularly in the current low commodity
price environment and plan for future growth.
Key Compensation Decisions in 2014. We believe that our compensation for Named Executive Officers (including
Mr. Mulhern) for fiscal 2014 was consistent with the objectives of our compensation philosophy and with our performance, and were
also consistent with the purposes of retaining and incentivizing our Named Executive Officers. The key compensation actions taken
with respect to our Named Executive Officers in 2014 (including Mr. Mulhern) are summarized below:
•
In January 2014, to retain and incentivize them to continue providing services in light of the senior management changes in
2013 and the search process for a replacement chief executive officer, the compensation committee recommended, and the
board of directors approved, a separate Bonus and Retention Agreement (as defined below) with each of Messrs. Boeing,
Hickey and Mulhern that provides for certain benefits upon a Qualifying Termination (as defined below).
• On April 21, 2014, our board of directors adopted the 2014 Management Incentive Plan (the “2014 Management Incentive
Plan”) to pay a cash bonus to our officers and replace the management incentive plan for 2013 (the “2013 Management
Incentive Plan”). The 2014 Management Incentive Plan provides performance-based metrics that account for 60% of the
bonus for each officer with the compensation committee having discretion over the remaining 40% of the bonus.
• On June 30, 2014, the compensation committee (i) approved a form of performance-based restricted stock unit award
agreement under the Incentive Plan and the performance criteria for grants of restricted stock units (“RSUs”) subject to
performance-based vesting conditions and (ii) granted performance-based RSUs to our Named Executive Officers.
•
In September 2014, in connection with Mr. Burnett’s appointment as Chief Financial Officer, he was awarded (i) an
increased annual base salary of $475,000, (ii) 100,000 shares of restricted stock, (iii) 39,063 shares of time-based restricted
stock and 39,063 performance-based RSUs, and (iv) an increased target bonus equal to 80% of his base salary under the
2014 Management Incentive Plan. In addition, we entered into a retention agreement with Mr. Burnett in connection with
his appointment that provides for certain benefits upon a Qualifying Termination.
Consistency with Compensation Objectives. We believe that the compensation decisions in 2014 were consistent with the
objectives of our compensation philosophy because:
• Competition for highly skilled, technical employees in the oil and natural gas industry remained intense in 2014;
• We continue to model our executive compensation incentives toward achieving long-term equity growth by using
significant vesting conditions, including conditions tied to our future stock price, to reward and retain our Named
Executive Officers for contributions to the Company’s long-term performance and value;
• Cash bonus payouts for Named Executive Officers and other officers under the 2014 Management Incentive Plan are tied
to the achievement of several key performance-based metrics; and
• We have retained several key officers and other management personnel and believe that our senior management team,
together with a new chief executive officer, will work to fulfill our business strategy and increase shareholder return.
7
Overview of Compensation Program
The compensation committee of our board of directors has responsibility for establishing, implementing and continually
monitoring adherence with our compensation philosophy. The compensation committee reviews and recommends to our board of
directors the compensation and benefits for our executive officers, administers our stock plans and assists with the establishment of
general policies relating to compensation and benefits for all of our employees. The compensation committee seeks to ensure that the
total compensation paid to our officers is fair, reasonable and competitive. Generally, the types of compensation and benefits provided
to our executive officers are similar to those provided to our other officers and managers.
The following discussion summarizes in more detail our executive compensation program, including our compensation
objectives and philosophies, the processes and sources of input that are considered in determining compensation for our Named
Executive Officers and an analysis of the compensation paid to or earned by our Named Executive Officers in 2014.
Compensation Philosophy and Objectives
We believe that the most effective compensation program is one that is designed to reward all of our employees, not just
executives, for the achievement of our short-term and long-term strategic goals.
When establishing total compensation for our Named Executive Officers, our compensation committee has the following
objectives:
•
•
•
to attract, retain and motivate highly qualified and experienced individuals;
to ensure that a significant portion of their total compensation is “at risk” in the form of equity compensation;
to ensure annual cash bonus payouts for Named Executive Officers and other officers are tied to the achievement of several
key performance-based metrics; and
•
to offer competitive compensation packages that are consistent with our core values.
Over the last several years, our focus was to maximize shareholder value by increasing reserves, production and cash flow in a
cost-effective manner through the appraisal and development of the Company’s shale resources, particularly in the Haynesville and
Eagle Ford shale formations. Proper development of these shale properties requires personnel with significant technical knowledge
and expertise that encompasses analyzing geological and geophysical data and possessing the skills necessary to drill and complete
these high-pressure wells to maximize the economic potential. As a result, we have cultivated a skilled workforce with core
competencies exploiting and developing complex shale resources. This skilled workforce is integral to the execution of our corporate
strategy.
Competition for skilled, technical employees in the oil and natural gas industry remained intense throughout 2014, particularly
for individuals with experience analyzing and exploiting shale resources. In 2014, we implemented the use of performance-based
RSUs and continued our philosophy of using restricted stock with significant time and performance-based vesting conditions as an
incentive for our officers, including our Named Executive Officers, and our other selected employees primarily because we believed:
•
•
•
•
restricted stock awards and performance-based RSUs help ensure that a significant portion of selected employees’ total
compensation is “at risk”;
restricted stock awards and performance-based RSUs are designed to allow selected employees to acquire a direct
ownership interest in us over time and therefore be fully aligned with our shareholders;
restricted stock awards and performance-based RSUs with vesting conditions tied to the price of our common stock align
the interest of our officers with our shareholders;
restricted stock awards are designed to be less vulnerable than stock options to volatility in our stock price, which is often
impacted by volatile swings in the price of natural gas, and therefore serve as a more meaningful long-term retention
vehicle even if our stock price decreased in the short-term; and
• based on market data provided by our outside compensation consultant, awarding restricted stock and performance-based
RSUs would allow the Company to offer similar incentives to those companies with whom we compete for skilled talent
since most of the companies in our peer group issue restricted stock or RSUs as part of their executive compensation
incentives.
During 2014, our compensation committee decided not to award any stock options to our Named Executive Officers and
implemented the use of performance-based RSUs. The performance-based RSUs are structured to incentivize our Named Executive
Officers to maximize the long-term value of our common stock, with the number of shares vesting being determined based on our total
8
shareholder return during the period from the date of grant to the third anniversary of the date of grant. The performance-based RSUs
only vest and convert into shares of our common stock if our percentile rank within a peer group established by the compensation
committee equals or exceeds 35% during the measurement period. For additional information concerning these awards, see “—
Executive Compensation Components—Long-Term Incentive Compensation—Restricted Stock Units.”
Role of Executive Officers in Compensation Decisions
Our board of directors has delegated authority to the compensation committee to make all compensation decisions for our
executive officers and approve all grants of equity awards to our executive officers and certain other selected officers. The
compensation committee annually reviews the performance of our chief executive officer, unless such position is vacant. In addition,
our chief executive officer has historically reviewed the performance of each other executive officer on an annual basis. During the
time period that we have not had a chief executive officer, our compensation committee has reviewed the performance of each other
executive officer. The conclusions and recommendations based on these reviews, including with respect to salary adjustments and
annual bonus award amounts, are determined by the compensation committee. The compensation committee may exercise its
discretion in modifying any recommended adjustments or awards to our executives and has the final authority to establish the
compensation packages for our executive officers. The compensation committee may delegate authority and responsibilities to
subcommittees, as long as such subcommittees consist of not less than two members.
Setting Executive Compensation
Outside Consulting Firm. In November 2013, the compensation committee engaged Frederic Cook to conduct an annual review
of our total compensation program for our Named Executive Officers, as well as for other key executives. The compensation
committee selected Frederic Cook to provide these services based on, among other things, Frederic Cook’s reputation, substantial
insight and experience with executive compensation programs in our industry.
Independence of Consulting Firm. The compensation committee annually reviews the performance, independence and related
fees paid to executive compensation consultants and has concluded that our current compensation consultant, Frederic Cook, is
independent. During 2014, the Company paid Frederic Cook $119,519 in fees for its executive compensation consulting services.
Peer Group. In making compensation decisions, the compensation committee compares each element of total compensation
against a peer group of publicly-traded oil and natural gas companies with similar operations and revenue. The peer group consists of
companies against which the compensation committee believes we compete for talent and for shareholder investment. Our peer group
in 2014 consisted of the following companies: Bill Barrett Corporation; Cabot Oil & Gas Corporation; Cimarex Energy Company;
Comstock Resources Inc.; Concho Resources, Inc.; Continental Resources Inc.; Forest Oil Corporation; Penn Virginia Corporation;
Petroleum Development Corporation; Quicksilver Resources Inc.; Range Resources Corporation; Rosetta Resources Inc.; Sandridge
Energy, Inc.; SM Energy Company; Stone Energy Corporation; Swift Energy Company; Ultra Petroleum Corporation; W&T
Offshore, Inc. and Whiting Petroleum Corporation.
In comparing the Company’s executive compensation levels to those of its peer group, the compensation committee looked at
base salary, cash incentives, other compensation (which includes restricted stock, RSUs, stock options, other types of equity
compensation, pensions, and perquisites), and total compensation for 2013 (the most recent year for which information regarding the
peer group’s executive compensation was available).
Total Direct Compensation. We compete with many larger companies for top executive-level talent. Our compensation
committee took into consideration a number of factors when setting and determining the total direct compensation (base salary, cash
bonus and the value of the individual’s equity awards granting during that year) for our Named Executive Officers (including
Mr. Mulhern) in 2014, including exercise prices for existing stock options and the vesting periods for previously issued restricted
stock awards. Although our compensation committee does not identify specific target ranges for the total direct compensation of each
Named Executive Officer, the compensation committee generally set total direct compensation for our Named Executive Officers
(including Mr. Mulhern) between the market median and the seventy-fifth percentile of compensation paid to similarly situated
executives of the companies comprising the peer group. The compensation committee determined that the level of 2014 total direct
compensation for our Named Executive Officers (including Mr. Mulhern) was appropriate based on an analysis of our peer group’s
total direct compensation and other market data that our compensation committee deemed relevant.
A significant percentage of total compensation for our Named Executive Officers is allocated to equity awards as a result of our
compensation philosophy described above. Restricted stock awards with significant vesting and other conditions and performance-
based RSUs with significant vesting conditions are aimed at ensuring that those executives remain with the Company and are
incentivized over a long-term horizon to maximize shareholder value. In addition, the compensation committee considers the
9
Company’s historical burn rate when determining what restricted stock awards and performance-based RSUs are appropriate. The
Company’s three-year average burn rate (using ISS’ methodology) was approximately 1.6%.
There is no pre-established policy or target for the allocation between either cash and non-cash or short-term and long-term
incentive compensation for our executive officers. Rather, the compensation committee relies on each committee member’s
knowledge and experience as well as information provided by management and the outside consultant to determine the appropriate
level and mix of compensation.
Executive Compensation Components
Our executive compensation program consists of various elements of compensation that are intended to work together to
provide total compensation that attracts, retains and motivates highly qualified and experienced individuals, ensures that a significant
portion of their total compensation is “at risk” in the form of equity compensation and that such compensation represents a
competitive compensation package that is consistent with our core values. For the fiscal year ended December 31, 2014, the principal
components of compensation for Named Executive Officers were:
•
base salary;
• performance-based cash bonus under the 2014 Management Incentive Plan;
•
•
long-term incentive compensation;
retirement and other benefits; and
• perquisites and other personal benefits.
Base Salary
We provide Named Executive Officers with a base salary to compensate them for services rendered during the fiscal year. Base
salary ranges for Named Executive Officers are determined for each executive based on his position and responsibility by using
market and other data that our compensation committee deems relevant.
During its review of base salaries for executives, the compensation committee primarily considers:
• market data provided by our outside consultant;
•
•
•
internal review of the executive’s compensation, both individually and relative to other officers;
individual performance of the executive;
performance of the executive’s department or functional unit;
• our operational performance, with respect to our production, reserves, finding and operating costs, drilling results, risk
management activities and asset acquisitions;
• our financial performance, with respect to our cash flow, net income, cost of capital, general and administrative costs and
common stock price performance;
• our overall competitive position and outlook relative to our industry;
•
•
level of responsibility; and
leadership ability, demonstrated commitment to the organization, motivational skills, attitude and work ethic.
Executive base salary levels are typically reviewed annually by our compensation committee and thereafter during the year if
significant changes are made in an executive’s duties or responsibilities. In December 2012, the compensation committee reviewed the
annual base salaries for our Named Executive Officers and decided not to make any changes for fiscal 2013. During 2013, the
compensation committee increased the base salary of Mr. Hickey to $750,000 in connection with his increased duties and
responsibilities upon being appointed our president on February 28, 2013. During 2014, the compensation committee increased
Mr. Burnett’s base salary to $475,000 in connection with his appointment as chief financial officer effective September 19, 2014, but
did not make any other changes to the base salaries for our other Named Executive Officers (including Mr. Mulhern). The
compensation committee has determined not to make any changes to the base salary levels of our Named Executive Officers for 2015.
10
Cash Bonus
Prior to 2013, we typically paid year-end discretionary cash bonuses to each of our Named Executive Officers based on the
Company’s performance during the year and an analysis by our compensation committee of our peer group’s total cash compensation
and other market data. The payment of any cash bonus to Named Executive Officers was approved by our compensation committee,
whose determination was historically based on the overall success of our company and not as a result of any particular financial,
operational or individual performance criteria or target.
2013 Management Incentive Plan. On February 28, 2013, our board of directors adopted the 2013 Management Incentive Plan
to replace our historical year-end discretionary cash bonuses for our officers, including our Named Executive Officers. The 2013
Management Incentive Plan created an annual incentive pool for the calendar year beginning January 1, 2013 and ending on
December 31, 2013 for our Named Executive Officers (including Mr. Mulhern) and certain other officers based on achievement of
certain performance measures and the discretion of the compensation committee. In fiscal 2013, we achieved the threshold goal for
three of the five performance measures of the Company and the compensation committee’s determination with respect to the
discretionary portion of the incentive pool was based primarily on management’s execution of the Company’s strategic goals during
2013. The compensation committee had the authority to determine the amounts of the individual awards to eligible employees under
the 2013 Management Incentive Plan. The compensation committee approved the payment of the following individual cash bonus
awards to our Named Executive Officers under the 2013 Management Incentive Plan.
Name
2013 Management
Incentive Plan Bonus
Harold L. Hickey ............................................................................... $
William L. Boeing ............................................................................. $
Mark F. Mulhern ............................................................................... $
240,000
160,000
180,000
For additional information concerning the achievement of certain performance measures and the calculation of the incentive
pool under the 2013 Management Incentive Plan, see “Compensation Discussion and Analysis—Executive Compensation
Components—Cash Bonus—2013 Management Incentive Plan” in our Definitive Proxy Statement filed with the SEC on April 7,
2014.
2014 Management Incentive Plan. In April 2014, the board of directors adopted a new performance-based cash bonus plan with
an initial performance period that began on January 1, 2014 and ended on December 31, 2014 (the “Performance Period”). The
purpose of the 2014 Management Incentive Plan is to attract and retain the Company’s management team and to encourage them to
remain with, and devote their best efforts to, the Company and to reward them for outstanding performance, thereby advancing the
interests of the Company and aligning management’s interests with those of the Company’s shareholders.
The compensation committee administers, interprets and makes determinations under, the 2014 Management Incentive Plan. For
the Performance Period, the compensation committee determined that the Named Executive Officers and certain other officers were
eligible for awards under the 2014 Management Incentive Plan. In addition, the compensation committee established the following
performance measures as the basis for the awards under the 2014 Management Incentive Plan for the Performance Period: production,
adjusted EBITDA and general and administrative costs. In addition, the compensation committee set the threshold achievement, target
achievement and maximum achievement levels for each performance measure that is described in further detail below.
Each award has two components: sixty percent (60%) of an award is based on the achievement of the three performance
measures and the remaining forty percent (40%) is determined in the sole discretion of the compensation committee. For the
Performance Period, the compensation committee established a payout schedule that varies among the participants and is based on a
percentage of the participant’s base salary (the “award amount”). Sixty percent of the award amount was paid based on the Company’s
overall performance level, which is the sum of the weighted actual achievement of the performance goals for each performance
measure in the Performance Period. Achievement of the performance goals was calculated on the basis of straight-line interpolation
between the threshold achievement, target achievement and maximum achievement levels of each performance measure. The
remaining forty percent (40%) of the award amount was paid based on the sole discretion of the compensation committee.
The 2014 Management Incentive Plan also includes provisions relating to the effect of a change in control of the Company as
defined in the 2014 Management Incentive Plan or a participant’s termination of employment.
11
For the Performance Period, each Named Executive Officer was entitled to an award based on the following performance
measures and performance goals. The target goals below represented the midpoints of the Company’s guidance for 2014. The fiscal
2014 performance targets and actual results for the performance measures of the Company taking into account acquisitions and
dispositions during 2014 are set forth below:
Performance Measures
Weight
Threshold
Target
Maximum
Actual
Performance
Production (Mcfe) (1) ...................................................................
20%
132,700
140,200
147,600
135,740
Adjusted EBITDA (dollars in millions) (2) ..................................
20% $
387.6 $
409.9 $
430.3 $
391.2
General and administrative costs (dollars in millions) (3) ............
20% $
73.1 $
69.6 $
66.1 $
61.0
Discretion of the compensation committee ...................................
40%
(1) Production represents the net interest volumes of oil, natural gas and natural gas liquids stated on a Mcfe basis.
(2) Adjusted EBITDA means earnings before interest, taxes, depreciation, depletion, amortization, ceiling test write-downs,
unrealized gains or losses on derivative financial instruments and other non-cash income and expense items.
(3) General and administrative costs represents expenses relating to the payment of employee compensation and benefits (other than
equity and equity-based compensation), rent for office space, audit, legal, consulting and other professional fees, 2014
Management Incentive Plan systems and overhead costs, and such other “general and administrative costs,” as determined under
our standard accounting procedures and reported in our audited financial statements (reported net of overhead amounts
reimbursed to us by working interest owners and joint venture partners, and net of amounts that are capitalized), but not
including such expenses associated with the acquisition, exploration, exploitation, development, production or operation of our
oil and gas properties.
Once the overall performance level was determined, the maximum award amounts for the Named Executive Officers were
determined using the following payout schedule:
Performance Level Payout Schedule
Percentage of
Base Salary
for Below
Threshold
Level
Performance
Percentage
of Base
Salary for
Threshold
Level
Performance
Percentage
of Base
Salary for
Target Level
Performance
Percentage
Base Salary
for
Maximum
Level
Performance
Harold L. Hickey ..................................................
William L. Boeing ................................................
Richard A. Burnett ...............................................
0%
0%
0%
45%
45%
40%
90%
90%
80%
180%
180%
160%
During 2014, our Named Executive Officers were instrumental in arranging and carrying out significant transactions to enhance
the Company’s liquidity, including an equity offering, a debt offering and refinancing transaction and the sale of certain non-core
assets and our interest in Compass. As a result of these transactions, the Company reduced its total debt by approximately $460
million in order to maintain greater financial flexibility to face the challenges associated with the current low commodity price
environment and plan for future growth. The compensation committee approved the payment of the following individual cash bonus
awards to our Named Executive Officers under the 2014 Management Incentive Plan, which were paid on March 13, 2015.
Mr. Mulhern did not receive a cash bonus or any other benefits under the 2014 Management Incentive Plan since he resigned prior to
the end of the Performance Period under the 2014 Management Incentive Plan.
Name
2014 Management
Incentive Plan Bonus
Harold L. Hickey ............................................................................... $
Richard A. Burnett ............................................................................. $
William L. Boeing ............................................................................. $
612,225
296,891
408,150
12
Long-Term Incentive Compensation
Incentive Plan. In many cases over the last several years, incentives granted under the Incentive Plan comprise the largest
portion of our Named Executive Officers’ total compensation package. As a result, a significant portion of compensation is “at risk”
and tied to the performance of the Company. The Incentive Plan was originally adopted and approved by the board of directors of our
predecessor entity in September 2005 and ultimately assumed by us. Over the years, with shareholder approval, we have increased the
number of shares of common stock authorized for issuance under the Incentive Plan. Currently, the number of shares authorized for
issuance under the Incentive Plan is 45,500,000 shares and each share granted that is subject to a full-value award will count as 1.74
shares against the total number of remaining shares we have reserved for issuance under the Incentive Plan. The term of the Incentive
Plan will expire on February 28, 2023. The stated purpose of the Incentive Plan is to provide financial incentives to selected
employees and to promote our long-term growth and financial success by:
•
•
attracting and retaining employees of outstanding ability;
strengthening our capability to develop, maintain and direct a competent management team;
• providing an effective means for selected employees to acquire an ownership interest in us;
• motivating employees to achieve long-range performance goals and objectives; and
• providing incentive compensation competitive with other similar companies.
Another important objective of our long-term incentive compensation is to strengthen the relationship between the long-term
value of the price of our common stock and the potential financial gain for employees. Our compensation committee administers the
Incentive Plan and the awards granted under the Incentive Plan. Awards under the Incentive Plan can consist of incentive stock
options, non-qualified stock options, restricted stock, RSUs, stock appreciation rights and other awards. Until we began using
restricted stock with significant vesting periods in August 2011, we had previously only used stock options under the Incentive Plan as
incentives for our employees. In 2014, we implemented the use of performance-based RSUs and continued our philosophy of using
restricted stock with significant vesting periods as an incentive for our officers and other selected employees primarily because we
believed:
•
•
•
•
restricted stock awards and performance-based RSUs help ensure that a significant portion of selected employees’ total
compensation is “at risk”;
restricted stock awards and performance-based RSUs are designed to allow selected employees to acquire a direct
ownership interest in us over time and therefore be fully aligned with our shareholders;
restricted stock awards and performance-based RSUs with vesting conditions tied to the price of our common stock align
the interest of our officers with our shareholders;
restricted stock awards are designed to be less vulnerable than stock options to volatility in our stock price, which is often
impacted by volatile swings in the price of natural gas, and therefore serve as a more meaningful long-term retention
vehicle even if our stock price decreased in the short-term; and
• based on market data provided by our outside compensation consultant, awarding restricted stock and performance-based
RSUs would allow the Company to offer similar incentives to those companies with whom we compete for skilled talent
since most of the companies in our peer group issue restricted stock or RSUs as part of their executive compensation
incentives.
Previous awards and grants of stock options, restricted stock or RSUs, whether vested or unvested, generally do not have a
significant impact on the current year’s awards and grants unless otherwise considered by our compensation committee.
Restricted Stock Grants. Restricted stock consists of shares of common stock that may not be sold, transferred, pledged,
hypothecated, encumbered or otherwise disposed of, and that may be forfeited in the event of certain terminations of employment or
service, prior to the end of a restricted period specified by the compensation committee. Restricted stock awards with significant
vesting periods and other conditions help ensure that those individuals remain with the Company and are incentivized over a long-
term horizon to maximize shareholder value. Pursuant to the terms of the restricted stock award agreements, the shares of restricted
stock granted:
•
on September 2, 2014 to Mr. Burnett in connection with his appointment as Chief Financial Officer vest over a three year
period in equal portions beginning on the first anniversary of the grant date, such that 1/3 of the shares vest on the first
anniversary of the grant date, 1/3 of the shares vest on the second anniversary of the grant date and 1/3 of the shares vest on
the third anniversary of the grant date;
13
•
•
on July 1, 2014 to each of our Named Executive Officers (including Mr. Mulhern) vest over a three year period in equal
portions beginning on the first anniversary of the grant date, such that 1/3 of the shares vest on the first anniversary of the
grant date, 1/3 of the shares vest on the second anniversary of the grant date and 1/3 of the shares vest on the third
anniversary of the grant date;
on August 13, 2013 in two separate restricted stock awards to certain of our Named Executive Officers (including
Mr. Mulhern) and selected other officers were subject to a performance vesting schedule based upon the first trading day
immediately following the date that the fair market value of a share of our common stock equals or exceeds $10.00 in one
grant and $15.00 in the other grant during any thirty (30) consecutive trading day period (the “Attainment Date”). The
shares of restricted stock vest as follows: (i) if the Attainment Date occurs on or before the first anniversary of the grant
date, 50% of the shares vest on the first anniversary of the grant date and the remaining 50% vest on the second
anniversary of the grant date; (ii) if the Attainment Date occurs after the first anniversary of the grant date but before the
second anniversary of the grant date, 50% of the shares vest on the Attainment Date and the remaining 50% vest on the
second anniversary of the grant date; (iii) if the Attainment Date occurs after the second anniversary of the grant date but
before the fifth anniversary of the grant date, 100% of the shares vest on the Attainment Date, in each case, provided the
applicable Named Executive Officer is employed by or providing services to the Company or a subsidiary on such date;
• on April 1, 2013 to Mr. Mulhern in connection with the commencement of his employment as our executive vice president
and chief financial officer were scheduled to vest over a three year period in equal portions beginning on the first
anniversary of the grant date, such that 1/3 of the shares vested on the first anniversary of the grant date while the
remaining shares were forfeited back to the Company in connection with Mr. Mulhern’s resignation;
•
•
•
on December 13, 2012 to certain of our Named Executive Officers and other selected officers and employees, vest over a
three year period in equal portions beginning on the first anniversary of the grant date, such that 1/3 of the shares vested on
the first anniversary of the grant date, 1/3 of the shares vested on the second anniversary of the grant date and 1/3 of the
shares are scheduled to vest on the third anniversary of the grant date; and
on November 21, 2011 to certain of our Named Executive Officers and selected officers, vest over a five year period with
60% of these shares having vested on the third anniversary of the grant date, 20% of these shares vesting on the fourth
anniversary of the grant date and 20% of these shares vesting on the fifth anniversary of the grant date; and
become fully vested, subject to their early termination as provided in the restricted stock award agreements, immediately
prior to a change of control of us or upon the death or disability of the holder as defined in the Incentive Plan.
Effective July 1, 2014, the compensation committee granted a total of 781,254 shares of restricted stock to a select group of
employees, which included our Named Executive Officers and Mr. Mulhern, based on a target percentage of such employee’s annual
base salary approved by the compensation committee at the time of the grant, pro rata for any partial year of service. Effective
September 2, 2014, the compensation committee granted an additional 139,063 shares of restricted stock to Mr. Burnett in connection
with his appointment as Chief Financial Officer. Under the terms of the Incentive Plan at the time of the grants, each share of
restricted stock granted counted as 1.74 shares against the total number of remaining shares we have reserved for issuance under the
Incentive Plan, subject to future forfeitures of unvested shares prior to the applicable vesting dates, such that 1,601,352 shares were
deemed to have been granted under the Incentive Plan.
The table below summarizes shares of restricted stock issued under the Incentive Plan to each of the Named Executive Officers
(including Mr. Mulhern) during 2014, 2013 and 2012:
Named Executive Officer
Harold L. Hickey ...............................................
Richard A. Burnett .............................................
William L. Boeing .............................................
Mark F. Mulhern(3) ...........................................
Restricted Stock
Awarded in
2014
Restricted Stock
Awarded in
2013
Restricted Stock
Awarded in
2012
104,167
178,126(1)
104,167
104,167
97,600
85,000(2)
48,800
173,200
20,800
—
23,100
—
(1) The compensation committee issued, effective September 2, 2014, a total of 139,063 shares of restricted stock to Mr. Burnett in
connection with his appointment as our Chief Financial Officer.
(2) Represents shares of restricted stock granted to Mr. Burnett in connection with his commencement of employment with the
Company.
(3) All shares of restricted stock issued to Mr. Mulhern during 2014 and the unvested portion of the shares of restricted stock issued
to Mr. Mulhern in 2013 were forfeited in connection with his resignation, effective September 19, 2014.
14
Restricted Stock Units. RSUs consist of equity awards that convert into shares of our common stock upon the achievement of
either time-based or performance-based vesting conditions. RSUs with significant performance-based vesting conditions help ensure
that individuals remain with EXCO and are incentivized over a long-term horizon to maximize shareholder value. The compensation
committee granted 104,167 performance-based RSUs to each of Messrs. Hickey, Mulhern and Boeing on July 1, 2014, 39,063
performance-based RSUs to Mr. Burnett on July 1, 2014 and an additional 39,063 performance-based RSUs to Mr. Burnett on
September 2, 2014 in connection with his appointment as our Chief Financial Officer. Mr. Mulhern forfeited all of his performance-
based RSUs in connection with his resignation from the Company.
The RSU award agreement provides that a participant is eligible to vest in and receive a number of shares of the common stock
ranging from 0% to 200% of the target number of RSUs granted based on the attainment of total shareholder return (“TSR”) goals
during the period commencing on and including the date of grant and ending on third anniversary of the date of grant (the
“Measurement Period”). The RSUs will vest upon the third anniversary of the date of grant, July 1, 2017 (the “Vesting Date”), subject
to the achievement of certain performance criteria set forth below, provided that the participant is providing services to the Company
or a subsidiary on that date and subject to the restrictions and conditions of the Incentive Plan.
The number of RSUs that vest and convert into shares of our common stock is dependent upon the Company’s TSR achieved
during the Measurement Period relative to the TSR achieved during the Measurement Period by the Company’s peer group
determined by the compensation committee. Each vested RSU will convert into one share of our common stock. If the percentile rank
of the Company’s TSR within the peer group is below 35%, then no RSUs will vest. If the percentile rank of the Company’s TSR
equals 35%, then 50% of the target RSUs will vest, and for every increase in the Company’s percentile rank within the peer group
over 35%, a proportionate percentage of target RSUs will vest on the Vesting Date (i.e., if the percentile rank of the Company’s TSR
is between 35%-49% of the peer group, then 50%-99% of target RSUs will vest; if the percentile rank of the Company’s TSR is
between 50%-74% of the peer group, then 100%-199% of target RSUs will vest; and if the percentile rank of the Company’s TSR is
75% of the peer group or above, then 200% of target RSUs will vest) and convert into shares of our common stock (calculated on the
basis of straight-line interpolation applied on the change in performance between threshold and target, and between target and
maximum levels of percentile rank). In addition, all unvested RSUs become immediately vested and convert into shares of our
common stock upon a change in control based on the achievement of the performance criteria determined as of the closing date of the
change in control as defined in the Incentive Plan; provided that the participant is employed by or providing services to the Company
as of the change in control. Unvested RSUs are forfeited upon the earliest of (i) the Vesting Date and (ii) the participant’s termination
of service, provided that if such termination of service is due to death or disability, such participant is treated as continuing to provide
services during the Measurement Period.
Stock Option Grants. A stock option becomes valuable only if the price of our common stock increases above the option
exercise price and the holder of the option remains employed during the period required for the option to “vest,” thus providing an
incentive for an option holder to remain our employee. In addition, stock options link a portion of an employee’s compensation to
shareholders’ interests by providing an incentive to increase the market price of our common stock. All options are awarded with an
exercise price equal to the closing price of our common stock on the NYSE on the date of the grant. The compensation committee has
never granted options with an exercise price that is less than the closing price of our common stock on the grant date, nor has it
granted options that have an exercise price based on a date other than the grant date.
Pursuant to the terms of our stock option agreements, the stock options granted:
•
•
•
are vested as to 25% of the shares subject to the option on the date of grant and will vest an additional 25% on each of the
next three anniversaries of the date of grant;
expire on either the tenth or the fifth anniversary of the date of grant, or sooner under some circumstances; and
become fully vested and exercisable, subject to their early termination as provided in the option agreements, immediately
prior to a change of control of us.
15
We granted stock option bonuses in August 2013 to selected employees, including Messrs. Hickey, Boeing and Mulhern, based
on a target percentage equal to between 55% and 125% of such employee’s annual base salary approved by the compensation
committee at the time of the grant, pro rata for any partial year of service, multiplied by such person’s base salary and then divided by
a Black-Scholes grant date valuation. Based on this formula, we granted stock options with an exercise price equal to $7.68 per share
to the Named Executive Officers in August 2013 as set forth in the table below. All of Mr. Mulhern’s stock options set forth in the
table below were forfeited back to the Company following his resignation. We did not grant any stock options to the Named Executive
Officers during 2014.
Name
Base Salary
Grant Date Fair Value
2013 Stock Options
Harold L. Hickey .................................................. $
750,000 $
Mark F. Mulhern ................................................... $
750,000 $
William L. Boeing ................................................ $
500,000 $
752,905
564,771
376,636
204,900
153,700
102,500
Historical Long-Term Incentive Grants. The following table shows the number of our employees as of December 31st of each
year set forth below, the number of stock options granted to new hires, the number of stock options granted as an annual incentive
bonus and the number of shares of restricted stock and performance-based RSUs granted (excluding the effect of the applicable
fungible share ratio) during each of the years set forth below.
2014
2013
2012
Number of Employees .......................................................
558
755
919
Stock Option Awards to New Hires ...................................
141,525
577,000
106,500
Annual Option Bonus Awards ...........................................
—
2,269,500
—
Restricted Stock Awards(1) ...............................................
1,339,782
1,292,700
926,900
RSU Awards(1) .................................................................
820,317
—
—
(1) The shares of restricted stock issued in 2012, 2013 and 2014 and the number of performance-based RSUs granted in 2014
resulted in a reduction of 1,946,490 shares, 2,285,298 shares and 5,185,924 shares, respectively, available for issuance under the
Incentive Plan due to the effect of the applicable fungible share ratios (subject to any forfeitures of unvested shares prior to the
applicable vesting dates).
Stock Ownership Guidelines. We do not have formal stock ownership guidelines. However, our executive officers are
encouraged to maintain or establish a significant level of direct stock ownership.
Hedging Policies. Pursuant to our insider trading policy, we discourage our directors, officers, employees and consultants
(collectively, “insiders”) from engaging in transactions pursuant to which such persons would hedge the economic ownership of our
securities. Under the insider trading policy, insiders are prohibited from engaging in short sales of our securities and in transactions in
publicly traded options, are subject to limitations on standing orders and are discouraged from placing our securities in a margin
account or being pledged as collateral.
Retirement and Other Benefit Plans
401(k) Plan. All of our employees are eligible to participate in the EXCO Resources, Inc. 401(k) Plan. While the amount of the
matching contribution under the 401(k) plan is discretionary, in recent years we have matched 100% of employee contributions to the
401(k) plan up to the Internal Revenue Service limit with vesting of Company matching contributions based on years of service with
us.
Severance Plan. The Fourth Amended and Restated Severance Plan (the “Severance Plan”) is applicable to all of our employees
in the event of a change of control. The Severance Plan provides for the payment of severance equal to 1.25 times an employee’s
annual base salary in the event the employee’s employment is terminated or there is an adverse change in the employee’s job or
compensation within twelve months following a change of control, as defined in the Severance Plan. For more information about the
Severance Plan, see “—Compensation of Executive Officers—Potential Payments Upon Termination or Change-in-Control.”
16
Other Benefits Plans. We offer a variety of health and benefit programs to all employees, including medical, dental, vision, life
insurance and disability insurance. Our Named Executive Officers (including Mr. Mulhern during his employment with us) are
generally eligible to participate in these employee benefit plans on the same basis as the rest of our employees. During 2014, we also
provided physical exams for our Named Executive Officers.
Retention Agreements
On January 17, 2014, we entered into a separate Bonus and Retention Agreement with each of Messrs. Hickey, Mulhern and
Boeing (collectively, the “Bonus and Retention Agreements”) in order to retain and incentivize them to continue providing services to
the Company in light of the resignation of the Company’s former chief executive officer and the board of directors’ search process for
a replacement chief executive officer. In addition, in connection with Mr. Burnett’s appointment as Chief Financial Officer, we
entered into a Retention Agreement with Mr. Burnett, effective as of September 1, 2014 (the “Burnett Retention Agreement” and,
collectively with the Bonus and Retention Agreements, the “Retention Agreements”), in order to retain and incentivize Mr. Burnett to
continue providing services to the Company. Mr. Mulhern’s Retention Agreement terminated in all respects effective September 19,
2014 in connection with his resignation from the Company.
Retention Bonus. Pursuant to the terms of the Retention Agreements, each of Messrs. Hickey, Mulhern and Boeing received a
cash payment on June 30, 2014 equal to fifty percent (50%) of their base salary (the “Retention Bonus”), or $375,000, $375,000 and
$250,000, respectively. The Burnett Retention Agreement does not provide for the payment of a Retention Bonus.
Burnett Initial Severance Benefits. If Mr. Burnett’s employment is terminated by the Company without “cause” or he terminates
his employment for “good reason” (collectively, a “Qualifying Termination”) during the period (the “Initial Severance Period”)
beginning on September 1, 2014 and ending on the day immediately prior to the first day of the Special Severance Period (as defined
below), he is entitled to receive, subject to certain exceptions, the following severance benefits (the “Initial Severance Benefits”):
• A cash payment equal to one (1) times Mr. Burnett’s annual base salary (less applicable income and employment tax
withholdings), fifty percent (50%) of which will be paid on the sixtieth (60th) day following Mr. Burnett’s Qualifying
Termination and fifty percent (50%) of which will be paid on the one (1) year anniversary of Mr. Burnett’s Qualifying
Termination; and
• COBRA benefits for up to twelve (12) months following Mr. Burnett’s Qualifying Termination.
Special Severance Benefits. The Retention Agreements provide for certain benefits upon a Qualifying Termination of Messrs.
Hickey, Boeing and Burnett during the period (the “Special Severance Period”) beginning on the date that a new person (other than a
person who was employed by the Company as of the date of the applicable Retention Agreement) is hired as the chief executive
officer of the Company (the “Commencement Date”) and ending on the earlier of (A) the effective date of a Change of Control or
(B) the date that is two years following the Commencement Date. The severance benefits (the “Special Severance Benefits”) provided
during the Special Severance Period include the following:
• A cash payment equal to two (2) times such executive’s base salary (less applicable income and employment tax
withholdings), fifty percent (50%) of which will be paid on the sixtieth (60th) day following such executive’s Qualifying
Termination and fifty percent (50%) of which will be paid on the one (1) year anniversary of such executive’s Qualifying
Termination;
• COBRA benefits for up to eighteen (18) months following such executive’s Qualifying Termination;
• Accelerated vesting of any unvested restricted stock awards with time-based vesting to the date of the Qualifying
Termination;
• Extension of the exercise period for any vested stock options for one (1) year following the date of such executive’s
Qualifying Termination (or if earlier, the date the options would have expired if such executive had remained employed by
the Company); and
• With respect to Mr. Burnett only, to the extent any performance-based RSUs granted by the Company to Mr. Burnett on
July 1, 2014 (the “July PRSUs”) are still outstanding and have not yet vested by the date of his Qualifying Termination,
such July PRSUs shall not be forfeited upon such Qualifying Termination, and Mr. Burnett shall be treated as if is
continuing to provide services for purposes of applying the vesting provisions set forth in the award agreement for such
July PRSUs through July 1, 2017.
In order to receive any of the Initial Severance Benefits or Special Severance Benefits, as applicable, the executive must sign
and return a release of claims, within thirty (30) days of a Qualifying Termination, and any applicable revocation period must have
expired. Receipt of the Initial Severance Benefits or Special Severance Benefits, as applicable, is also contingent on such executive’s
continued compliance with certain confidentiality, non-disparagement and non-solicitation provisions contained in his Retention
17
Agreement. In the event that a Change of Control occurs prior to an executive’s Qualifying Termination, no Initial Severance Benefits
or Special Severance Benefits will be paid under the Retention Agreement, and such executive’s right to severance payments, if any,
shall be governed by the terms of the Severance Plan. Further, with respect to the Burnett Retention Agreement, no Special Severance
Benefits are payable if his Qualifying Termination occurs during the Initial Severance Period; rather, Mr. Burnett would only be
entitled to receive his Initial Severance Benefits.
Compensation Business Risk Review
While a significant portion of our annual cash bonus structure is based on the Company’s achievement of specified operational
and financial performance metrics, we have historically compensated our executive officers and other employees under a structure that
is focused on overall company performance and is not based on the achievement of specified targets or milestones by any one
individual, department or function. We believe this compensation structure protected the Company and its shareholders against
excessive risk taking by individuals, departments or functions who may have otherwise been motivated to achieve a particular target
or milestone even if the achievement of that objective would not necessarily have contributed to the overall success of the Company.
For 2014, our board of directors adopted the 2014 Management Incentive Plan, which provided for annual cash bonuses to our
executive officers based on the Company’s achievement of certain performance criteria. In addition, we use restricted stock and RSU
awards with significant vesting periods or conditions because we believe those types of awards incentivize our executive officers and
other employees to achieve our long-term goal of maximizing shareholder value. Restricted stock or RSU awards with significant
vesting periods or conditions help ensure that our executives remain with the Company and are incentivized over a long-term horizon
to maximize shareholder value. The other elements of our compensation are comprised of typical benefit plans, such as a 401(k) plan
and health, life and disability insurance. Accordingly, our compensation committee believes that our compensation policies and
practices do not create unreasonable or inappropriate risks that are reasonably likely to have a material adverse effect on the Company.
Say-on-Pay Vote
In May 2014, we held a shareholder advisory vote to approve the compensation of our Named Executive Officers, commonly
referred to as a say-on-pay vote. Our shareholders approved the compensation of our Named Executive Officers, with over 88% of
shareholder votes cast in favor of our say-on-pay resolution. The compensation committee was mindful of this supportive say-on-pay
vote when making its decisions regarding executive compensation for 2014. The compensation committee intends to take the say-on-
pay votes into consideration in setting future compensation for our Named Executive Officers. We are mindful of the support our
shareholders expressed for our compensation philosophy and the compensation committee remains committed to a focus on long-term
incentive compensation as a strong incentive to reward our employees, including the Named Executive Officers, for achievement of
strategic goals, and we will continue to consider shareholder concerns and feedback in the future. We intend to conduct an advisory
vote to approve executive compensation on an annual basis until the next advisory vote to determine the frequency of future advisory
votes on such compensation.
Tax and Accounting Implications
Deductibility of Executive Compensation
As part of its role, the compensation committee reviews and considers the deductibility of executive compensation under
Section 162(m) of the Code, which provides generally that we may not deduct compensation of more than $1,000,000 that is paid to
certain individuals. We believe that compensation paid under our incentive plans is generally fully deductible for federal income tax
purposes. However, in the future, the compensation committee may approve compensation that will not meet these requirements in
order to ensure competitive levels of total compensation for our executive officers.
Nonqualified Deferred Compensation
On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law, changing the tax rules applicable to
nonqualified deferred compensation arrangements. We believe that we are operating in compliance with the final regulations that
became effective January 1, 2009.
18
Accounting for Share-Based Compensation
Our predecessor adopted the provisions of ASC Topic 718 upon its formation in August 2005. Upon the closing of a series of
mergers in connection with our initial public offering in February 2006, we adopted ASC Topic 718.
Compensation Committee Report
Our compensation committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b)
of Regulation S-K with management and, based on such review and discussions, the compensation committee recommended to our
board of directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
The foregoing report is provided by the following directors, who constitute the compensation committee.
COMPENSATION COMMITTEE*
Robert L. Stillwell, Chairman
Jeffrey D. Benjamin
B. James Ford
Samuel A. Mitchell**
Wilbur L. Ross, Jr.
Jeffrey S. Serota
* Mr. Mulhern resigned from the compensation committee on February 28, 2013.
** Mr. Mitchell was appointed to the compensation committee on September 10, 2013 and therefore did not participate in setting
executive compensation for the fiscal 2012 year.
Compensation of Executive Officers
The total compensation paid to our chief executive officer and president and former chief operating officer, Harold L. Hickey,
our chief financial officer, Richard A. Burnett, our former chief financial officer, Mark F. Mulhern, and William L. Boeing, our vice
president, general counsel and secretary is set forth in the following Summary Compensation Table. For purposes of this section,
references to Named Executive Officers include Mr. Mulhern.
2014, 2013 AND 2012 SUMMARY COMPENSATION TABLE
Name and
Principal Position
Harold L. Hickey(5) .........
Chief Executive Officer
and President and
Former Chief
Operating Officer
Richard A. Burnett(6) .......
Vice President, Chief
Financial Officer and
Chief Accounting
Officer
Mark F. Mulhern(7) ..........
Former Executive Vice
President and Chief
Financial Officer
William L. Boeing ............
Vice President,
General Counsel and
Secretary
Year
2014
2013
2012
Salary
($)
750,000
656,250
450,000
Bonus
($)(1)
Stock
Awards
($)(2)
Option
Awards
($)(3)
Non-Equity
Incentive Plan
Compensation
($)
987,225 1,365,629
621,224
465,000
157,456
362,500
—
752,905
—
2014
409,167
296,891 1,449,263
—
2014
2013
534,135
562,500
375,000 1,365,629
380,000 1,159,918 1,198,411
—
2014
2013
2012
500,000
500,000
500,000
658,150 1,365,629
310,612
410,000
174,867
325,000
—
376,636
—
19
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
All Other
Compensation
($)(4)
Total
($)
—
—
—
23,000 3,125,854
23,000 2,518,379
992,456
22,500
—
17,500 2,172,821
—
—
—
—
—
23,000 2,297,764
32,246 3,333,075
23,000 2,546,779
23,000 1,620,248
22,500 1,022,367
—
—
—
—
—
—
—
—
—
(1) Bonus column for 2013 includes the cash amount paid in March 2014 pursuant to the 2013 Management Incentive Plan. Bonus
column for 2014 includes a cash retention bonus paid pursuant to the Retention Agreements on June 30, 2014 equal to fifty
percent (50%) of base salary for each of Messrs. Hickey, Mulhern and Boeing, or $375,000, $375,000 and $250,000,
respectively, and the cash bonus amount paid in March 2015 pursuant to the 2014 Management Incentive Plan.
(2) This column represents the aggregate grant date fair value of shares of restricted stock issued to each Named Executive Officer
in 2014, 2013 and 2012 in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards
Codification (“ASC”) Topic 718—Compensation—Stock Compensation (“ASC 718”), with the exception that the amount
shown assumes no forfeitures. Assumptions used in the calculation of these amounts are included in “Note 2. Summary of
significant accounting policies—Share-based compensation” and “Note 11. Stock options and awards” to our audited financial
statements for the fiscal year ended December 31, 2014 included in this Annual Report on Form 10-K.
(3) This column represents the aggregate grant date fair value of stock options granted to each Named Executive Officer in 2014,
2013 and 2012 in accordance with ASC Topic 718, with the exception that the amount shown assumes no forfeitures.
Assumptions used in the calculation of these amounts are included in “Note 2. Summary of significant accounting policies—
Share-based compensation” and “Note 11. Stock options and awards” to our audited financial statements for the fiscal year
ended December 31, 2014 included in this Annual Report on Form 10-K.
(4) The amounts shown in this column reflect, for each Named Executive Officer, matching contributions allocated by us to each of
the Named Executive Officers pursuant to the EXCO Resources, Inc. 401(k) Plan as follows: Mr. Hickey—$23,000;
Mr. Burnett—$17,500; Mr. Mulhern—$23,000; and Mr. Boeing—$23,000 for 2014; Mr. Hickey—$23,000; Mr. Mulhern—
$23,000; and Mr. Boeing—$23,000 for 2013; and Mr. Hickey—$22,500; and Mr. Boeing—$22,500 for 2012. We maintained a
suite at the Rangers Ballpark in Arlington, Texas during 2012, 2013 and 2014 and a suite at the American Airlines Center in
Dallas, Texas during 2012 and 2013 for sporting events and other entertainment purposes. We have not included any amounts
related to the suites as a perquisite because tickets to the suites are available to all of our employees on a non-discriminatory
basis, with business entertainment purposes having priority as to use. We no longer maintain either of those suites.
(5) Mr. Hickey became our Chief Executive Officer effective March 30, 2015. Mr. Hickey served as our Chief Operating Officer
from October 2005 until March 2015.
(6) Mr. Burnett became our Chief Financial Officer effective September 19, 2014. In connection with the appointment as Chief
Financial Officer, Mr. Burnett received 139,063 shares of restricted stock.
(7) Mr. Mulhern became our Executive Vice President and Chief Financial Officer on April 1, 2013. In connection with the
commencement of his employment, Mr. Mulhern received a sign-on bonus equal to $200,000 and 100,000 shares of restricted
stock and a stock option to purchase 200,000 shares. Mr. Mulhern resigned from his positions as Executive Vice President and
Chief Financial Officer, effective September 19, 2014. Mr. Mulhern forfeited all of his unvested shares of restricted stock,
restricted stock units and stock options and did not receive any severance or other benefits in connection with his resignation
from the Company.
See “—Compensation Discussion and Analysis—Executive Compensation Components—Base Salary” for a discussion of the
2015 base salaries of our Named Executive Officers.
20
2014, 2013 AND 2012 REALIZED COMPENSATION TABLE
The following table supplements the Summary Compensation Table set forth under “—Compensation of Executive Officers”
above. This table shows the compensation actually realized in the fiscal years ended December 31, 2014, 2013 and 2012 by our
Named Executive Officers. We have included the Realized Compensation Table to better show how our equity compensation drives
actual or “realized” compensation. The primary difference between this supplemental table and the Summary Compensation Table is
the method used to value equity awards. SEC rules require companies to report the grant date fair value of all equity awards in the
Summary Compensation Table for the year for which they were granted. As a result, a significant portion of the total compensation
amounts reported in the Summary Compensation Table related to equity grants that have not yet vested and for which the value is
consequently uncertain. In contrast, the supplemental table below includes only (i) the value of restricted stock awards that vested
during the applicable fiscal year as of the applicable vesting date, (ii) the value of shares of performance-based restricted stock
actually vested based on a performance threshold being met for the performance period ending in the applicable fiscal year and
(iii) the value of performance-based RSUs actually vested based on a performance threshold being met for the performance period
ending in the applicable fiscal year. The supplemental table below also includes only stock options that were exercised during the
applicable fiscal year and shows the value of those awards as of the applicable exercise date. It should be noted that there is no
assurance that the Named Executive Officers will actually realize the value attributed to the restricted stock and RSU awards even in
this supplemental table, since the value of the restricted stock and RSU awards will depend on when the common stock underlying
such awards is sold.
Name and Principal Position
Year
Salary
($)(1)
Bonus
($)(1)
Stock
Awards
Value
Realized
($)(2)
Option
Value
Realized
($)(3)
All Other
Compensation
($)(1)
Total
Realized
Compensation
($)
2014
2013
2012
750,000
656,250
450,000
987,225
465,000
362,500
311,122
73,560
38,391
—
—
—
23,000
23,000
22,500
2,071,347
1,217,810
873,391
2014
409,167
296,891
74,516
—
17,500
798,074
Harold L. Hickey(4) ............................
Chief Executive Officer and
President and Former Chief
Operating Officer
Richard A. Burnett(5) .........................
Vice President, Chief Financial
Officer and Chief Accounting
Officer
Mark F. Mulhern(6) ............................
Former Executive Vice President
and Chief Financial Officer
2014
2013
534,135
562,500
375,000
380,000
185,670
—
William L. Boeing ..............................
Vice President, General Counsel
and Secretary
2014
2013
2012
500,000
500,000
500,000
658,150
410,000
325,000
343,760
81,650
42,604
—
—
—
—
—
23,000
32,246
1,117,805
974,746
23,000
23,000
22,500
1,524,910
1,014,650
890,104
(1) The amount shown in this column for each Named Executive Officer, if any, is identical to the amount set forth in the
corresponding column in the “Summary Compensation Table” above.
(2) This column represents the value, as of the applicable vesting date, of the shares of restricted stock that vested during the
applicable fiscal year, calculated by multiplying the number of shares of restricted stock vested by the closing price on the
vesting date. This column does not include (i) the value of shares of performance-based restricted stock because our
performance did not reach threshold levels during the applicable year or (ii) the value of performance-based RSUs because the
performance period did not end during the applicable fiscal year.
(3) This column represents the aggregate value of all stock options that were exercised during the applicable fiscal year. The value
of exercised stock options is calculated by multiplying the number of options exercised by the difference between the exercise
price and the closing price of our common stock on the exercise date.
(4) Mr. Hickey became our Chief Executive Officer effective March 30, 2015. Mr. Hickey served as our Chief Operating Officer
from October 2005 until March 2015.
(5) Mr. Burnett became our Chief Financial Officer effective September 19, 2014. In connection with the commencement of his
appointment as our Chief Financial Officer, Mr. Burnett received 139,063 shares of restricted stock.
(6) Mr. Mulhern resigned from his positions as Executive Vice President and Chief Financial Officer, effective September 19, 2014.
Mr. Mulhern forfeited all of his unvested shares of restricted stock, restricted stock units and stock options and did not receive
any severance or other benefits in connection with his resignation from the Company.
21
Equity Incentive Awards
The following table sets forth information regarding the plan-based awards under the Incentive Plan granted to each Named
Executive Officer (including Mr. Mulhern) during the fiscal year ended December 31, 2014:
2014 FISCAL YEAR GRANTS OF PLAN-BASED AWARDS
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards
Estimated Future Payouts
Under Equity
Incentive Plan Awards
Name
Grant Date
Threshold
($)
Target
($)
Maximum
($)
Threshold
(#)
Target
(#)
Maximum
(#)
All Other
Stock
Awards:
Number of
Shares of
Stock
or Units
(#)
All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)
Exercise or
Base Price
of Option
Awards
($ /
Share)
Grant
Date
Fair
Value
of Stock
and
Option
Awards
($)(1)
Harold L.
Hickey ......
Richard A.
Burnett ......
Mark F.
Mulhern ....
William L.
Boeing ......
7/1/2014
7/1/2014
—
—
—
—
—
—
—
—
—
—
— 104,167(2)
— 104,167(3)
7/1/2014
7/1/2014
9/2/2014
9/2/2014
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 39,063(2)
— 39,063(3)
— 139,063(4)
— 39,063(5)
7/1/2014
7/1/2014
—
—
—
—
—
—
—
—
—
—
— 104,167(2)(6)
— 104,167(3)(6)
7/1/2014
7/1/2014
—
—
—
—
—
—
—
—
—
—
— 104,167(2)
— 104,167(3)
—
—
—
—
—
—
—
—
—
—
— 602,086
— 763,544
— 225,784
— 286,332
— 650,815
— 286,332
— 602,085
— 763,544
— 602,085
— 763,544
(1) Represents the grant date fair value of the awards computed in accordance with ASC 718, with the exception that the amount
shown assumes no forfeitures. Assumptions used in the calculation of these amounts are included in “Note 2. Summary of
significant accounting policies—Share-based compensation” and “Note 11. Stock options and awards” to our audited financial
statements for the fiscal year ended December 31, 2014 included in this Annual Report on Form 10-K.
(2) Represents shares of restricted common stock issued to the Named Executive Officer pursuant to a restricted stock award
agreement dated July 1, 2014. The shares of restricted stock vest over a three year period in equal portions beginning on the first
anniversary of the grant date, such that 1/3 of the shares vest on the first anniversary of the grant date, 1/3 of the shares vest on
the second anniversary of the grant date and 1/3 of the shares vest on the third anniversary of the grant date, provided that the
holder of the shares of restricted stock remains employed with us on that date. These shares of restricted stock are subject to
forfeiture and other restrictions as more fully set forth in the Incentive Plan and the applicable restricted stock award agreement
and are subject to accelerated vesting upon a change in control, death or permanent disability.
(3) Represents performance-based RSUs that will vest between 0% and 200% of the target number of RSUs on July 1, 2017 based
on the Company’s achievement of TSR relative to the TSR achieved by a peer group established by the compensation
committee. These RSUs were issued pursuant to the Incentive Plan and an RSU award agreement dated as of July 1, 2014 and
are subject to forfeiture, accelerated vesting and other restrictions as more fully set forth in the Incentive Plan and the RSU
award agreement.
(4) Represents shares of restricted common stock issued to Mr. Burnett pursuant to a restricted stock award agreement dated
September 2, 2014. The shares of restricted stock vest over a three year period in equal portions beginning on the first
anniversary of the grant date, such that 1/3 of the shares vest on the first anniversary of the grant date, 1/3 of the shares vest on
the second anniversary of the grant date and 1/3 of the shares vest on the third anniversary of the grant date, provided that
Mr. Burnett remains employed with us on that date. These shares of restricted stock are subject to forfeiture and other
restrictions as more fully set forth in the Incentive Plan and the restricted stock award agreement and are subject to accelerated
vesting upon a change in control, death or permanent disability.
22
(5) Represents performance-based RSUs that will vest between 0% and 200% of the target number of RSUs on July 1, 2017 based
on the Company’s achievement of TSR relative to the TSR achieved by a peer group established by the compensation
committee. These RSUs were issued to Mr. Burnett pursuant to the Incentive Plan and an RSU award agreement dated as of
September 2, 2014 and are subject to forfeiture, accelerated vesting and other restrictions as more fully set forth in the Incentive
Plan the RSU award agreement.
(6) The RSUs and shares of restricted stock granted to Mr. Mulhern during 2014 were forfeited pursuant to the terms of the
restricted stock award agreement and the RSU award agreement in connection with his resignation, which was effective
September 19, 2014.
See “—Compensation Discussion and Analysis—Executive Compensation Components—Long-Term Incentive
Compensation—Incentive Plan” for a discussion of grants of plan-based awards made to our Named Executive Officers in 2014.
The following table sets forth information regarding the outstanding equity awards held by our Named Executive Officers
(including Mr. Mulhern) as of December 31, 2014.
23
2014 FISCAL YEAR OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END
Option Awards(1)
Stock Awards
Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexercised
Unearned
Options (#)
Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable
Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable
166,700
30,000
35,000
35,000
35,000
43,800
—
—
102,450
—
—
—
62,500
—
—
—
—
—
500,000
26,200
40,000
40,000
40,000
48,700
—
—
51,250
—
—
—
—
—
—
—
—
—
—
—
102,450
—
—
—
62,500
—
—
—
—
—
—
—
—
—
—
—
—
—
51,250
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Number
of
Shares or
Units of
Stock
That
Have Not
Vested
(#)
—
—
—
—
—
—
48,087(3)
6,933(4)
—
—
104,167(6)
—
—
56,666(8)
39,063(6)
—
139,063(9)
—
—
—
—
—
—
—
53,096(3)
7,700(4)
—
Market
Value of
Shares or
Units of
Stock
That
Have Not
Vested
($)(2)
—
—
—
—
—
—
104,349
15,045
—
—
226,042
—
—
122,965
84,767
—
301,767
—
—
—
—
—
—
—
115,218
16,709
—
104,167(6)
226,042
Option
Exercise
Price
($)
7.50
14.62
13.72
7.88
17.60
18.50
—
—
7.68
—
—
—
5.17
—
—
—
—
—
12.36
14.62
13.72
7.88
17.60
18.50
—
—
7.68
—
—
—
Option
Expiration
Date
10/4/2015
11/30/2016
12/3/2017
12/10/2018
11/30/2019
12/6/2020
—
—
8/12/2023
—
—
—
12/1/2023
—
—
—
—
—
4/4/2016
11/30/2016
12/3/2017
12/10/2018
11/30/2019
12/6/2020
—
—
8/12/2023
—
—
—
Equity
Incentive
Plan Awards:
Number of
Unearned
Shares, Units
or Other
Rights
That Have
Not Vested
(#)
Equity
Incentive
Plan
Awards:
Market or
Payout Value
of Unearned
Shares, Units
or Other
Rights That
Have Not
Vested ($)(2)
—
—
—
—
—
—
—
—
—
97,600(5)
—
—
—
—
—
—
—
—
—
211,792
52,084(7)
113,022
—
—
19,532(7)
—
19,532(10)
—
—
—
—
—
—
—
—
—
48,800(5)
—
52,084(7)
—
—
42,384
—
42,384
—
—
—
—
—
—
—
—
—
105,896
—
113,022
Grant
Date
Name
Harold L.
Hickey ...... 10/5/2005
12/1/2006
12/4/2007
12/11/2008
12/1/2009
12/7/2010
11/21/2011
12/13/2012
8/13/2013
8/13/2013
7/1/2014
7/1/2014
Richard A.
Burnett ..... 12/2/2013
12/2/2013
7/1/2014
7/1/2014
9/2/2014
9/2/2014
William L.
Boeing ...... 4/5/2006
12/1/2006
12/4/2007
12/11/2008
12/1/2009
12/7/2010
11/21/2011
12/13/2012
8/13/2013
8/13/2013
7/1/2014
7/1/2014
(1)
Pursuant to the terms of the stock option agreements that we entered into with the Named Executive Officer, these options are vested as to 25% of the shares
subject to the option on the date of grant and vest an additional 25% on each of the next three anniversaries of the date of grant provided that the holder of the
option remains employed with us on that date. These options become fully vested and exercisable, subject to their early termination as provided in the option
agreements, immediately prior to a change of control of us.
(2) Market value is based on $2.17 per share closing price of our common stock as reported on the NYSE as of December 31, 2014.
(3)
Pursuant to the terms of the restricted stock award agreement that we entered into with the Named Executive Officer on November 21, 2011, the award vests
over a five year period with 60% of the shares vesting on the third anniversary of the grant date, 20% of the shares vesting on the fourth anniversary of the grant
date and 20% of the shares vesting on the fifth anniversary of the grant date, provided that the holder of the restricted stock award remains employed with us on
that date. These shares become fully vested and exercisable, subject to their early termination as provided in the restricted stock award agreement, immediately
prior to a change of control of us.
Pursuant to the terms of the restricted stock award agreement that we entered into with the Named Executive Officer on December 13, 2012, the award vests in
equal proportions over three years with one-third vesting on December 13, 2013, one-third vesting on December 13, 2014 and one-third vesting on
December 13, 2015, provided that the holder of the restricted stock award remains employed with us on that date. These shares become fully vested and
exercisable, subject to their early termination as provided in the restricted stock award agreement, immediately prior to a change of control of us.
(4)
24
(5)
(6)
(7)
(8)
(9)
(10)
Represents shares of restricted stock issued to the Named Executive Officer in two separate restricted stock award agreements, each of which is dated as of
August 13, 2013 and is subject to a performance vesting schedule based upon the Attainment Date. The “Attainment Date” means the first trading day
immediately following the date that the fair market value of a share of our common stock equals or exceeds $10.00 for one award and $15.00 for the other award
during any thirty (30) consecutive trading day period. The shares of restricted stock vest as follows: (i) if the Attainment Date occurs on or before the first
anniversary of the grant date, 50% of the shares vest on the first anniversary of the grant date and the remaining 50% vest on the second anniversary of the grant
date; (ii) if the Attainment Date occurs after the first anniversary of the grant date but before the second anniversary of the grant date, 50% of the shares vest on
the Attainment Date and the remaining 50% vest on the second anniversary of the grant date; (iii) if the Attainment Date occurs after the second anniversary of
the grant date but before the fifth anniversary of the grant date, 100% of the shares vest on the Attainment Date, in each case, provided the Named Executive
Officer is employed by or providing services to the Company or a subsidiary on such date. These shares of restricted stock are subject to forfeiture and other
restrictions as more fully set forth in the Incentive Plan and the applicable restricted stock award agreement and are subject to accelerated vesting upon a change
in control, death or permanent disability.
Pursuant to the terms of the restricted stock award agreement that we entered into with the Named Executive Officer on July 1, 2014, the shares of restricted
stock vest over a three year period in equal portions beginning on the first anniversary of the grant date, such that 1/3 of the shares vest on the first anniversary
of the grant date, 1/3 of the shares vest on the second anniversary of the grant date and 1/3 of the shares vest on the third anniversary of the grant date, provided
that the holder of the restricted stock remains employed with us on that date. These shares of restricted stock are subject to forfeiture and other restrictions as
more fully set forth in the Incentive Plan and the restricted stock award agreement and are subject to accelerated vesting upon a change in control, death or
permanent disability.
Share amounts represent the target level achievement for performance-based RSUs, which equals 50% of the target number of RSUs granted on July 1, 2014
and is the most probable level of payout other than no award. The actual number of shares that will vest is between 0% and 200% of the target number of RSUs
on July 1, 2017 based on the Company’s achievement of TSR relative to the TSR achieved by a peer group established by the compensation committee. These
RSUs were issued to the Named Executive Officer pursuant to the Incentive Plan and an RSU award agreement dated as of July 1, 2014 and are subject to
forfeiture, accelerated vesting and other restrictions as more fully set forth in the Incentive Plan and the RSU award agreement.
Represents shares of restricted stock issued to Mr. Burnett on December 2, 2013 that vest over a three year period in equal portions beginning on the first
anniversary of the grant date, such that 1/3 of the shares vest on the first anniversary of the grant date, 1/3 of the shares vest on the second anniversary of the
grant date and 1/3 of the shares vest on the third anniversary of the grant date, provided that Mr. Burnett remains employed with us on that date.
Represents shares of restricted stock issued to Mr. Burnett pursuant to a restricted stock award agreement dated September 2, 2014. The shares of restricted
stock vest over a three year period in equal portions beginning on the first anniversary of the grant date, such that 1/3 of the shares vest on the first anniversary
of the grant date, 1/3 of the shares vest on the second anniversary of the grant date and 1/3 of the shares vest on the third anniversary of the grant date, provided
that Mr. Burnett remains employed with us on that date. These shares of restricted stock are subject to forfeiture and other restrictions as more fully set forth in
the Incentive Plan and the restricted stock award agreement and are subject to accelerated vesting upon a change in control, death or permanent disability.
Share amounts represent the target level achievement for performance-based RSUs, which equals 50% of the target number of RSUs granted on September 2,
2014 and is the most probable level of payout other than no award. The actual number of shares that will vest is between 0% and 200% of the target number of
RSUs on July 1, 2017 based on the Company’s achievement of TSR relative to the TSR achieved by a peer group established by the compensation committee.
These RSUs were issued to Mr. Burnett pursuant to the Incentive Plan and an RSU award agreement dated as of September 2, 2014 and are subject to forfeiture,
accelerated vesting and other restrictions as more fully set forth in the Incentive Plan and the RSU award agreement.
OPTION EXERCISES AND STOCK VESTED DURING 2014
None of our Named Executive Officers exercised any stock options during 2014. The following table summarizes the vesting of
restricted stock awards for each of our Named Executive Officers (including Mr. Mulhern) during the fiscal year ended December 31,
2014.
Name and Principal Position
Harold L. Hickey ........................
Chief Executive Officer and
President and Former Chief
Operating Officer ..................
Richard A. Burnett .....................
Vice President, Chief Financial
Officer and Chief Accounting
Officer ....................................
Mark F. Mulhern ........................
Former Executive Vice
President and Chief
Financial Officer ...................
William L. Boeing ......................
Vice President, General
Counsel and Secretary ...........
Option Awards
Stock Awards
Number of Shares
Acquired on
Exercise (#)
Value Realized
on Exercise ($)
Number of Shares
Acquired on Vesting
(#)
Value Realized on
Vesting ($)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5,166(1)
72,131(2)
6,933(3)
22,937(6)
272,655(7)
15,530(8)
28,333(4)
74,516(9)
33,334(5)
185,670(10)
5,733(1)
79,645(2)
7,700(3)
25,454(6)
301,058(7)
17,248(8)
(1)
Pursuant to the terms of the restricted stock award agreement that we entered into with the Named Executive Officer on
August 15, 2011, the award vested in equal proportions over three years with one-third vested on August 15, 2012, one-third
vested on August 15, 2013 and one-third vested on August 15, 2014.
25
(2)
(3)
(4)
(5)
Pursuant to the terms of the restricted stock award agreement that we entered into with the Named Executive Officer on
November 21, 2011, the award vests over a five year period with 60% of the shares vesting on the third anniversary of the
grant date, 20% of the shares vesting on the fourth anniversary of the grant date and 20% of the shares vesting on the fifth
anniversary of the grant date, provided that the holder of the restricted stock award remains employed with us on that date.
These shares become fully vested and exercisable, subject to their early termination as provided in the restricted stock award
agreements, immediately prior to a change of control of us.
Pursuant to the terms of the restricted stock award agreement that we entered into with the Named Executive Officer on
December 13, 2012, the award vests in equal proportions over three years with one-third vesting on December 13, 2013, one-
third vesting on December 13, 2014 and one-third vesting on December 13, 2015, provided that the holder of the restricted
stock award remains employed with us on that date.
Pursuant to the terms of a restricted stock award agreement that we entered into with the Named Executive Officer on
December 2, 2013, the award vests in equal proportions over three years with one-third vesting December 2, 2013, one-third
vesting December 2, 2014 and one-third vesting December 2, 2015.
Pursuant to the terms of a restricted stock award agreement that we entered into with Mr. Mulhern on April 1, 2013, the award
vests in equal proportions over three years with one-third vesting April 1, 2014, one-third vesting April 1, 2015 and one-third
vesting April 1, 2016, provided that the Mr. Mulhern remained employed with us on that date. The unvested portion of this
award was forfeited upon Mr. Mulhern’s resignation, which was effective September 19, 2014.
(6) Market value is based on $4.44 per share closing price of our common stock as reported on the NYSE as of August 15, 2014.
(7) Market value is based on $3.78 per share closing price of our common stock as reported on the NYSE as of November 21,
2014.
(8) Market value is based on $2.24 per share closing price of our common stock as reported on the NYSE as of December 12,
2014.
(9) Market value is based on $2.63 per share closing price of our common stock as reported on the NYSE as of December 2, 2014.
(10) Market value is based on $5.57 per share closing price of our common stock as reported on the NYSE as of April 1, 2014.
Pension Benefits
We do not provide any pension benefits for our Named Executive Officers.
Nonqualified Defined Contribution and Other Nonqualified Deferred Compensation Plans
We do not provide any nonqualified defined contribution or other deferred compensation plans for our Named Executive
Officers.
Potential Payments Upon Termination or Change of Control
Fourth Amended and Restated EXCO Resources, Inc. Severance Plan
We have adopted the Fourth Amended and Restated EXCO Resources, Inc. Severance Plan (the “Severance Plan”), which
provides that, among other things, (i) employees are eligible for severance pay equal to 1.25 times their base pay, (ii) there is a 12-
month protection period following a change of control for eligible employees, and (iii) eligible employees can terminate for “good
reason” due to a material reduction in base pay or a forced relocation. The Severance Plan provides for the payment of severance in
the event the employee’s employment was terminated or there was an adverse change in the employee’s job or compensation, as more
specifically described in the Severance Plan, within twelve months following a change of control of EXCO. The Severance Plan is
administered by our compensation committee, which has the sole discretion to determine whether an employee’s termination of
employment is eligible for payment of severance. All of our regular, full-time employees are eligible to participate in and receive
benefits under the Severance Plan.
A change of control is defined under the Severance Plan as the occurrence of any of the following: (i) we are merged or
consolidated into or with another entity, and as a result less than a majority of the combined voting power of the surviving entity is
held by the holders of our voting stock prior to the merger; (ii) we sell or otherwise transfer all or substantially all of our assets to any
person or entity if less than a majority of the combined voting power of such person or entity immediately after such sale or transfer is
held by the holders of our voting stock prior to such sale or transfer; (iii) any person is or becomes the beneficial owner, directly or
indirectly, of more than 50% of our total voting power; (iv) individuals who on the effective date of the Severance Plan constituted our
board of directors and their successors or other nominees that are appointed or otherwise approved by the board of directors then still
in office, cease for any reason to constitute a majority of the board of directors; or (v) the adoption of a plan relating to the liquidation
or dissolution of us. The definition of “change of control” specifically excludes an event in which any subsidiary of EXCO is spun off
by means of a rights offering to EXCO’s shareholders or an underwritten public offering, or any combination thereof, even where less
than a majority of the voting equity ownership is retained by EXCO.
26
Severance payment will be made only if the employee fully executes a release form with the plan administrator, to release and
forever discharge us from any and all liability which the employee may have against us as a result of employment with or subsequent
termination from us. Severance payment is equal to 1.25 times an employee’s base salary to be paid in cash in a lump sum 60 days
following termination of employment, provided that we have timely received an executed release form.
Severance Arrangements with our Former Chief Executive Officer
In connection with his resignation as chairman and chief executive officer effective November 20, 2013, we entered into a
Settlement Agreement and Mutual Release and Waiver of Claims (the “Settlement Agreement”) with Douglas H. Miller. Pursuant to
the Settlement Agreement, we paid Mr. Miller $4.0 million on November 29, 2013 and $1.0 million on December 31, 2014. In
addition, we agreed to provide health care benefits coverage for Mr. Miller and his dependents through May 31, 2015.
Potential Payments
The following table shows potential payments to our Named Executive Officers (including Mr. Mulhern) for various scenarios
involving a change of control, death or disability, using, where applicable, the closing price of our common stock of $2.17 as reported
on the NYSE as of December 31, 2014 and assuming that the applicable triggering event occurred on December 31, 2014.
Termination for
Cause or
Misconduct Within
12 Months After a
Change of Control
Termination Not
for Cause or
Misconduct or by the
Executive for Good
Reason
Within 12 Months
After a Change of
Control
Change of
Control (No
Termination)
Death
Disability
Executive Benefits and Payments Upon Termination
Harold L. Hickey(1)
Severance ......................................................... $
Long-term Equity Incentives
—Unvested Stock Options(3) ..........................
—Unvested Restricted Stock Awards(4) .........
—Unvested RSUs(5)........................................
—
$
937,500(2) $
— $
— $
—
—
557,228
226,042
—
557,228
226,042
—
557,228
226,042
—
557,228
226,042
—
557,228
226,042
Total ................................................................ $
783,270
$
1,720,770
$
783,270 $ 783,270 $ 783,270
Richard A. Burnett(6)
Severance ......................................................... $
Long-term Equity Incentives
—Unvested Stock Options(3) ..........................
—Unvested Restricted Stock Awards(4) .........
—Unvested RSUs(5)........................................
—
$
593,750(2) $
— $
— $
—
—
509,501
169,533
—
509,501
169,533
—
509,501
169,533
—
509,501
169,533
—
509,501
169,533
Total ................................................................ $
679,034
$
1,272,784
$
679,034 $ 679,034 $ 679,034
Mark F. Mulhern(7) .......................................
Severance ......................................................... $
Long-term Equity Incentives
—Unvested Stock Options(3) ..........................
—Unvested Restricted Stock Awards(4) .........
—Unvested RSUs(5)........................................
Total ................................................................ $
William L. Boeing(1) ......................................
Severance ......................................................... $
Long-term Equity Incentives
—Unvested Stock Options(3) ..........................
—Unvested Restricted Stock Awards(4) .........
—Unvested RSUs(5)........................................
—
$
—
$
— $
— $
—
—
—
—
—
$
—
—
—
—
—
—
—
—
—
—
$
— $
— $
—
—
—
—
—
$
625,000(2) $
— $
— $
—
—
463,866
226,042
—
463,866
226,042
—
463,866
226,042
—
463,866
226,042
—
463,866
226,042
Total ................................................................ $
689,908
$
1,314,908
$
689,908 $ 689,908 $ 689,908
27
(1) As of December 31, 2014, we had not hired a new chief executive officer of the Company and no Special Severance Benefits
were payable pursuant to the Retention Agreements.
(2) Represents a payment equal to 1.25 times officer’s annual base salary pursuant to our Severance Plan. The applicable Named
Executive Officer shall not be eligible to receive a severance payment if either (a) he receives a comparable offer of
employment from any other operation of EXCO or any of its affiliate organizations, regardless of whether he accepts such offer
or (b) he receives and accepts a transfer of employment to any other operation of EXCO or any of its affiliate organizations.
(3) Excludes stock options that are currently exercisable. The exercise price of all unvested stock option awards exceeded the $2.17
closing price of our common stock as reported on the NYSE on December 31, 2014. Pursuant to the terms of each stock option
award, all options become fully vested automatically upon a change of control or upon the death or the total and permanent
disability of the officer.
(4) Pursuant to the terms of each restricted stock award agreement, all shares of restricted stock become fully vested automatically
upon a change of control or upon the death or the total and permanent disability of the officer.
(5) Pursuant to the terms of each RSU award agreement, upon a change of control or upon the death or the total and permanent
disability of the officer, unvested RSUs become fully vested based on the achievement of the performance criteria as of the date
of such triggering event. For purposes of this table, we assumed that 100% of target RSUs will vest as further described under
“—Compensation Discussion and Analysis—Executive Compensation Components—Long-Term Incentive Compensation—
Restricted Stock Units.”
(6) Pursuant to the Burnett Retention Agreement, if Mr. Burnett’s employment is terminated without cause or by Mr. Burnett for
good reason during the period beginning on September 1, 2014 and ending on the later of March 1, 2015 or the date on which
we hire a new chief executive officer, Mr. Burnett is also entitled to (a) a cash payment equal to his annual base salary, or
$475,000, and (b) COBRA benefits for up to 12 months following such termination.
(7) Mr. Mulhern resigned effective as of September 19, 2014 and was not entitled to any payments in connection with such
resignation.
Director Compensation
The following table provides compensation information for the year ended December 31, 2014 for each non-employee member
of our board of directors:
2014 FISCAL YEAR DIRECTOR COMPENSATION TABLE
Name
Fees Earned or
Paid in Cash
($)(1)
Stock
Awards
($)(2)
Option
Awards
($)
Non-Equity
Incentive Plan
Compensation
($)
Jeffrey D. Benjamin (3) .......
400,000
14,150
—
Earl E. Ellis (4) ....................
15,714
—
—
B. James Ford ......................
55,000
14,150
—
Samuel A. Mitchell ..............
55,000
14,150
—
T. Boone Pickens (5)............
40,000
14,150
—
Wilbur L. Ross, Jr. ...............
50,000
14,150
—
Jeffrey S. Serota ...................
55,000
14,150
—
Robert L. Stillwell ................
60,000
14,150
—
—
—
—
—
—
—
—
—
Change
in Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
—
—
—
—
—
—
—
—
All Other
Compensation
($)
Total ($)
—
414,150
—
—
—
—
—
—
—
15,714
69,150
69,150
54,150
64,150
69,150
74,150
(1)
Includes the amount of cash fees forgone at the election of Messrs. Benjamin and Ellis and either paid during 2014 or deferred
until a later date in shares of our common stock pursuant to the Director Plan (as defined below). See “—Director Plan.”
28
(2) This column provides the aggregate grant date fair value of shares of restricted stock issued to each non-employee director in
2014 in accordance with ASC 718, with the exception that the amount shown assumes no forfeitures. Assumptions used in the
calculation of these amounts are included in “Note 2. Summary of significant accounting policies—Share-based compensation”
and “Note 11. Stock options and awards” to our audited financial statements for the fiscal year ended December 31, 2014
included in this Annual Report on Form 10-K. Pursuant to the policies of Oaktree, Mr. Ford must hold these shares of restricted
stock on behalf of and for the sole benefit of Oaktree and has assigned all economic, pecuniary and voting rights to Oaktree.
(3) Mr. Benjamin serves as non-executive chairman of the board of directors and received a fee in the amount of $25,000 per month
during 2014 for such service.
(4) Represents fees earned for service on our board of directors from January 1, 2014 to May 22, 2014. Mr. Ellis did not stand for
re-election at the 2014 Annual Meeting.
(5) Mr. Pickens resigned from our board of directors effective March 2, 2015.
Cash Compensation. Our non-employee directors were paid an annual retainer of $40,000 in 2014. Our non-executive chairman
was paid an additional fee of $25,000 per month for his service. The chairs of our compensation committee and nominating and
corporate governance committee were each paid an additional $10,000 in 2014 and the chair of the audit committee was paid an
additional $50,000 in 2014. Each non-chair member of our compensation committee, nominating and corporate governance committee
and audit committee was paid an additional $5,000 in 2014. We pay no additional remuneration to our employees serving as directors.
All directors, including our employee directors (if any), are reimbursed for reasonable out-of-pocket expenses incurred in connection
with their attendance at meetings of the board of directors and committee meetings. The board of directors has not made any changes
to director compensation for fiscal 2015.
Restricted Stock Grant. On October 30, 2014, each of our non-employee directors received an automatic annual grant of 5,000
shares of restricted stock pursuant to the Amended and Restated 2007 Director Plan (the “Director Plan”) and the EXCO Resources,
Inc. Amended and Restated 2005 Long-Term Incentive Plan (the “Incentive Plan”). Pursuant to the Director Plan, the automatic
annual grants of shares of restricted stock are made on the second trading day after the press release containing the Company’s third
quarter earnings is issued. Such shares of restricted stock will vest on the first anniversary of the date of grant or automatically upon a
change in control as defined in the Incentive Plan. However, no shares granted under the Director Plan will vest, and the shares that
would otherwise have vested will be forfeited, in any fiscal year in which a director attends less than 75% of the board of directors
meetings held for that fiscal year. In the event a director ceases to serve as a director for any reason, such director’s unvested shares of
restricted stock will be forfeited.
Director Plan. The Director Plan permits non-employee directors who receive fees for their service on the board of directors and
its committees to make an annual election to receive their fees (i) entirely in cash, (ii) 50% in cash and 50% in our common stock, or
(iii) entirely in our common stock. Messrs. Ford, Mitchell, Pickens, Ross, Serota and Stillwell elected to receive cash for their service
during 2014. For his service during 2014, Mr. Benjamin elected to receive his fees 50% in cash and 50% in our common stock.
Mr. Ellis elected to receive his fees for service from January 1, 2014 through May 22, 2014 entirely in our common stock. All director
fees are paid on a quarterly basis. Payments in the form of our common stock are issued as of the payment date, which is the first
business day following the end of the fiscal quarter, at the closing price of our common stock on the NYSE on that date.
The Director Plan also permits a non-employee director to defer the payment of his or her director fees (employee directors do
not receive fees in their capacity as directors). A director may defer the payment of director fees, whether payable in the form of cash
or our common stock, to (i) a specified date, (ii) his or her termination of service, (iii) the occurrence of a change of control, or (iv) the
earlier of two or more of those events. This deferral satisfies the requirements of Section 409A of the Code. Mr. Benjamin elected to
defer the payment of his 2014 director fees that are paid in our common stock under the Director Plan.
Compensation Committee Interlocks and Insider Participation
During the fiscal year ended December 31, 2014, the compensation committee was comprised of Messrs. Stillwell (chair),
Benjamin, Ford, Mitchell, Ross and Serota.
During the fiscal year ended December 31, 2014, no member of our compensation committee was or had been an officer or
employee of us or any of our subsidiaries or had any relationship requiring disclosure pursuant to Item 404 of Regulation S-K. None
of our executive officers served as a director or member of the compensation committee (or other board committee performing similar
functions or, in the absence of any such committee, the entire board of directors) of another entity, one of whose executive officers
served on our compensation committee or as one of our directors.
29
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Equity Compensation Plan Information
The following table provides certain information as of December 31, 2014 with respect to our equity compensation plans under
which our equity securities are authorized for issuance:
(a)
(b)
(c)
Number of securities to
be issued upon exercise of
outstanding options,
warrants, and rights
Weighted-average
exercise price of
outstanding options,
warrants and rights
Number of securities remaining
available for future issuance under
equity compensation plans (excluding
securities reflected in column (a))
10,150,518 $
12.58
18,517,815
Not applicable
10,150,518 $
Not applicable
12.58
Not applicable
18,517,815
Plan Category
Equity compensation
plans approved by
security holders ......
Equity compensation
plans not approved
by security
holders .....................
Total .............................
Security Ownership of Certain Beneficial Owners and Management
The following tables set forth as of March 31, 2015 (unless otherwise specified) the number and percentage of shares of our
common stock beneficially owned by (i) each person known by us to beneficially own more than 5% of the outstanding shares of our
common stock, (ii) each of our directors, each of our director nominees and each of our Named Executive Officers (including
Mr. Mulhern) and (iii) all of our directors, director nominees and executive officers as a group.
Beneficial ownership is determined in accordance with the rules of the SEC. Beneficial ownership information is based on the
most recent Forms 3, 4 and 5 and Schedules 13D and 13G filings with the SEC and reports made directly to us. In computing the
number of shares of common stock beneficially owned by a person and the beneficial ownership percentage of that person, shares of
common stock subject to options held by that person that are currently exercisable or exercisable within 60 days of March 31, 2015
are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Percentage of
beneficial ownership of our common stock is based upon 273,702,116 shares of common stock outstanding as of March 31, 2015. To
our knowledge, except as set forth in the footnotes to this table and subject to applicable community property laws, each person named
in the table has sole voting and investment power with respect to the shares set forth opposite such person’s name. Unless otherwise
indicated in a footnote, the address for each individual listed below is c/o EXCO Resources, Inc., 12377 Merit Drive, Suite 1700,
Dallas, Texas 75251.
Principal Shareholders
Beneficial owner
Holders of more than 5%
Common Stock
Beneficial Ownership
Shares
% of
Class
WL Ross & Co. LLC(1) ...........................................................................
1166 Avenue of the Americas ..................................................................
New York, New York 10036 ...................................................................
Oaktree Capital Group Holdings GP, LLC(2) ..........................................
333 S. Grand Avenue, ..............................................................................
28th Floor ..................................................................................................
Los Angeles, CA 90071 ...........................................................................
Fairfax Financial Holdings Limited(3) .....................................................
95 Wellington Street West .......................................................................
Suite 800 Toronto, Ontario A6 M5K 1B1 ................................................
51,104,050
18.67%
45,254,932
16.53%
17,538,912
6.41%
(1) Based solely on the information contained in the Schedule 13D/A filed with the SEC on January 17, 2014.
30
(2) Based solely on the information contained in the Schedule 13D/A filed with the SEC on January 15, 2014 and includes options
to purchase an aggregate of 81,250 shares of our common stock held by Mr. Ford for the benefit of Oaktree as described below
in note 7 to the beneficial ownership table for “Executive Officers, Directors and Director Nominees”.
(3) Based solely on the information contained in the Schedule 13G/A filed with the SEC on February 13, 2015.
Executive Officers, Directors and Director Nominees
Beneficial owner
Shares(1)
Named Executive Officers
Options
exercisable
within 60
days
Percentage of
shares
outstanding
Harold L. Hickey ...............................................................
1,089,015(2)
447,950
Richard A. Burnett .............................................................
331,126(3)
62,500
William L. Boeing .............................................................
1,088,324(4)
746,150
Mark F. Mulhern ................................................................
70,659(5)
—
Directors and Director Nominees
Jeffrey D. Benjamin ...........................................................
464,553(6)
B. James Ford ....................................................................
Samuel A. Mitchell ............................................................
Wilbur L. Ross, Jr. .............................................................
86,250(7)
72,500(8)
11,250(9)
Jeffrey S. Serota .................................................................
86,250(10)
Robert L. Stillwell .............................................................
178,354(11)
81,250
81,250
2,500
6,250
81,250
81,250
*
*
*
*
*
*
*
*
*
*
All executive officers and directors as a group
(10 persons) ...................................................................
3,478,281
1,590,350
1.27%
(1)
(2)
(3)
Includes the options exercisable within 60 days of March 31, 2015 shown in the options column.
Includes (a) 20,815 shares of our common stock held in a 401(k) account, (b) 120,218 shares of restricted stock issued on
November 21, 2011 that vest over five years with 60% vesting on November 21, 2014, 20% vesting on November 21, 2015 and
20% vesting on November 21, 2016, (c) 20,800 shares of restricted stock issued on December 13, 2012 that vest in equal
proportions over three years with one-third vesting on December 13, 2013, one-third vesting on December 13, 2014 and one-
third vesting on December 13, 2015, (d) 97,600 shares of restricted stock issued on August 13, 2013 with performance-based
vesting conditions described under “—Compensation Discussion and Analysis—Executive Compensation Components—Long-
Term Incentive Compensation—Restricted Stock Grants”, (e) 104,167 shares of restricted stock issued on July 1, 2014 that vest
in equal proportions over three years with one-third vesting on July 1, 2015, one-third vesting on July 1, 2016 and one-third
vesting on July 1, 2017, and (f) the vested portion of (i) an option to purchase 166,700 shares of our common stock granted on
October 5, 2005, all of which have vested, (ii) an option to purchase 30,000 shares of our common stock granted on
December 1, 2006, all of which have vested, (iii) an option to purchase 35,000 shares of our common stock granted on
December 4, 2007, all of which have vested, (iv) an option to purchase 35,000 shares of our common stock granted on
December 11, 2008, all of which have vested, (v) an option to purchase 35,000 shares of our common stock granted on
December 1, 2009, all of which have vested, (vi) an option to purchase 43,800 shares of our common stock granted on
December 7, 2010, all of which have vested, and (vii) an option to purchase 204,900 shares of our common stock granted on
August 13, 2013, of which 102,450 have vested. Excludes 104,167 performance-based RSUs issued on July 1, 2014.
Includes (a) 85,000 shares of restricted stock issued on December 2, 2013 that vest in equal proportions over three years with
one-third vesting on December 2, 2013, one-third vesting on December 2, 2014 and one-third vesting on December 2, 2015,
(b) 39,063 shares of restricted stock issued on July 1, 2014 that vest in equal proportions over three years with one-third vesting
on July 1, 2015, one-third vesting on July 1, 2016 and one-third vesting on July 1, 2017, (c) 139,063 shares of restricted stock
issued on September 2, 2014 that vest in equal proportions over three years with one-third vesting on September 2, 2015, one-
third vesting on September 2, 2016 and one-third vesting on September 2, 2017 and (d) the vested portion of an option to
purchase 125,000 shares of our common stock granted on December 2, 2013, of which 62,500 have vested. Excludes 39,063
performance-based RSUs issued on July 1, 2014 and 39,063 performance-based RSUs issued on September 2, 2014.
31
(4)
(5)
(6)
Includes (a) 132,741 shares of restricted stock issued on November 21, 2011 that vest over five years with 60% vesting on
November 21, 2014, 20% vesting on November 21, 2015 and 20% vesting on November 21, 2016, (b) 23,100 shares of
restricted stock issued on December 13, 2012 that vest in equal proportions over three years with one-third vesting on
December 13, 2013, one-third vesting on December 13, 2014 and one-third vesting on December 13, 2015, (c) 48,800 shares of
restricted stock issued on August 13, 2013 with performance-based vesting conditions described under “—Compensation
Discussion and Analysis—Executive Compensation Components—Long-Term Incentive Compensation—Restricted Stock
Grants”, (d) 104,167 shares of restricted stock issued on July 1, 2014 that vest in equal proportions over three years with one-
third vesting on July 1, 2015, one-third vesting on July 1, 2016 and one-third vesting on July 1, 2017, and (e) the vested portion
of (i) an option to purchase 500,000 shares of our common stock on April 5, 2006, all of which have vested, (ii) an option to
purchase 26,200 shares of our common stock on December 1, 2006, all of which have vested, (iii) an option to purchase 40,000
shares of our common stock on December 4, 2007, all of which have vested, (iv) an option to purchase 40,000 shares of our
common stock granted on December 11, 2008, all of which have vested, (v) an option to purchase 40,000 shares of our common
stock granted on December 1, 2009, all of which have vested, (vi) an option to purchase 48,700 shares of our common stock
granted on December 7, 2010, all of which have vested, and (vii) an option to purchase 102,500 shares of our common stock
granted on August 13, 2013, of which 51,250 have vested. Excludes 104,167 performance-based RSUs issued on July 1, 2014.
In connection with Mr. Mulhern’s resignation in September 2014, he forfeited (a) all unvested shares of restricted stock, (b) all
options to purchase shares of our common stock granted for his service on our board of directors and (c) all options to purchase
shares of our common stock granted as executive compensation. Accordingly, this figure is based on Mr. Mulhern’s ownership
on the date of his resignation and includes 33,334 shares of restricted stock that vested on April 1, 2014. Also includes 9,220
shares of our common stock issued to Mr. Mulhern under the Director Plan in lieu of cash compensation for his service on our
board of directors and committees.
Includes the right to acquire 116,300 shares of our common stock granted pursuant to the Director Plan as deferred
compensation in lieu of cash for service on our board of directors and committees. These shares will vest immediately and are to
be settled in our common stock upon the earlier to occur of (a) as soon as administratively feasible after the date on which
Mr. Benjamin incurs a “Termination of Service” under the Director Plan and (b) a “Change in Control” under the Director Plan.
See “—Director Compensation” for a discussion of the Director Plan. Also includes (x) 5,000 shares of restricted stock granted
on October 30, 2014 that vest in full on October 30, 2015, subject to certain conditions set forth in the Director Plan, and (y) the
vested portion of (i) an option to purchase 50,000 shares of our common stock granted on October 5, 2005, all of which have
vested, (ii) an option to purchase 15,000 shares of our common stock granted on December 1, 2009, all of which have vested,
(iii) an option to purchase 5,000 shares of our common stock granted on November 5, 2010, all of which have vested, (iv) an
option to purchase 5,000 shares of our common stock granted on November 4, 2011, all of which have vested, (v) an option to
purchase 5,000 shares of our common stock granted on November 1, 2012, of which 3,750 have vested and (vi) an option to
purchase 5,000 shares of our common stock granted on November 1, 2013, of which 2,500 have vested. The shares of restricted
stock and options described in the preceding sentence were granted in connection with Mr. Benjamin’s appointment to and
service on our board of directors.
(7) Consists of (a) 5,000 shares of restricted stock granted on October 30, 2014 that vest in full on October 30, 2015, subject to
certain conditions set forth in the Director Plan, and (b) the vested portion of (i) an option to purchase 50,000 shares of our
common stock granted to Mr. Ford, a Managing Director of Oaktree, upon becoming one of our directors in December 2007, all
of which have vested, (ii) an option to purchase 15,000 shares of our common stock granted on December 1, 2009, all of which
have vested, (iii) an option to purchase 5,000 shares of our common stock granted on November 5, 2010, all of which have
vested (iv) an option to purchase 5,000 shares of our common stock granted on November 4, 2011, all of which have vested,
(v) an option to purchase 5,000 shares of our common stock granted on November 1, 2012, of which 3,750 have vested and
(vi) an option to purchase 5,000 shares of our common stock issued to Mr. Ford on November 1, 2013, of which 2,500 have
vested. The shares of restricted stock and options described in the preceding sentence were granted in connection with
Mr. Ford’s appointment to and service on our board of directors, and are held directly by Mr. Ford for the benefit of Oaktree.
Pursuant to the policies of Oaktree, Mr. Ford must hold these stock options and shares of restricted stock on behalf of and for
the sole benefit of Oaktree and has assigned all economic, pecuniary and voting rights to Oaktree. Mr. Ford disclaims beneficial
ownership of these securities, except to the extent of any indirect pecuniary interest therein. Amounts reported for Mr. Ford do
not include the shares of our common stock referred to in note 2 to the beneficial ownership table for “Holders of more than
5%” above, with respect to which Mr. Ford disclaims beneficial ownership, except to the extent of any indirect pecuniary
interest therein.
(8) Consists of (a) 5,000 shares of restricted stock granted on October 30, 2014 that vest in full on October 30, 2015, subject to
certain conditions set forth in the Director Plan, and (b) the vested portion of an option to purchase 5,000 shares our common
stock granted on November 1, 2013, of which 2,500 have vested. The shares of restricted stock and options described in the
preceding sentence were granted in connection with Mr. Mitchell’s service on our board of directors. Mr. Mitchell serves as a
managing director and a member of the investment committee of Hamblin Watsa, which manages the investment portfolios of
Fairfax Financial. Amounts reported do not include the shares of our common stock held by Fairfax Financial. Mr. Mitchell
expressly disclaims beneficial ownership of our shares of common stock that are held by Fairfax Financial.
32
(9) Consists of (a) 5,000 shares of restricted stock granted on October 30, 2014 that vest in full on October 30, 2015, subject to
certain conditions set forth in the Director Plan, and (b) the vested portion of (i) an option to purchase 5,000 shares of our
common stock granted on November 1, 2012, of which 3,750 have vested and (ii) an option to purchase 5,000 shares of our
common stock granted on November 1, 2013, of which 2,500 have vested. The shares of restricted stock and options described
in the preceding sentence were granted in connection with Mr. Ross’ service on our board of directors. Amounts reported for
Mr. Ross do not include the shares of our common stock referred to in note 1 to the beneficial ownership table for “Holders of
more than 5%” above, with respect to which Mr. Ross disclaims beneficial ownership, except to the extent of any indirect
pecuniary interest therein.
(10) Includes (a) 5,000 shares of restricted stock granted on October 30, 2014 that vest in full on October 30, 2015, subject to certain
conditions set forth in the Director Plan, and (b) the vested portion of (i) an option to purchase 50,000 shares of our common
stock granted on March 30, 2007, all of which have vested, (ii) an option to purchase 15,000 shares of our common stock
granted on December 1, 2009, all of which have vested, (iii) an option to purchase 5,000 shares of our common stock granted on
November 5, 2010, all of which have vested, (iv) an option to purchase 5,000 shares of our common stock granted on
November 4, 2011, all of which have vested, (v) an option to purchase 5,000 shares of our common stock granted on
November 1, 2012, of which 3,750 have vested and (vi) an option to purchase 5,000 shares of our common stock granted on
November 1, 2013, of which 2,500 have vested. The shares of restricted stock and options described in the preceding sentence
were granted in connection with Mr. Serota’s appointment to and service on our board of directors. Pursuant to an arrangement
between Ares and Mr. Serota, Mr. Serota has assigned all economic, pecuniary and voting rights with respect to the stock
options that vested on or before December 31, 2013 to Ares while the unvested portion of such stock options as well as shares of
restricted stock granted after December 31, 2013, were not assigned to Ares and are owned solely by Mr. Serota. Mr. Serota
expressly disclaims beneficial ownership of the stock options he holds for the benefit of Ares.
(11) Includes the right to acquire 5,404 shares of our common stock granted pursuant to the Director Plan as deferred compensation
in lieu of cash for Mr. Stillwell’s service on our board of directors and committees. These shares vested immediately and are to
be settled in our common stock upon the earlier to occur of (a) as soon as administratively feasible after the date on which
Mr. Stillwell incurs a “Termination of Service” under the Director Plan and (b) a “Change in Control” under the Director Plan.
See “—Director Compensation” for a discussion of the Director Plan. Also includes (x) 10,000 shares held by Mr. Stillwell’s
spouse, (y) 5,000 shares of restricted stock granted on October 30, 2014 that vest in full on October 30, 2015, subject to certain
conditions set forth in the Director Plan, and (z) the vested portion of (i) an option to purchase 50,000 shares of our common
stock granted on October 5, 2005, all of which have vested, (ii) an option to purchase 15,000 shares of our common stock
granted on December 1, 2009, all of which have vested, (iii) an option to purchase 5,000 shares of our common stock granted on
November 5, 2010, all of which have vested, (iv) an option to purchase 5,000 shares of our common stock granted on
November 4, 2011, all of which have vested, (v) an option to purchase 5,000 shares of our common stock granted on
November 1, 2012, of which 3,750 have vested and (vi) an option to purchase 5,000 shares of our common stock granted on
November 1, 2013, of which 2,500 have vested. The shares of restricted stock and options described in clauses (y) and (z) were
granted in connection with Stillwell’s appointment to and service on our board of directors.
Less than 1%.
*
Item 13.
Certain Relationships and Related Transactions and Director Independence
Transactions with Related Persons
Relationship with Kyle Hickey
Kyle Hickey, the son of Harold L. Hickey, our chief executive officer and president, is one of our employees. From January 1,
2014 through March 31, 2015, compensation paid to Mr. Kyle Hickey (including the value of equity awards) totaled approximately
$186,000.
33
Investment Agreements
We entered into two investment agreements (individually, the “Investment Agreement,” or, collectively, the “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 (together with WL Ross, the “Investors”) 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 shares of common stock that rights holders do not elect to purchase in the Rights Offering pursuant to the
basic subscription right (the “Unsubscribed Shares”) under the over-subscription privilege, subject to availability and the pro rata
allocation among rights holders who elected to exercise their over-subscription privilege; provided, that each of the Investors was not
obligated to purchase an aggregate number of shares that would exceed the lesser of (i) 100% of the Unsubscribed Shares, or (ii) an
amount of Unsubscribed Shares, which when taken together with the number of shares issued pursuant to the Investor’s basic
subscription right, equaled 50% of the total shares offered in the rights offering. For additional information concerning the Investment
Agreements, please see the description in our Current Report on Form 8-K filed with the SEC on December 17, 2013, which
description is incorporated by reference herein.
Rights Offering
On January 17, 2014, we issued 54,574,734 shares of our common stock pursuant to the Rights Offering and the transactions
contemplated by the Investment Agreements for an aggregate subscription price of approximately $273 million. We issued 19,599,973
and 6,726,712 shares of common stock to 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. (collectively, the “WL Ross Purchasers”)
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 (collectively, the “Hamblin Watsa Purchasers” and, together with the WL Ross Purchasers, the “Purchasers”), respectively,
pursuant to the transactions contemplated by the Investment Agreements for aggregate subscription amounts of approximately $98.0
million and $33.6 million, respectively.
On January 17, 2014, in accordance with the terms of the Investment Agreements, we executed a Joinder Agreement to
Registration Rights Agreement (the “WL Ross Joinder Agreement”) with the WL Ross Purchasers and a Joinder Agreement to
Registration Rights Agreement with the Hamblin Watsa Purchasers, each dated as of January 17, 2014. The Joinder Agreements relate
to the Company’s First Amended and Restated Registration Rights Agreement, dated December 30, 2005, by and among EXCO
Holdings Inc. (our predecessor by merger) and the Initial Holders (as defined therein) (the “Registration Rights Agreement”). Pursuant
to the Joinder Agreements, the Purchasers became “Holders” under the Registration Rights Agreement and shares owned by the
Purchasers, including shares of common stock acquired under the Investment Agreements, became subject to the Registration Rights
Agreement. The Registration Rights Agreement provides for, among other things, certain registration rights for shares of common
stock that the Purchasers acquired pursuant to the Investment Agreements.
Audit Committee Review
In accordance with our audit committee charter, our audit committee is responsible for reviewing and approving the terms and
conditions of all related party transactions that are required to be disclosed under Item 404 of Regulation S-K. Our Audit Committee
Charter requires all transactions with related persons to be pre-approved by the audit committee. Our audit committee or the
disinterested members of our board of directors pre-approved the foregoing related party transactions that occurred during 2014.
Director Independence
The standards relied upon by the board of directors in affirmatively determining whether a director is “independent” in
compliance with the rules of the NYSE are comprised, in part, of those objective standards set forth in NYSE rules. In addition, no
director will qualify as “independent” unless the Board affirmatively determines that the director has no material relationship with the
Company (either directly or as a partner, shareholder or officer of an organization that has a relationship with us). The following
commercial or charitable relationships, although not exclusive, will not be considered to be material relationships that would impair a
director’s independence: (a) the director is an executive officer or owns beneficially or of record more than a ten percent equity
interest of another company that does business with us or our subsidiaries and the annual sales to, or purchases from, us or our
subsidiaries are less than five percent of the annual revenues of the company for which he or she serves as an executive officer; (b) the
director is an executive officer or owns beneficially or of record more than a ten percent equity interest of another company which is
indebted to us or our subsidiaries, or to which we or our subsidiaries are indebted, and the total amount of either company’s
indebtedness to the other is less than five percent of the total consolidated assets of the company for which he or she serves as an
34
executive officer; and (c) the director serves as an officer, director or trustee of a charitable organization, and our discretionary
charitable contributions to the organization are less than five percent of that organization’s total annual charitable receipts. Any
automatic matching by us of employee charitable contributions will not be included in the amount of our contributions for this
purpose.
The board of directors, in applying the above-referenced standards, has affirmatively determined that our current “independent”
directors are Jeffrey D. Benjamin, B. James Ford, Samuel A. Mitchell, Wilbur L. Ross, Jr., Jeffrey S. Serota and Robert L. Stillwell.
As part of the board of directors’ process in making such determination, each such director provided written assurances that (a) all of
the above-cited objective criteria for independence are satisfied and (b) he has no other “material relationship” with us that could
interfere with his ability to exercise independent judgment.
In determining that the directors above are “independent,” the board of directors considered the transactions, relationships and
arrangements described in our prior proxy statements and under this “Item 13. Certain Relationships and Related Transactions and
Director Independence.”
Item 14.
Principal Accountant Fees and Services
Fees
Aggregate fees for professional services provided to us by our principal accountant, KPMG LLP, for the years ended
December 31, 2014 and 2013 were as follows:
2014
2013
(in thousands)
Audit Fees(a) ............................................................................... $
Audit-Related Fees(b) .................................................................
Tax Fees(c) ..................................................................................
All Other Fees(d) .........................................................................
1,722
111
237
—
$
2,065
22
108
200
Total ............................................................................................ $
2,070
$
2,395
(a) Fees for audit services include fees associated with the annual audit, the reviews of EXCO’s quarterly reports on Form 10-Q and
Sarbanes-Oxley compliance test work.
(b) Audit-related fees principally include costs incurred related to accounting consultations related to generally accepted accounting
principles and the application of generally accepted accounting principles to proposed transactions.
(c) Tax fees include tax compliance and tax planning.
(d) All other fees principally include costs incurred related to audits under Section 3-05 of Regulation S-X associated with the
acquisition of oil and natural gas properties in the Haynesville and Eagle Ford shales in July 2013 and the formation of Compass
in 2013.
In considering the nature of the services provided by KPMG LLP, the audit committee determined that such services are
compatible with the provision of independent audit services. The audit committee discussed these services with KPMG LLP and our
management to determine that they are permitted under the rules and regulations concerning auditor independence promulgated by the
SEC to implement the Sarbanes-Oxley Act of 2002, as well as the American Institute of Certified Public Accountants.
Pre-Approval of Independent Registered Public Accounting Firm Fees and Services Policy
The audit committee has adopted a policy that requires advance approval of all audit services and non-audit services performed
by the independent registered public accounting firm or other public accounting firms. Audit services approved by the audit committee
within the scope of the engagement of the independent registered public accounting firm are deemed to have been pre-approved. The
policy further provides that pre-approval of non-audit services by the independent registered public accounting firm will not be
required if:
•
•
the aggregate amount of all such non-audit services provided by the independent registered public accounting firm to us
does not constitute more than 5% of the total amount of revenues paid by us to the independent auditor during that fiscal
year;
such non-audit services were not recognized by us at the time of the independent registered public accounting firm’s
engagement to be non-audit services; and
35
•
such non-audit services are promptly brought to the attention of the audit committee and approved by the audit committee
prior to the completion of the audit.
The audit committee may delegate to one or more members of the audit committee the authority to grant pre-approval of non-
audit services provided that such member or members reports any decision to the audit committee at its next scheduled meeting.
The audit committee pre-approved all of the aggregate audit fees, audit-related fees, tax fees and other fees set forth in the table
above.
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.
PART IV
(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.
36
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.
SIGNATURES
Date: April 10, 2015
EXCO RESOURCES, INC.
(Registrant)
/s/ Harold L. Hickey
Harold L. Hickey
President and Chief Executive Officer
37
Exhibit
Number
31.1
31.2
INDEX TO EXHIBITS
Description of Exhibits
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer of EXCO
Resources, Inc., filed herewith.
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Financial Officer of EXCO
Resources, Inc., filed herewith.
38
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________________
FORM 10-K
______________________________
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
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 001-32743
______________________________
EXCO RESOURCES, INC.
(Exact name of registrant as specified in its charter)
______________________________
Texas
(State or other jurisdiction of incorporation or organization)
74-1492779
(I.R.S. Employer Identification No.)
12377 Merit Drive
Suite 1700, LB 82
Dallas, Texas
(Address of principal executive offices)
75251
(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
NO
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
NO
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES
NO
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate 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
NO
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.
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
Accelerated filer
Non-accelerated filer
(Do not check if
a smaller reporting
company)
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). YES
NO
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
PART I.
Item 1.
Business ............................................................................................................................................................... 2
Item 1A. Risk Factors ......................................................................................................................................................... 30
Item 1B. Unresolved Staff Comments ................................................................................................................................ 45
Item 2.
Item 3.
Properties ............................................................................................................................................................. 45
Legal Proceedings................................................................................................................................................ 45
Item 4. Mine Safety Disclosures ...................................................................................................................................... 46
PART II.
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
46
Securities..............................................................................................................................................................
Item 6.
Selected Financial Data........................................................................................................................................ 47
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations............................... 49
Item 7A. Quantitative and Qualitative Disclosures About Market Risk............................................................................. 72
Financial Statements and Supplementary Data.................................................................................................... 73
Item 8.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure ............................. 120
Item 9A. Controls and Procedures ...................................................................................................................................... 120
Item 9B. Other Information ................................................................................................................................................ 120
PART III.
Item 10. Directors, Executive Officers and Corporate Governance................................................................................... 121
Item 11. Executive Compensation ..................................................................................................................................... 121
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters ........... 121
Item 13. Certain Relationships and Related Transactions, and Director Independence .................................................... 121
Item 14.
Principal Accountant Fees and Services .............................................................................................................. 121
Part IV.
Item 15. Exhibits and Financial Statement Schedules ....................................................................................................... 121
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.
2
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.
3
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.
4
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
East Texas/North Louisiana..................
South Texas (4).....................................
Appalachia and other............................
Total.................................................
Areas
East Texas/North Louisiana..................
South Texas (6).....................................
Appalachia and other............................
Total.................................................
Total Proved Reserves (Bcfe)
(1)
PV-10 (in millions) (1) (2)
Average daily net production
(Mmcfe) (3)
881.2
$
113.1
269.5
1,263.8
$
813.8
561.5
167.3
1,542.6
238
39
55
332
Estimated drilling locations
(5)
Total gross acreage
Total net acreage
1,988
212
4,194
6,394
230,600
101,400
659,400
991,400
99,300
52,900
297,100
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.
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”).
(5)
(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
6
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
7
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.
8
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
Oil (Mbbls)
Developed.................................................
Undeveloped.............................................
Total..........................................................
Natural gas (Mmcf)
Developed.................................................
Undeveloped.............................................
Total..........................................................
Natural gas liquids (Mbbls)
Developed.................................................
Undeveloped.............................................
Total..........................................................
Equivalent reserves (Mmcfe)
Developed.................................................
Undeveloped.............................................
Total..........................................................
PV-10 (in millions) (1)
Developed.................................................
Undeveloped.............................................
Total..........................................................
Standardized Measure (in millions) (2)....
As of December 31,
2014
2013
2012
14,429
3,258
17,687
502,314
652,714
1,155,028
387
54
441
591,210
672,586
1,263,796
11,274
4,104
15,378
657,116
359,363
1,016,479
2,088
495
2,583
737,291
386,954
1,124,245
$
$
$
1,117.6
425.0
1,542.6
1,542.6
$
$
$
1,153.5
98.8
1,252.3
1,252.3
$
$
$
4,371
1,199
5,570
917,326
18,806
936,132
4,784
1,855
6,639
972,256
37,130
1,009,386
666.0
30.1
696.1
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.
Oil (per Bbl)
Natural gas (per Mmbtu)
Average spot prices
December 31, 2014 ..................................
December 31, 2013 ..................................
December 31, 2012 ..................................
$
94.99
$
96.78
94.71
4.35
3.67
2.76
Natural gas liquids (per Bbl)
33.03
$
39.92
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.
Proved Developed Reserves ....................................................
Proved Undeveloped Reserves ................................................
Total Proved Reserves (1)...................................................
The changes in reserves for the year are as follows:
January 1, 2014 ........................................................................
Purchases of reserves in place..................................................
Discoveries and extensions .................................................
Revisions of previous estimates (2):
Oil (Mbbls)
14,429
Natural gas
(Mmcf)
502,314
3,258
652,714
17,687
1,155,028
Natural gas
liquids
(Mbbls)
387
54
441
Equivalent
natural gas
(Mmcfe)
591,210
672,586
1,263,796
15,378 1,016,479
2,583
1,124,245
—
4,164
7,316
69,902
—
107
7,316
95,528
Changes in price..................................................................
Other factors........................................................................
Sales of reserves in place .........................................................
Production ................................................................................
December 31, 2014 ..................................................................
45
167,302
1,737
(1,401)
(2,236)
17,687
120,850
(105,841)
(120,980)
1,155,028
127
(8)
(2,144)
(224)
441
168,334
131,224
(127,111)
(135,740)
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:
Proved Undeveloped Reserves at January 1, 2014 ..........................................................
Purchases of Proved Undeveloped Reserves in place ......................................................
Sales of Proved Undeveloped Reserves ...........................................................................
New discoveries and extensions (1) .................................................................................
Proved Undeveloped Reserves transferred to developed (2) ...........................................
Proved Undeveloped Reserves transferred to unproved (3).............................................
Other revisions of previous estimates of Proved Undeveloped Reserves (4) ..................
Proved Undeveloped Reserves at December 31, 2014 ....................................................
Mmcfe
386,954
—
(4,526)
63,018
(71,776)
—
298,916
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.
(in thousands, except production and per unit amounts)
Revenues, production and prices:
Oil:
Year Ended December 31,
2014
2013
2012
Revenue..............................................................................................................
Production sold (Mbbls) ....................................................................................
Average sales price per Bbl................................................................................
Natural gas:
Revenue..............................................................................................................
Production sold (Mmcf).....................................................................................
Average sales price per Mcf...............................................................................
Natural gas liquids:
Revenue..............................................................................................................
Production sold (Mbbls) ....................................................................................
Average sales price per Bbl................................................................................
Costs and Expenses:
Oil and natural gas operating costs per Mcfe.....................................................
$
$
$
$
$
$
$
196,316
2,236
87.80
457,946
120,980
3.79
6,007
224
26.82
0.47
$
$
$
$
$
$
$
111,440
1,188
93.80
514,309
153,321
3.35
8,560
243
35.23
0.38
$
$
$
$
$
$
$
62,119
704
88.24
462,422
182,644
2.53
22,068
510
43.27
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)..................................................................................
Average price per Mcf ....................................................................................................... $
Oil and natural gas operating costs per Mcf ......................................................................
82,299
107,746
111,629
$
4.02
0.22
3.39
0.13
$
2.47
0.11
Shelby field:
Natural gas production sold (Mmcf)..................................................................................
Average price per Mcf ....................................................................................................... $
Oil and natural gas operating costs per Mcf ......................................................................
10,314
12,020
24,764
$
3.90
0.33
3.32
0.28
$
2.48
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...............
South Texas........................................
Appalachia and other .........................
Total.................................................
—
220
338
558
691
5
5,812
6,508
691
225
6,150
7,066
—
108.0
165.2
273.2
246.6
2.2
2,629.9
2,878.7
246.6
110.2
2,795.1
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.
Year ended December 31, 2014 (1) ...............
Year ended December 31, 2013.....................
Year ended December 31, 2012.....................
Year ended December 31, 2014 (1) ...............
Year ended December 31, 2013 (2) ...............
Year ended December 31, 2012 (3) ...............
Productive
98
105
169
Productive
—
15
6
Gross
Dry
Gross
Dry
—
2
2
—
—
—
Development wells
Total
98
107
171
Productive
29.6
48.7
73.8
Exploratory wells
Total
Productive
—
7.7
2.2
—
15
6
Net
Dry
Net
Dry
—
0.5
1.9
—
—
—
Total
29.6
49.2
75.7
Total
—
7.7
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:
Area
East Texas/North Louisiana ............................
South Texas.....................................................
Appalachia ......................................................
Other................................................................
Total.................................................................
At December 31, 2014
Developed
Undeveloped
Gross
Net
Gross
Net
149,700
93,500
397,300
4,400
644,900
71,700
48,100
181,000
3,200
304,000
80,900
7,900
253,500
4,200
346,500
27,600
4,800
109,000
3,900
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.
18
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.
19
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.
20
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.
21
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
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• 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
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• 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:
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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:
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our future financial and operating performance and results;
our business strategy;
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:
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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;
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• 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 the 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:
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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;
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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:
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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:
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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
38
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.
39
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.
40
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
41
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.
42
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
Dallas, Texas (1)................................................
Cranberry Township, Pennsylvania...................
Approximate square
footage
Approximate monthly
payment
Expiration
155,000
15,400
$
$
253,826 May 31, 2025
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.
45
Item 3. Legal Proceedings
In the ordinary course of business, we are periodically a party to various litigation matters. We do not believe that any
resulting liability from existing legal proceedings, individually or in the aggregate, will have a material adverse effect on our
results of operations or financial condition.
Item 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:
2014
First Quarter....................................................................
Second Quarter ...............................................................
Third Quarter ..................................................................
Fourth Quarter ................................................................
2013
First Quarter....................................................................
Second Quarter ...............................................................
Third Quarter ..................................................................
Fourth Quarter ................................................................
$
$
Our shareholders
Price per share
High
Low
Dividends Declared
$
$
5.85
6.60
5.95
3.80
7.92
8.70
9.00
7.25
$
$
4.60
5.05
3.25
1.98
5.97
6.52
6.63
4.83
0.05
0.05
0.05
—
0.05
0.05
0.05
0.05
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
October 1 - October 31 ............................
— $
November 1 - November 30 ....................
December 1 - December 31 .....................
Total..................................................
32,011
6,810
38,821
—
3.78
2.24
3.51
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)
— $
—
—
—
192.5
192.5
192.5
(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
(in thousands, except per share amounts)
Statement of operations data (1):
Revenues:
Year Ended December 31,
2014
2013
2012
2011
2010
Oil and natural gas...................................................
$
660,269
$
634,309
$
546,609
$
754,201
$
515,226
Cost and expenses:
Oil and natural gas production (2)...........................
Gathering and transportation ...................................
Depletion, depreciation and amortization................
Impairment of oil and natural gas properties...........
Accretion of discount on asset retirement
obligations ...............................................................
General and administrative (3) ................................
(Gain) loss on divestitures and other operating
items (4)...................................................................
Total cost and expenses ...........................................
Operating income (loss) ...............................................
Other income (expense):
Interest expense, net ................................................
Gain (loss) on derivative financial instruments (5) .
Other income (expense)...........................................
Equity income (loss) (6) ..........................................
Total other income (expense) ..................................
Income (loss) before income taxes...............................
Income tax expense ......................................................
Net income (loss) .........................................................
Basic net income (loss) per share.................................
Diluted net income (loss) per share..............................
Cash dividends declared per share ...............................
Weighted average common shares and common share
equivalents outstanding:
94,326
101,574
263,569
—
2,690
65,920
5,315
533,394
126,875
(94,284)
87,665
241
172
(6,206)
120,669
—
120,669
0.45
0.45
0.15
$
$
$
$
83,248
100,645
245,775
108,546
2,514
91,878
104,610
102,875
303,156
1,346,749
108,641
86,881
362,956
233,239
108,184
54,877
196,963
—
3,887
83,818
3,652
3,758
104,618
105,114
(177,518)
455,088
179,221
17,029
23,819
1,962,124
(1,415,515)
923,806
(169,605)
(509,872)
(40,976)
556,202
(102,589)
(320)
(828)
(53,280)
(157,017)
22,204
—
22,204
0.10
0.10
0.20
$
$
$
$
(73,492)
66,133
969
28,620
22,230
(1,393,285)
—
$(1,393,285) $
(6.50) $
$
(6.50) $
$
0.16
$
$
(61,023)
219,730
788
32,706
192,201
22,596
—
22,596
0.11
0.10
0.16
$
$
$
$
(45,533)
146,516
327
16,022
117,332
673,534
1,608
671,926
3.16
3.11
0.14
Basic ........................................................................
Diluted .....................................................................
268,258
268,376
215,011
230,912
214,321
214,321
213,908
216,705
212,465
215,735
Statement of cash flow data:
Net cash provided by (used in):
Operating activities..................................................
Investing activities...................................................
Financing activities..................................................
$
362,093
(221,588)
(144,683)
$
350,634
(252,478)
(93,317)
$
514,786
(427,094)
(74,045)
$
428,543
(709,531)
268,756
$
339,921
(712,854)
348,755
Balance sheet data:
Current assets...........................................................
Total assets...............................................................
Current liabilities .....................................................
Long-term debt ........................................................
Shareholders' equity ................................................
Total liabilities and shareholders' equity .................
$
330,766
$
305,854
$
361,866
$
678,008
$
520,460
2,356,896
2,408,628
2,323,732
3,791,587
3,477,420
365,371
349,170
237,931
287,399
285,698
1,446,535
1,858,912
1,848,972
1,887,828
1,588,269
510,004
147,905
149,393
1,558,332
1,540,552
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:
(dollars in thousands, except per unit prices)
2014
2013
2012
2014-2013
2013-2012
Year Ended December 31,
Year to year change
Production:
Oil (Mbbls)...............................................
Natural gas (Mmcf) ..................................
Natural gas liquids (Mbbls)......................
Total production (Mmcfe) (1) ..................
Average daily production (Mmcfe)..........
2,236
120,980
224
135,740
372
1,188
153,321
243
161,907
444
704
182,644
510
189,928
519
1,048
(32,341)
(19)
(26,167)
(72)
Revenues before derivative financial instrument activities:
Oil.............................................................
$
196,316
$
111,440
$
62,119
$
84,876
$
Natural gas ...............................................
Natural gas liquids....................................
457,946
6,007
514,309
8,560
462,422
22,068
(56,363)
(2,553)
Total revenues.....................................
$
660,269
$
634,309
$
546,609
$
25,960
$
484
(29,323)
(267)
(28,021)
(75)
49,321
51,887
(13,508)
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) $
Natural gas (per Mcf) ...............................
Natural gas liquids (per Bbl) ....................
Natural gas equivalent (per Mcfe)............
3.79
26.82
4.86
3.35
35.23
3.92
2.53
43.27
2.88
0.44
(8.41)
0.94
5.56
0.82
(8.04)
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 .............
Gathering and transportation....................
Depletion ..................................................
Depreciation and amortization .................
General and administrative (2).................
Interest expense, net .................................
Costs and expenses (per Mcfe):
Oil and natural gas operating costs ..........
$
Production and ad valorem taxes .............
Gathering and transportation....................
Depletion ..................................................
Depreciation and amortization .................
General and administrative ......................
Interest expense, net .................................
29,859
101,574
258,266
5,303
65,920
94,284
21,971
100,645
237,899
7,876
91,878
102,589
27,483
102,875
288,401
14,755
83,818
73,492
$
0.47
0.22
0.75
1.90
0.04
0.49
0.69
$
0.38
0.14
0.62
1.47
0.05
0.57
0.63
$
0.41
0.14
0.54
1.52
0.08
0.44
0.39
7,888
929
20,367
(2,573)
(25,958)
(8,305)
$
0.09
0.08
0.13
0.43
(0.01)
(0.08)
0.06
(5,512)
(2,230)
(50,502)
(6,879)
8,060
29,097
(0.03)
—
0.08
(0.05)
(0.03)
0.13
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:
(dollars in thousands, except
per unit rate)
Production
(Mmcfe)
Revenue
$/Mcfe
Production
(Mmcfe)
Revenue
$/Mcfe
Production
(Mmcfe)
Revenue
$/Mcfe
Year Ended December 31,
2014
2013
Year to year change
Producing region:
East Texas/North
Louisiana.........................
South Texas.....................
Appalachia ......................
Other ...............................
Compass ...............................
92,916
$ 371,074
$ 3.99
123,218
$ 417,811
$ 3.39
(30,302) $ (46,737) $
0.60
13,713
21,289
364
7,458
176,022
12.84
6,197
85,926
13.87
7,516
90,096
67,794
3.18
22,816
78,424
3,649
10.02
41,730
5.60
1,139
8,537
9,135
43,013
3.44
8.02
5.04
(1,527)
(10,630)
(775)
(1,079)
(5,486)
(1,283)
(1.03)
(0.26)
2.00
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:
(dollars in thousands, except
per unit rate)
Production
(Mmcfe)
Revenue
$/Mcfe
Production
(Mmcfe)
Revenue
$/Mcfe
Production
(Mmcfe)
Revenue
$/Mcfe
Year Ended December 31,
2013
2012
Year to year change
Producing region:
East Texas/North
Louisiana ..........................
South Texas......................
Appalachia........................
Other.................................
Compass ................................
123,218
$ 417,811
$ 3.39
164,779
$ 420,579
$ 2.55
(41,561) $
(2,768) $ 0.84
6,197
22,816
1,139
8,537
85,926
13.87
78,424
9,135
43,013
3.44
8.02
5.04
—
16,153
8,996
—
—
47,379
78,651
—
—
2.93
8.74
—
6,197
6,663
85,926
31,045
13.87
0.51
(7,857)
(69,516)
(0.72)
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
Lease
operating
expenses
Workovers
and other
Total
Lease
operating
expenses
Workovers
and other
Total
Lease
operating
expenses
Workovers
and other
Total
(in thousands)
Producing region:
East Texas/North
Louisiana........................
South Texas....................
Appalachia .....................
Other ..............................
$ 18,056
$
3,815
$ 21,871
$ 16,980
$
4,294
$ 21,274
$ 1,076
$
(479) $
15,242
14,072
300
396
58
—
15,638
14,130
300
11,454
14,073
1,623
13
11,467
3,788
— 14,073
(1)
—
1,623
(1,323)
597
4,171
57
(1,323)
(312)
$
3,190
383
58
—
247
209
Compass ..............................
10,838
1,690
12,528
11,397
1,443
12,840
(559)
Total..........................
$ 58,508
$
5,959
$ 64,467
$ 55,527
$
5,750
$ 61,277
$ 2,981
$
Year Ended December 31,
2014
2013
Year to year change
Lease
operating
expenses
Workovers
and other
Total
Lease
operating
expenses
Workovers
and other
Total
Lease
operating
expenses
Workovers
and other
Total
(per Mcfe)
Producing region:
East Texas/North
Louisiana........................
$
South Texas....................
Appalachia .....................
Other ..............................
Compass ..............................
Total..........................
$
0.19
1.11
0.66
0.82
1.45
0.43
$
$
0.04
0.03
—
—
0.23
0.04
$
$
0.23
1.14
0.66
0.82
1.68
0.47
$
$
0.14
1.85
0.62
1.42
1.34
0.34
$
0.03
$
—
—
—
0.17
0.04
$
$
0.17
1.85
0.62
1.42
1.51
0.38
(0.74)
0.04
(0.60)
0.11
0.09
$
0.01
0.03
—
—
0.06
$
— $
$
0.05
$
$
0.06
(0.71)
0.04
(0.60)
0.17
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
Lease
operating
expenses
Workovers
and other
Total
Lease
operating
expenses
Workovers
and other
Total
Lease
operating
expenses
Workovers
and other
Total
$ 16,980
$
4,294
$ 21,274
$ 39,897
$
9,497
$ 49,394
$(22,917) $
(5,203) $ (28,120)
11,454
14,073
1,623
11,397
13
11,467
— 14,073
—
1,623
1,443
12,840
—
14,882
12,539
—
—
—
11,454
— 14,882
(809)
13
—
11,467
(809)
312
—
12,851
(10,916)
(312)
(11,228)
—
11,397
1,443
12,840
(in thousands)
Producing region:
East Texas/North
Louisiana ..........................
South Texas.......................
Appalachia ........................
Other .................................
Compass ..............................
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
Lease
operating
expenses
Workovers
and other
Total
Lease
operating
expenses
Workovers
and other
Total
Lease
operating
expenses
Workovers
and other
Total
(per Mcfe)
Producing region:
East Texas/North
Louisiana ..........................
$
South Texas.......................
Appalachia ........................
Other .................................
Compass ..............................
Total.............................
$
0.14
1.85
0.62
1.42
1.34
0.34
$
0.03
$
—
—
—
0.17
0.04
$
$
0.17
1.85
0.62
1.42
1.51
0.38
$
0.24
$
0.06
$
0.30
$
(0.10) $
(0.03) $
(0.13)
—
0.92
1.39
—
—
—
0.03
—
—
0.92
1.42
—
1.85
(0.30)
0.03
1.34
—
—
(0.03)
0.17
1.85
(0.30)
—
1.51
$
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 increased 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
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
$
10,032
2.7% $
0.11
$
13,406
2,256
92
4,073
7.6%
3.3%
2.5%
9.8%
0.98
0.11
0.25
0.55
9,287
4,962
2,653
815
4,254
2.2% $
0.08
$
17,501
4.2% $
0.11
5.8%
3.4%
8.9%
9.9%
0.80
0.12
0.72
0.50
—
3,013
6,969
—
—%
6.4%
8.9%
—%
—
0.19
0.77
—
(in thousands, except per unit
rate)
Producing region:
East Texas/North
Louisiana........................
South Texas....................
Appalachia .....................
Other ..............................
Compass ..............................
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 decreased 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:
(in thousands, except per unit rate)
General and administrative costs:
Year Ended December 31,
Year to year change
2014
2013
2012
2014-2013
2013-2012
Gross general and administrative expense ......
$
119,959
$
147,432
$
152,057
$
(27,473) $
(4,625)
Technical services and service agreement
charges.............................................................
Operator overhead reimbursements ................
Capitalized salaries and share-based
compensation...................................................
(24,747)
(13,507)
(26,846)
(10,462)
(25,242)
(20,544)
2,099
(3,045)
(15,785)
(18,246)
(22,453)
2,461
General and administrative expense................
$
65,920
$
91,878
$
83,818
$
(25,958) $
(1,604)
10,082
4,207
8,060
General and administrative expenses for the year ended December 31, 2014 decreased 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 increased 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
(in thousands)
Interest expense:
Year Ended December 31,
Period to period change
2014
2013
2012
2014-2013
2013-2012
2018 Notes.....................................................................
$
57,585
$
57,485
$
57,394
$
100
$
2022 Notes.....................................................................
EXCO Resources Credit Agreement .............................
Compass Production Partners Credit Agreement ..........
Amortization of deferred financing costs ......................
30,104
16,368
2,022
7,939
—
33,119
2,335
28,169
—
31,068
—
8,644
Capitalized interest ........................................................
(20,060)
(18,729)
(23,809)
Other ..............................................................................
326
210
195
30,104
(16,751)
(313)
(20,230)
(1,331)
116
91
—
2,051
2,335
19,525
5,080
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.
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.........................................................
Net price per Mcfe, including derivative financial
instruments .........................................................................
$
(0.14)
0.26
1.06
(0.40)
(0.80)
4.72
$
4.18
$
3.94
$
0.54
$
0.24
Year Ended December 31,
Period to period change
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:
(in thousands)
Year Ended December 31,
2014
2013
2012
Federal income taxes (benefit) provision at statutory rate of 35%..................
$
42,234
$
7,772
$
(487,649)
Increases (reductions) resulting from:
Goodwill.....................................................................................................
Adjustments to the valuation allowance.....................................................
Non-deductible compensation....................................................................
State taxes net of federal benefit ................................................................
State tax rate change...................................................................................
Other...........................................................................................................
—
(64,757)
3,409
3,464
15,496
154
16,382
(28,865)
1,328
3,239
—
144
Total income tax provision.........................................................................
$
— $
— $
—
544,949
1,893
(59,406)
—
213
—
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 .............................................................................................................................
$
2018 Notes (1) ...............................................................................................................................................................
2022 Notes.....................................................................................................................................................................
Total debt.......................................................................................................................................................................
Net debt .........................................................................................................................................................................
Borrowing base (2) ........................................................................................................................................................
Unused borrowing base (3) ...........................................................................................................................................
Cash (4) .........................................................................................................................................................................
Unused borrowing base plus cash .................................................................................................................................
$
$
$
$
$
$
202,492
750,000
500,000
1,452,492
1,382,217
900,000
690,935
70,275
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.
Includes restricted cash of $24.0 million at December 31, 2014.
(4)
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
The fiscal quarter ending December 31, 2016 .................................................................................
The fiscal quarter ending March 31, 2017 and June 30, 2017 .........................................................
The fiscal quarter ending September 30, 2017.................................................................................
The fiscal quarter ending December 31, 2017 .................................................................................
Each fiscal quarter ending thereafter................................................................................................
Ratio
6.00 to 1.00
5.75 to 1.00
5.25 to 1.00
4.75 to 1.00
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:
(in thousands)
Net cash provided by operating activities ..................................................................... $
Net cash used in investing activities..............................................................................
Net cash used in financing activities .............................................................................
Net increase (decrease) in cash...................................................................................... $
Year Ended December 31,
$
2014
362,093
(221,588)
(144,683)
(4,178) $
2013
350,634
(252,478)
(93,317)
4,839
$
$
2012
514,786
(427,094)
(74,045)
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 for 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 compared 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.
(in thousands)
Capital expenditures:
Year Ended December 31,
2014
2013
2012
Lease purchases and seismic....................................................................................
$
10,477
$
25,052
$
Development capital expenditures ...........................................................................
Field operations, gathering and water pipelines.......................................................
Corporate and other..................................................................................................
Total capital expenditures excluding oil and natural gas property acquisitions .
Oil and natural gas property acquisitions (1) ...........................................................
356,344
20,256
37,198
424,275
10,562
265,120
12,379
37,287
339,838
942,946
49,158
403,342
1,044
48,303
501,847
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:
(in millions, except wells)
East Texas/North Louisiana...................
South Texas............................................
Appalachia .............................................
Corporate and other (2)..........................
Total..................................................
Gross Wells
Spud (1)
Net Wells
Spud (1)
Net Wells
Completed (1)
Drilling &
Completion
Other Capital
Total Capital
25
23
2
—
50
11.9
7.1
0.7
—
19.7
17.6
10.7
0.5
—
$
150.0
$
59.0
6.0
—
28.8
$
215.0
$
8.0
7.0
8.0
37.0
60.0
$
$
158.0
66.0
14.0
37.0
275.0
(1)
(2)
The wells spud and completed within this table only include those operated by EXCO.
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)
Swaps:
NYMEX gas volume -
Mmbtu
Weighted average contract
price per Mmbtu
NYMEX oil volume -
Bbls
Weighted average contract
price per Bbl
2015.............................................
42,888
$
Basis swaps:
2015.............................................
Call options:
2015.............................................
Three-way collars:
2015.............................................
Sold call .................................
Purchased put .........................
Sold put ..................................
2016
Sold call .................................
Purchased put .........................
Sold put ..................................
—
20,075
27,375
10,980
4.20
—
4.29
4.47
3.83
3.33
4.80
3.90
3.40
1,095
$
91
365
—
—
91.09
6.10
100.00
—
—
—
—
—
—
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.
(in thousands)
Payments due by period
Less than
one year
One to
three years
Three to five
years
More than
five years
Total
EXCO Resources Credit Agreement (1)......................................
$
Senior Notes (2)...........................................................................
— $
—
Gathering and firm transportation services (3)............................
136,040
Other fixed commitments (4).......................................................
Drilling contracts (5)....................................................................
Operating leases and other...........................................................
17,332
22,191
5,912
— $
202,492
$
— $
202,492
—
266,289
18,696
2,538
9,070
750,000
218,200
5,613
—
6,145
500,000
101,618
3,530
—
1,623
1,250,000
722,147
45,171
24,729
22,750
Total contractual obligations........................................................
$ 181,475
$ 296,593
$ 1,182,450
$
606,771
$
2,267,289
71
(1)
(2)
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.
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
Management's Report on Internal Control Over Financial Reporting .............................................................................. 74
Report of Independent Registered Public Accounting Firm ............................................................................................. 75
Consolidated Balance Sheets at December 31, 2014 and 2013 ........................................................................................ 76
Consolidated Statements of Operations for the years ended December 31, 2014, 2013, and 2012 ................................. 78
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013, and 2012 ................................ 79
Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 2014, 2013, and
2012................................................................................................................................................................................... 80
Notes to consolidated financial statements ....................................................................................................................... 81
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:
Title:
/s/ Harold L. Hickey
President and Chief Operating Officer
By:
Title:
/s/ Richard A. Burnett
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
December 31,
2014
December 31,
2013
(in thousands)
Assets
Current assets:
Cash and cash equivalents .......................................................................................................
$
46,305
$
Restricted cash.........................................................................................................................
Accounts receivable, net:.........................................................................................................
Oil and natural gas............................................................................................................
Joint interest .....................................................................................................................
Other.................................................................................................................................
Derivative financial instruments..............................................................................................
Inventory and other..................................................................................................................
Total current assets .................................................................................................
Equity investments..........................................................................................................................
Oil and natural gas properties (full cost accounting method):
23,970
81,720
65,398
8,945
97,278
7,150
330,766
55,985
50,483
20,570
128,352
70,759
18,022
8,226
9,442
305,854
57,562
Unproved oil and natural gas properties and development costs not being amortized ...........
Proved developed and undeveloped oil and natural gas properties.........................................
Accumulated depletion............................................................................................................
Oil and natural gas properties, net...........................................................................................
276,025
425,307
3,852,073
(2,414,461)
1,713,637
3,554,210
(2,183,464)
1,796,053
Gathering assets ..............................................................................................................................
Accumulated depreciation and amortization ...........................................................................
Gathering assets, net................................................................................................................
Office, field and other assets, net....................................................................................................
Deferred financing costs, net ..........................................................................................................
Derivative financial instruments.....................................................................................................
Deferred income taxes ....................................................................................................................
1,488
(168)
1,320
23,324
30,636
2,138
35,935
33,473
(10,338)
23,135
27,233
28,807
6,829
—
Goodwill .........................................................................................................................................
163,155
163,155
Total assets..............................................................................................................
$ 2,356,896
$ 2,408,628
See accompanying notes.
76
EXCO RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
December 31,
2014
December 31,
2013
(in thousands, except per share and share data)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities................................................................................
$
110,211
$
109,217
Revenues and royalties payable..............................................................................................
Drilling advances ....................................................................................................................
Accrued interest payable.........................................................................................................
Current portion of asset retirement obligations ......................................................................
Income taxes payable..............................................................................................................
Deferred income taxes ............................................................................................................
Derivative financial instruments.............................................................................................
Current maturities of long-term debt ......................................................................................
Total current liabilities.....................................................................................................
152,651
37,648
26,265
1,769
—
35,935
892
—
365,371
154,862
22,971
18,144
191
—
—
11,919
31,866
349,170
Long-term debt...............................................................................................................................
1,446,535
1,858,912
Derivative financial instruments ....................................................................................................
Asset retirement obligations and other long-term liabilities..........................................................
Commitments and contingencies ...................................................................................................
—
34,986
—
9,671
42,970
—
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........................................
Subscription rights, $0.001 par value, none issued and outstanding at December 31, 2014;
54,574,734 issued and outstanding at December 31, 2013.....................................................
Additional paid-in capital .......................................................................................................
Accumulated deficit................................................................................................................
270
—
215
55
3,502,209
(2,984,860)
3,219,748
(3,064,634)
Treasury shares, at cost; 578,042 at December 31, 2014 and 539,221 at December 31,
(7,615)
2013 ........................................................................................................................................
Total shareholders’ equity................................................................................................
510,004
Total liabilities and shareholders’ equity......................................................................... $ 2,356,896
(7,479)
147,905
$ 2,408,628
See accompanying notes.
77
EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Revenues:
Oil .................................................................................................. $
Natural gas .....................................................................................
Natural gas liquids .........................................................................
Total revenues.........................................................................
Costs and expenses:
Oil and natural gas operating costs ................................................
Production and ad valorem taxes ...................................................
Gathering and transportation..........................................................
Depletion, depreciation and amortization ......................................
Impairment of oil and natural gas properties .................................
Accretion of discount on asset retirement obligations...................
General and administrative ............................................................
(Gain) loss on divestitures and other operating items....................
Total costs and expenses.........................................................
Operating income (loss).................................................................
Other income (expense):
Interest expense, net.......................................................................
Gain (loss) on derivative financial instruments .............................
Other income (expense) .................................................................
Equity income (loss) ......................................................................
Total other income (expense)..................................................
Income (loss) before income taxes........................................................
Income tax expense ...............................................................................
Net income (loss) ..................................................................................
Earnings (loss) per common share:
Basic:
Net income (loss)....................................................................
Weighted average common shares outstanding......................
Diluted:
Net income (loss)....................................................................
Weighted average common shares and common share
equivalents outstanding ..........................................................
$
$
$
See accompanying notes.
Year Ended December 31,
2013
2012
2014
196,316
$
111,440
$
457,946
6,007
660,269
64,467
29,859
101,574
263,569
—
2,690
65,920
5,315
533,394
126,875
(94,284)
87,665
241
172
(6,206)
120,669
—
514,309
8,560
634,309
61,277
21,971
100,645
245,775
108,546
2,514
91,878
(177,518)
455,088
179,221
(102,589)
(320)
(828)
(53,280)
(157,017)
22,204
—
120,669
$
22,204
$
62,119
462,422
22,068
546,609
77,127
27,483
102,875
303,156
1,346,749
3,887
83,818
17,029
1,962,124
(1,415,515)
(73,492)
66,133
969
28,620
22,230
(1,393,285)
—
(1,393,285)
0.45
$
0.10
$
268,258
215,011
(6.50)
214,321
0.45
$
0.10
$
(6.50)
268,376
230,912
214,321
78
EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2014
2013
2012
(in thousands)
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
Share-based compensation expense.................................................................................................
Accretion of discount on asset retirement obligations.....................................................................
Impairment of oil and natural gas properties ...................................................................................
(Income) loss from equity investments............................................................................................
(Gain) loss on derivative financial instruments ...............................................................................
Cash settlements (payments) of derivative financial instruments....................................................
Amortization of deferred financing costs and discount on debt issuance........................................
(Gain) loss on divestitures and other non-operating items ..............................................................
Effect of changes in: ........................................................................................................................
Accounts receivable ................................................................................................................
Other current assets.................................................................................................................
Accounts payable and other current liabilities........................................................................
Net cash provided by operating activities.................................................................................................
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment ...........................................
Property acquisitions.................................................................................................................................
Proceeds from disposition of property and equipment .............................................................................
Restricted cash ..........................................................................................................................................
Net changes in advances to joint ventures ................................................................................................
Equity method investments.......................................................................................................................
Other .........................................................................................................................................................
Net cash used in investing activities .........................................................................................................
Financing Activities:
4,962
2,690
—
(172)
(87,665)
(18,991)
12,055
(17)
52,007
(2,609)
15,595
362,093
(391,776)
(10,790)
187,655
(3,400)
(5,026)
1,749
—
(221,588)
245,775
10,748
2,514
108,546
53,280
320
42,119
29,624
(185,163)
(46,176)
9,627
57,216
350,634
(320,538)
(976,714)
749,628
49,515
10,645
236,289
(1,303)
(252,478)
Borrowings under credit agreements ........................................................................................................
100,000
1,004,523
Repayments under credit agreements .......................................................................................................
(964,970)
(1,022,785)
Proceeds received from issuance of 2022 Notes.......................................................................................
Proceeds from issuance of common shares, net........................................................................................
Payment of common share dividends .......................................................................................................
Deferred financing costs and other ...........................................................................................................
Payments of common shares repurchased ................................................................................................
500,000
271,773
(41,060)
(10,290)
(136)
—
1,712
(43,214)
(33,553)
—
303,156
8,926
3,887
1,346,749
(28,620)
(66,133)
202,078
9,788
1,303
112,919
7,090
6,928
514,786
(534,175)
(2,748)
38,045
85,840
851
(14,907)
—
(427,094)
53,000
(93,000)
—
1,968
(34,358)
(1,655)
—
Net cash used in financing activities.........................................................................................................
(144,683)
(93,317)
(74,045)
Net increase (decrease) in cash .................................................................................................................
Cash at beginning of period ......................................................................................................................
Cash at end of period ................................................................................................................................
Supplemental Cash Flow Information:
Cash interest payments .............................................................................................................................
Income tax payments ................................................................................................................................
Supplemental non-cash investing and financing activities: ......................................................................
$
$
(4,178)
50,483
46,305
91,735
—
$
$
4,839
45,644
50,483
88,936
—
$
$
Capitalized share-based compensation ..................................................................................................
$
5,498
$
7,288
$
Capitalized interest.................................................................................................................................
Issuance of common shares for director services ..................................................................................
Debt eliminated upon sale of Compass and assumed upon formation of Compass, net for the years
ended December 31, 2014 and 2013, respectively ................................................................................
Issuance of subscription rights...............................................................................................................
20,060
235
(83,246)
—
18,729
93
58,613
55
13,647
31,997
45,644
86,298
—
7,513
23,809
597
—
—
See accompanying notes.
79
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
EXCO RESOURCES, INC.
(in thousands)
Shares
Amount
Shares
Amount
Shares
Amount
Common Shares
Subscription Rights
Treasury Shares
Additional
paid-in
capital
Accumulated
deficit
Total
shareholders’
equity
(539) $ (7,479) $
3,181,063
$
(1,615,467) $
1,558,332
—
—
—
—
—
—
—
—
—
—
2,565
16,439
—
—
—
—
—
—
2,565
16,439
—
(34,658)
(34,658)
(1,393,285)
(1,393,285)
(539) $ (7,479) $
3,200,067
$
(3,043,410) $
149,393
—
—
—
—
—
—
—
—
—
—
—
—
1,805
17,931
—
—
(55)
—
—
—
—
1,805
17,931
—
(43,428)
(43,428)
—
22,204
—
22,204
(539) $ (7,479) $
3,219,748
$
(3,064,634) $
147,905
—
—
—
—
—
—
—
—
(39)
—
(136)
—
272,008
10,453
—
—
—
—
—
—
—
272,008
10,453
—
(40,895)
(40,895)
—
(136)
120,669
120,669
(578) $ (7,615) $
3,502,209
$
(2,984,860) $
510,004
Balance at December
31, 2011 .........................
Issuance of common
shares .............................
Share-based
compensation.................
Restricted shares issued,
net of cancellations........
Common share
dividends .......................
Net income ....................
Balance at December
31, 2012 .........................
Issuance of common
shares .............................
Share-based
compensation.................
Restricted shares issued,
net of cancellations........
Common share
dividends .......................
Issuance of subscription
rights..............................
Net income ....................
Balance at December
31, 2013 .........................
Issuance of common
shares .............................
Share-based
compensation.................
Restricted shares issued,
net of cancellations........
Common share
dividends .......................
Treasury share
repurchases ....................
Net income ....................
Balance at December
31, 2014 .........................
See accompanying notes.
217,245
$
215
— $
266
—
615
—
—
—
—
—
—
—
—
—
—
—
—
218,126
$
215
— $
228
—
429
—
—
—
—
—
—
—
—
—
—
—
—
—
54,575
—
218,783
$
215
54,575
$
—
—
—
—
—
—
—
—
—
—
—
55
—
55
(54,575)
(55)
54,582
—
987
—
—
—
55
—
—
—
—
—
—
—
—
—
—
274,352
$
270
— $
—
—
—
—
—
—
80
EXCO RESOURCES, INC.
NOTES TO CONSOLIDATED 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 not 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 not 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
83
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.
84
The following is a reconciliation of our asset retirement obligations for the periods indicated:
(in thousands)
Asset retirement obligations at beginning of period .................
Activity during the period:
Liabilities incurred during the period .....................................
Revisions in estimated assumptions .......................................
Liabilities settled during the period ........................................
Adjustment to liability due to acquisitions .............................
Adjustment to liability due to divestitures (1) ........................
Accretion of discount..............................................................
Asset retirement obligations at end of period ...........................
Less current portion ..................................................................
Long-term portion .....................................................................
December 31,
2014
2013
2012
$
42,954
$
61,864
$
58,088
576
—
(33)
107
(9,539)
2,690
36,755
1,769
514
1,268
(187)
5,566
(28,585)
2,514
42,954
191
$
34,986
$
42,763
$
971
—
(338)
—
(744)
3,887
61,864
1,200
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
85
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
87
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:
88
Purchase Price Allocation (in thousands):
Assets acquired:
Haynesville
Acquired Properties
Eagle Ford
Acquired Properties
Unproved oil and natural gas properties.....................................................................................
$
2,319
$
Proved developed and undeveloped oil and natural gas properties............................................
282,918
Liabilities assumed:
Accounts payable and accrued liabilities ...................................................................................
Revenues and royalties payable .................................................................................................
Asset retirement obligations.......................................................................................................
—
(3,526)
(610)
Total purchase price.........................................................................................................................
$
281,101
$
227,869
437,616
(580)
—
(3,060)
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:
(in thousands, except for per share data)
Year Ended December 31,
2013
2012
Oil and natural gas revenues.............................................................................................................
Net income (loss) (1) ........................................................................................................................
Basic earnings (loss) per share .........................................................................................................
Diluted earnings (loss) per share ......................................................................................................
$
$
$
$
784,628
38,663
0.18
0.17
$
$
$
$
715,286
(1,398,169)
(6.52)
(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)
Derivative financial instruments - Current assets............................................................................
Derivative financial instruments - Long-term assets.......................................................................
Derivative financial instruments - Current liabilities ......................................................................
Derivative financial instruments - Long-term liabilities .................................................................
Net derivative financial instruments................................................................................................
December 31,
2014
97,278
$
December 31,
2013
$
8,226
2,138
(892)
—
$
98,524
$
6,829
(11,919)
(9,671)
(6,535)
90
The Effect of Derivative Financial Instruments
(in thousands)
Gain (loss) on derivative financial instruments.................................................................
2014
87,665
$
2013
2012
$
(320) $ 66,133
Year Ended December 31,
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.
91
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)
Natural gas:
Swaps:
Volume Mmbtu/
Bbl
Weighted average
strike price per
Mmbtu/Bbl
Fair value at
December 31,
2014
2015.........................................................................................................
42,888
$
Call options:
2015.........................................................................................................
20,075
Three-way collars:
2015.........................................................................................................
Sold call..............................................................................................
Purchased put .....................................................................................
Sold put ..............................................................................................
2016.........................................................................................................
Sold call..............................................................................................
Purchased put .....................................................................................
Sold put ..............................................................................................
Total natural gas.........................................................................................
Oil:
Swaps:
27,375
10,980
4.20
4.29
4.47
3.83
3.33
4.80
3.90
3.40
49,926
(784)
10,205
2,138
$
61,485
2015.........................................................................................................
1,095
$
91.09
36,797
Basis swaps:
2015.........................................................................................................
Call options:
2015.........................................................................................................
Total oil........................................................................................................
Total oil and natural gas derivative financial instruments ....................
91
365
6.10
350
100.00
(108)
37,039
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:
92
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.
(in thousands)
Level 1
Level 2
Level 3
Total
Oil and natural gas derivative financial instruments.................................
$
— $
98,524
$
— $
98,524
December 31, 2014
(in thousands)
Level 1
Level 2
Level 3
Total
Oil and natural gas derivative financial instruments.................................
$
— $
(6,535) $
— $
(6,535)
December 31, 2013
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.
93
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.
(in thousands)
Level 1
Level 2
Level 3
Total
2018 Notes ................................................................................................
$
558,750
$
2022 Notes ................................................................................................
373,500
— $
—
— $
558,750
—
373,500
December 31, 2014
(in thousands)
Level 1
Level 2
Level 3
Total
2018 Notes ................................................................................................
$
714,000
$
Term Loan.................................................................................................
298,500
— $
—
— $
714,000
—
298,500
December 31, 2013
6.
Debt
Our total debt is summarized as follows:
(in thousands)
Revolving credit facility under EXCO Resources Credit Agreement...........................................................
Term Loan under EXCO Resources Credit Agreement................................................................................
Unamortized discount on Term Loan............................................................................................................
2018 Notes ....................................................................................................................................................
Unamortized discount on 2018 Notes...........................................................................................................
2022 Notes ....................................................................................................................................................
Total debt excluding Compass......................................................................................................................
Compass Production Partners Credit Agreement..........................................................................................
Total debt.......................................................................................................................................................
Less amounts due within one year ................................................................................................................
December 31,
2014
December 31,
2013
$
202,492
$
—
—
750,000
(5,957)
500,000
763,866
298,500
(2,780)
750,000
(7,293)
—
1,446,535
1,802,293
—
88,485
1,446,535
1,890,778
—
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.
94
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:
95
Period
The fiscal quarter ending December 31, 2016 ...................................................................................
The fiscal quarter ending March 31, 2017 and June 30, 2017...........................................................
The fiscal quarter ending September 30, 2017 ..................................................................................
The fiscal quarter ending December 31, 2017 ...................................................................................
Each fiscal quarter ending thereafter .................................................................................................
Ratio
6.00 to 1.00
5.75 to 1.00
5.25 to 1.00
4.75 to 1.00
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.
Gathering and firm
transportation
services
$
136,040
$
133,429
132,860
129,140
89,060
101,618
(in thousands)
2015......................
2016......................
2017......................
2018......................
2019......................
Thereafter .............
Total......................
Other fixed
commitments
Drilling contracts
Operating leases and
other
Total
17,332
$
13,253
22,191
$
2,538
5,443
3,210
2,403
3,530
—
—
—
—
5,912
$
5,223
3,847
3,094
3,051
1,623
181,475
154,443
142,150
135,444
94,514
106,771
814,797
$
722,147
$
45,171
$
24,729
$
22,750
$
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:
97
(in Bcf)
2015...............................................................................................................
2016...............................................................................................................
2017...............................................................................................................
2018...............................................................................................................
2019...............................................................................................................
Thereafter ......................................................................................................
Total...............................................................................................................
Firm transportation
services
Gathering services
293
272
269
269
269
299
1,671
110
110
110
100
—
—
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:
(in thousands, except per share data)
Basic net income (loss) per common share:
Year Ended December 31,
2014
2013
2012
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 ....................................................
Subscription rights ..........................................................................................
—
118
—
Weighted average common shares and common share equivalents outstanding ......
268,376
—
420
15,481
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:
(in thousands)
Share-based compensation expense ........................
Share-based compensation capitalized....................
Total share-based compensation .............................
$
$
Year Ended December 31,
2014
2013
2012
4,962
5,498
10,460
$
$
10,748
7,288
18,036
$
$
8,926
7,513
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
$
Granted....................................................................
Forfeitures...............................................................
Exercised.................................................................
Options outstanding at December 31, 2012....................
Granted....................................................................
Forfeitures...............................................................
Exercised.................................................................
Options outstanding at December 31, 2013....................
Granted....................................................................
Forfeitures...............................................................
Exercised.................................................................
146,500
(1,543,933)
(256,940)
14,015,795
2,886,500
(4,969,877)
(220,675)
11,711,743
141,525
(1,700,250)
(2,500)
Options outstanding at December 31, 2014....................
Options exercisable at December 31, 2014 ....................
10,150,518
9,181,306
$
$
13.44
8.00
16.12
7.66
13.20
7.48
11.32
7.66
12.69
5.24
12.71
5.22
12.58
13.15
3.7
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:
Expected life..................................................
2014
7.5 years
Risk-free rate of return ..................................
2.25 - 2.61 %
Volatility........................................................
59.46 - 59.61 %
Dividend yield ...............................................
3.36 - 4.34 %
2013
3.8 to 7.5 years
0.48 - 2.49 %
49.47 - 59.86 %
2.27 - 3.87 %
2012
3.8 to 7.5 years
0.56 - 1.64 %
57.34 - 60.24 %
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
Non-vested shares outstanding at December 31, 2011 ................
Granted.................................................................................
Vested...................................................................................
Forfeited ...............................................................................
Non-vested shares outstanding at December 31, 2012 ................
Granted.................................................................................
Vested...................................................................................
Forfeited ...............................................................................
Non-vested shares outstanding at December 31, 2013 ................
Granted.................................................................................
Vested...................................................................................
Forfeited ...............................................................................
Non-vested shares outstanding at December 31, 2014 ................
Market-based restricted share awards
Shares
Weighted average grant date fair
value per share
2,562,409
$
926,900
(370,448)
(312,496)
2,806,365
$
556,700
(832,706)
(602,045)
1,928,314
$
1,339,782
(1,109,866)
(280,301)
1,877,929
$
11.72
7.57
12.89
11.89
10.16
7.15
10.47
9.84
9.26
5.20
9.79
6.89
6.40
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
Vested...............................................................................
—
Forfeited...........................................................................
(261,400)
Non-vested shares outstanding at December 31, 2013............
474,600
$
Granted ............................................................................
Vested...............................................................................
—
—
Forfeited...........................................................................
(73,200)
Non-vested shares outstanding at December 31, 2014............
401,400
$
—
6.36
—
6.36
6.36
—
—
6.36
6.36
— $
—
—
—
— $
820,317
—
(104,167)
716,150
$
—
—
—
—
—
7.33
—
7.33
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
(in thousands)
Current:
Year ended December 31,
2014
2013
2012
Federal ...............................................................................
State ...................................................................................
Total current income tax (benefit).....................................
$
$
— $
—
— $
— $
—
— $
Deferred:
Federal ...............................................................................
$
45,797
$
25,626
$
State ...................................................................................
Valuation allowance...........................................................
Total deferred income tax (benefit)...................................
Total income tax (benefit)............................................................
$
18,960
(64,757)
—
— $
3,239
(28,865)
—
— $
—
—
—
(485,543)
(59,406)
544,949
—
—
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)
Current deferred tax assets (liabilities):
December 31, 2014 December 31, 2013
Derivative financial instruments.....................................................................................................
$
(38,519) $
Other ...............................................................................................................................................
Valuation allowance........................................................................................................................
Net current deferred tax assets (liabilities) .....................................................................................
2,584
—
(35,935)
—
5,332
(5,332)
—
Non-current deferred tax assets:
Net operating loss and AMT credits carryforwards........................................................................
$
781,899
$
737,399
Capital loss carryforwards ..............................................................................................................
Share-based compensation..............................................................................................................
Oil and natural gas properties, gathering assets, and equipment ....................................................
Goodwill .........................................................................................................................................
Derivative financial instruments.....................................................................................................
Investment in partnerships ..............................................................................................................
Other ...............................................................................................................................................
Total non-current deferred tax assets..............................................................................................
Valuation allowance........................................................................................................................
Total non-current deferred tax assets..............................................................................................
Non-current deferred tax liabilities:
40,356
14,856
—
5,419
—
72,988
84
915,602
(826,852)
88,750
Oil and natural gas properties, gathering assets, and equipment ....................................................
$
(51,961) $
Derivative financial instruments.....................................................................................................
Total non-current deferred tax liabilities ........................................................................................
(854)
(52,815)
Net non-current deferred tax assets (liabilities)..............................................................................
$
35,935
$
—
16,060
47,491
9,812
2,102
73,328
85
886,277
(886,277)
—
—
—
—
—
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:
(in thousands)
Year Ended December 31,
2014
2013
2012
Federal income taxes (benefit) provision at statutory rate of 35% .............................
$
42,234
$
7,772
$
(487,649)
Increases (reductions) resulting from:
Goodwill ................................................................................................................
Adjustments to the valuation allowance ................................................................
Non-deductible compensation ...............................................................................
State taxes net of federal benefit............................................................................
State tax rate change ..............................................................................................
Other ......................................................................................................................
—
(64,757)
3,409
3,464
15,496
154
16,382
(28,865)
1,328
3,239
—
144
Total income tax provision..........................................................................................
$
— $
— $
—
544,949
1,893
(59,406)
—
213
—
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:
(in thousands)
Advances to OPCO ..............................................................................................................
Amounts received from OPCO ............................................................................................
2014
2013
$
— $ 28,378
2012
$ 76,729
53,002
43,632
52,206
Year Ended December 31,
103
As of December 31, 2014 and 2013, the amounts owed under the service agreements were as follows:
(in thousands)
Amounts due to EXCO (1) ..................................................................................................
Amounts due from EXCO (1) .............................................................................................
December 31, 2014 December 31, 2013
2,283
$
2,799
$
—
—
(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
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
(in thousands)
Assets
Current assets:
Cash and cash equivalents ............................................
$
86,837
$
(40,532) $
— $
— $
Restricted cash ..............................................................
Other current assets.......................................................
Total current assets................................................
Equity investments........................................................
Oil and natural gas properties (full cost accounting
method):
Unproved oil and natural gas properties and
development costs not being amortized....................
Proved developed and undeveloped oil and natural
gas properties............................................................
—
110,145
196,982
—
23,970
150,346
133,784
—
—
—
—
55,985
—
276,025
335,838
3,516,235
Accumulated depletion..............................................
(330,771)
(2,083,690)
Oil and natural gas properties, net ............................
Gathering, office, field and other assets, net.................
5,067
1,269
1,708,570
23,375
Investments in and advances to affiliates, net...............
1,746,931
Deferred financing costs, net ........................................
Derivative financial instruments ...................................
Goodwill .......................................................................
Deferred income taxes ..................................................
30,636
2,138
13,293
35,935
—
—
—
149,862
—
—
—
—
—
—
—
—
—
—
(1,746,931)
—
—
—
—
46,305
23,970
260,491
330,766
55,985
276,025
3,852,073
(2,414,461)
1,713,637
24,644
—
30,636
2,138
163,155
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
Deferred income taxes ..................................................
Other long-term liabilities.............................................
Payable to parent...........................................................
—
271
—
—
—
34,715
2,058,683
—
—
—
—
—
—
—
(2,058,683)
Total shareholders' equity .....................................
510,004
(367,737)
55,985
311,752
1,446,535
—
34,986
—
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
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
(in thousands)
Assets
Current assets:
50,483
20,570
234,801
305,854
57,562
425,307
3,554,210
(2,183,464)
1,796,053
50,368
—
28,807
6,829
163,155
Cash and cash equivalents ..........................................
$
81,840
$
(35,892) $
4,535
$
— $
Restricted cash ............................................................
Other current assets.....................................................
Total current assets..............................................
Equity investments......................................................
Oil and natural gas properties (full cost accounting
method):
Unproved oil and natural gas properties and
development costs not being amortized .................
Proved developed and undeveloped oil and
natural gas properties..............................................
Accumulated depletion ...........................................
Oil and natural gas properties, net ..........................
Gathering, office, field and other assets, net ..............
—
22,533
104,373
—
20,570
206,708
191,386
—
—
5,560
10,095
57,562
6,758
415,290
3,259
337,972
(330,086)
14,644
3,481
3,097,335
(1,840,332)
1,672,293
24,639
118,903
(13,046)
109,116
22,248
—
—
—
—
—
—
—
—
—
Investments in and advances to affiliates, net ............
1,834,197
Deferred financing costs, net ......................................
Derivative financial instruments.................................
Goodwill .....................................................................
Total assets..........................................................
Liabilities and shareholders' equity
Current liabilities ........................................................
27,771
6,829
13,293
2,004,588
76,174
$
$
$
$
Long-term debt ...........................................................
1,770,427
Deferred income taxes ................................................
Other long-term liabilities...........................................
Payable to parent.........................................................
Total shareholders' equity...................................
—
10,082
—
147,905
—
—
—
$
$
149,862
2,038,180
264,485
—
—
33,831
2,230,108
(490,244)
—
(1,834,197)
1,036
—
—
—
—
—
200,057
$ (1,834,197) $ 2,408,628
8,511
$
— $
349,170
88,485
—
8,728
35,777
58,556
—
—
—
(2,265,885)
1,858,912
—
52,641
—
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)
Revenues:
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Oil and natural gas ...............................................................
$
3,649
$
614,889
$
41,731
$
— $
660,269
Costs and expenses:
Oil and natural gas production.............................................
Gathering and transportation ...............................................
394
—
77,334
97,784
Depletion, depreciation and amortization............................
3,174
244,761
Impairment of oil and natural gas properties.......................
Accretion of discount on asset retirement obligations.........
General and administrative ..................................................
Other operating items ..........................................................
Total costs and expenses..................................................
Operating income.................................................................
Other income (expense):
Interest expense, net.............................................................
Gain on derivative financial instruments.............................
Other income .......................................................................
Equity income......................................................................
Net earnings from consolidated subsidiaries .......................
Total other income (expense)...........................................
Income before income taxes ................................................
Income tax expense..............................................................
—
16
(3,342)
(134)
108
3,541
(92,049)
87,565
226
—
121,386
117,128
120,669
—
—
2,107
66,686
5,459
494,131
120,758
—
—
—
—
—
—
16,598
3,790
15,634
—
567
2,576
(10)
39,155
2,576
(2,235)
100
15
172
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(121,386)
94,326
101,574
263,569
—
2,690
65,920
5,315
533,394
126,875
(94,284)
87,665
241
172
—
(1,948)
(121,386)
(6,206)
120,758
—
628
—
(121,386)
120,669
—
—
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)
Revenues:
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Oil and natural gas ..................................................................
$
9,136
$
582,158
$
43,015
$
— $
634,309
Costs and expenses:
Oil and natural gas production................................................
Gathering and transportation ..................................................
Depletion, depreciation and amortization...............................
Impairment of oil and natural gas properties ..........................
Accretion of discount on asset retirement obligations............
2,440
—
5,917
—
63
General and administrative .....................................................
23,125
63,716
97,166
225,499
108,546
1,881
66,558
Gain on divestitures and other operating items ......................
(25,950)
(151,549)
Total costs and expenses.....................................................
Operating income (loss)..........................................................
5,595
3,541
411,817
170,341
Other income (expense):
Interest expense, net................................................................
(99,815)
Gain (loss) on derivative financial instruments ......................
Other income (loss).................................................................
Equity loss ..............................................................................
1,439
(1,068)
—
Net earnings from consolidated subsidiaries ..........................
118,107
Total other income (expense)..............................................
Income (loss) before income taxes .........................................
Income tax expense.................................................................
18,663
22,204
—
—
(177)
229
—
—
52
170,393
—
17,092
3,479
14,359
—
570
2,195
(19)
37,676
5,339
(2,774)
(1,582)
11
(53,280)
—
(57,625)
(52,286)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(118,107)
(118,107)
(118,107)
—
83,248
100,645
245,775
108,546
2,514
91,878
(177,518)
455,088
179,221
(102,589)
(320)
(828)
(53,280)
—
(157,017)
22,204
—
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)
Revenues:
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Oil and natural gas....................................................
$
78,649
$
467,960
$
— $
— $
546,609
Costs and expenses:
Oil and natural gas production..................................
Gathering and transportation ....................................
Depletion, depreciation and amortization.................
Impairment of oil and natural gas properties............
Accretion of discount on asset retirement
obligations ................................................................
General and administrative.......................................
Other operating items ...............................................
Total costs and expenses.......................................
Operating income (loss)............................................
Other income:
19,820
—
7,767
—
526
14,394
(194)
42,313
36,336
Interest expense, net .................................................
Gain on derivative financial instruments..................
Other income ............................................................
Equity income...........................................................
Net loss from consolidated subsidiaries ...................
Total other income (expense)................................
(73,489)
62,812
238
—
(1,419,182)
(1,429,621)
84,790
102,875
295,389
1,346,749
3,361
69,424
17,223
1,919,811
(1,451,851)
(3)
3,321
731
—
—
4,049
Income (loss) before income taxes ...........................
(1,393,285)
(1,447,802)
Income tax expense ..................................................
—
—
—
—
—
—
—
—
—
—
—
—
—
—
28,620
—
28,620
28,620
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,419,182
1,419,182
1,419,182
—
104,610
102,875
303,156
1,346,749
3,887
83,818
17,029
1,962,124
(1,415,515)
(73,492)
66,133
969
28,620
—
22,230
(1,393,285)
—
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)
Operating Activities:
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
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 ...........................................
Restricted cash .............................................................................
Equity method investments..........................................................
Proceeds from disposition of property and equipment ................
Distributions received from Compass .........................................
Net changes in advances to joint ventures...................................
Advances/investments with affiliates ..........................................
Net cash provided by (used in) investing activities .....................
Financing Activities:
(2,531)
(395,974)
(4,061)
—
—
99,612
5,856
—
125,612
228,549
(3,400)
1,749
95,594
—
(5,026)
(125,612)
—
—
(7,551)
—
—
—
—
—
—
—
(5,856)
—
—
(402,566)
(3,400)
1,749
187,655
—
(5,026)
—
(432,669)
(11,612)
(5,856)
(221,588)
Borrowings under credit agreements ...........................................
100,000
Repayments under credit agreements ..........................................
(959,874)
Proceeds received from issuance of 2022 Notes .........................
Proceeds from issuance of common shares, net ..........................
500,000
271,773
Payment of common share dividends ..........................................
(41,060)
Compass cash distribution ...........................................................
—
Deferred financing costs and other ..............................................
(10,188)
Payments of common shares repurchased ...................................
(136)
Net cash used in financing activities ...........................................
(139,485)
—
—
—
—
—
—
—
—
—
—
(5,096)
—
—
—
—
—
—
—
—
(5,856)
5,856
(102)
—
—
—
100,000
(964,970)
500,000
271,773
(41,060)
—
(10,290)
(136)
(11,054)
5,856
(144,683)
Net increase (decrease) in cash....................................................
Cash at beginning of period.........................................................
4,997
81,840
(4,640)
(35,892)
(4,535)
4,535
—
—
Cash at end of period ...................................................................
$
86,837
$
(40,532) $
— $
— $
(4,178)
50,483
46,305
111
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended December 31, 2013
(in thousands)
Operating Activities:
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
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....................................
Restricted cash.............................................................................
Equity method investments .........................................................
Proceeds from disposition of property and equipment................
244,500
Distributions from Compass .......................................................
Net changes in advances to joint ventures ..................................
Advances/investments with affiliates..........................................
Other............................................................................................
3,825
—
(59,575)
(1,303)
(15,767)
(1,242,667)
(38,818)
—
—
49,515
236,289
505,128
—
10,645
59,575
—
—
—
—
—
—
—
—
—
—
—
—
(3,825)
—
—
—
(1,297,252)
49,515
236,289
749,628
—
10,645
—
(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
Repayments under credit agreements..........................................
(1,015,900)
Proceeds from issuance of common shares, net..........................
1,712
Payment of common share dividends..........................................
(43,214)
Compass cash distribution...........................................................
—
Deferred financing costs and other..............................................
(33,317)
Net cash provided by (used in) financing activities ....................
(122,953)
—
—
—
—
—
—
—
Net increase (decrease) in cash ...................................................
Cash at beginning of period ........................................................
16,049
65,791
(15,745)
(20,147)
36,757
(6,885)
—
—
(3,825)
(236)
25,811
4,535
—
—
—
—
—
3,825
—
3,825
—
—
Cash at end of period...................................................................
$
81,840
$
(35,892) $
4,535
$
— $
1,004,523
(1,022,785)
1,712
(43,214)
—
(33,553)
(93,317)
4,839
45,644
50,483
112
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended December 31, 2012
(in thousands)
Operating Activities:
Resources
Guarantor
Subsidiaries
Non-
guarantor
subsidiaries
Eliminations
Consolidated
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.......................................................
Restricted cash.................................................................
Equity method investments .............................................
Proceeds from disposition of property and equipment....
Net changes in advances to joint ventures ......................
Advances/investments with affiliates..............................
Net cash used in investing activities ...............................
Financing Activities:
Borrowings under the credit agreements.........................
Repayments under the credit agreements........................
Proceeds from issuance of common shares, net..............
Payment of common share dividends..............................
Deferred financing costs and other..................................
Net cash used in financing activities ...............................
Net increase (decrease) in cash .......................................
Cash at beginning of period ............................................
(77,006)
(459,917)
—
—
15,161
—
(59,126)
(120,971)
53,000
(93,000)
1,968
(34,358)
(1,655)
(74,045)
(12,873)
78,664
85,840
(14,907)
22,884
851
59,126
(306,123)
—
—
—
—
—
—
26,520
(46,667)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Cash at end of period.......................................................
$
65,791
$
(20,147) $
— $
— $
(536,923)
85,840
(14,907)
38,045
851
—
(427,094)
53,000
(93,000)
1,968
(34,358)
(1,655)
(74,045)
13,647
31,997
45,644
113
17.
Quarterly financial data (unaudited)
The following are summarized quarterly financial data for the years ended December 31, 2014 and 2013:
(in thousands, except per share amounts)
2014
Oil and natural gas revenues............................
Operating income (loss) ..................................
Net income (loss).............................................
Basic earnings (loss) per share:
Net income (loss)........................................
Weighted average shares.............................
Diluted earnings (loss) per share:
Net income (loss)........................................
Weighted average shares.............................
2013
Oil and natural gas revenues............................
Operating income (loss) (1).............................
Net income (loss) (2) (3) .................................
Basic earnings (loss) per share:
Net income (loss)........................................
Weighted average shares.............................
Diluted earnings (loss) per share:
Net income (loss)........................................
Weighted average shares.............................
$
$
$
$
$
$
$
$
1st
2nd
3rd
4th
Quarter
198,472
$
57,423
(4,606) $
(0.02) $
260,716
$
$
$
182,966
43,312
2,293
0.01
270,492
$
$
$
151,042
22,799
41,569
0.15
270,631
(0.02) $
0.01
$
0.15
$
260,716
271,226
272,066
$
$
$
138,223
209,075
158,120
0.74
214,784
$
$
$
150,332
33,883
85,598
0.40
214,788
165,314
$
15,594
(98,651) $
(0.46) $
215,056
0.74
$
0.40
$
(0.46) $
214,861
216,023
215,056
127,789
3,341
81,413
0.30
271,053
0.30
271,053
180,440
(79,331)
(122,863)
(0.57)
215,410
(0.57)
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)
2014:
Amount
Proved property acquisition costs .................................................................................................................
$
Unproved property acquisition costs.............................................................................................................
Total property acquisition costs ....................................................................................................................
Development .................................................................................................................................................
Exploration costs (1) .....................................................................................................................................
Lease acquisitions and other .........................................................................................................................
Capitalized asset retirement costs .................................................................................................................
Depletion per Boe .........................................................................................................................................
Depletion per Mcfe .......................................................................................................................................
$
$
2013:
Proved property acquisition costs .................................................................................................................
$
Unproved property acquisition costs.............................................................................................................
Total property acquisition costs (2)...............................................................................................................
Development .................................................................................................................................................
Exploration costs (3) .....................................................................................................................................
Lease acquisitions and other .........................................................................................................................
Capitalized asset retirement costs .................................................................................................................
Depletion per Boe .........................................................................................................................................
Depletion per Mcfe .......................................................................................................................................
$
$
2012:
Proved property acquisition costs .................................................................................................................
$
Unproved property acquisition costs.............................................................................................................
Total property acquisition costs ....................................................................................................................
Development .................................................................................................................................................
Exploration costs (4) .....................................................................................................................................
Lease acquisitions and other (5)....................................................................................................................
Capitalized asset retirement costs .................................................................................................................
Depletion per Boe .........................................................................................................................................
Depletion per Mcfe .......................................................................................................................................
$
$
10,562
—
10,562
354,199
5,906
9,681
576
11.42
1.90
754,370
232,020
986,390
231,447
38,579
14,835
514
8.82
1.47
—
3,349
3,349
346,017
57,325
44,546
971
9.11
1.52
Exploration costs in 2014 include $5.9 million in the Bossier shale in North Louisiana.
(1)
(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.
Exploration costs in 2013 include $29.2 million in the Eagle Ford shale and $9.4 million in the Marcellus shale.
Exploration costs in 2012 include $40.1 million in the Haynesville shale $17.2 million in the Marcellus shale.
Lease acquisition costs in 2012 are net of acreage reimbursements from BG Group totaling $2.1 million.
(3)
(4)
(5)
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.
December 31, 2011
Purchase of reserves in place ...............................................
Discoveries and extensions (1).............................................
Revisions of previous estimates: ..........................................
Changes in price ..............................................................
Other factors (2) ..............................................................
Sales of reserves in place .....................................................
Production ............................................................................
December 31, 2012
Purchase of reserves in place (3)..........................................
Discoveries and extensions (4).............................................
Revisions of previous estimates: ..........................................
Changes in price ..............................................................
Other factors (5) ..............................................................
Sales of reserves in place (6)................................................
Production ............................................................................
December 31, 2013
Purchase of reserves in place (7).........................................
Discoveries and extensions (8).............................................
Revisions of previous estimates: ..........................................
Changes in price ..............................................................
Other factors (9) ..............................................................
Sales of reserves in place (10)..............................................
Production ............................................................................
December 31, 2014
Oil
(Mbbls)
6,354
—
492
(110)
(463)
—
(703)
5,570
16,022
5,960
457
(3,219)
(8,224)
(1,188)
15,378
—
4,164
45
1,737
(1,401)
(2,236)
17,687
Natural
Gas
(Mmcf)
1,291,464
—
96,615
(466,238)
199,784
(2,837)
(182,656)
936,132
290,933
46,834
272,614
(106,695)
(270,018)
(153,321)
1,016,479
7,316
69,902
167,302
120,850
(105,841)
(120,980)
1,155,028
Natural Gas
Liquids (Mbbls)
—
—
424
—
6,724
—
(509)
6,639
2,201
513
686
(741)
(6,472)
(243)
2,583
—
107
127
(8)
(2,144)
(224)
441
Mmcfe (11)
1,329,588
—
102,111
(466,898)
237,350
(2,837)
(189,928)
1,009,386
400,271
85,672
279,472
(130,455)
(358,194)
(161,907)
1,124,245
7,316
95,528
168,334
131,224
(127,111)
(135,740)
1,263,796
Estimated Quantities of Proved Developed and Proved Undeveloped Reserves
Proved developed:
December 31, 2014..................................
December 31, 2013..................................
December 31, 2012..................................
Proved undeveloped:
December 31, 2014..................................
December 31, 2013..................................
December 31, 2012..................................
Oil
(Mbbls)
Natural
Gas
(Mmcf)
Natural Gas Liquids
(Mbbls)
Mmcfe
14,429
11,274
4,371
3,258
4,104
1,199
502,314
657,116
917,326
652,714
359,363
18,806
387
2,088
4,784
54
495
1,855
591,210
737,291
972,256
672,586
386,954
37,130
(1) New discoveries and extensions in 2012 include 25,626 Mmcfe in East Texas/North Louisiana, primarily in the
(2)
Haynesville shale, 59,455 Mmcfe in the Marcellus shale and 17,027 Mmcfe in the Permian Basin.
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
(3)
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.
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.
(5)
(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.
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.
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.
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.
(7)
(6)
(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.
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.
(9)
(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)
Year ended December 31, 2014:
Future cash inflows ..............................................................................................................
Future production costs........................................................................................................
Future development costs ....................................................................................................
Future income taxes .............................................................................................................
Future net cash flows ...........................................................................................................
Discount of future net cash flows at 10% per annum ..........................................................
Standardized measure of discounted future net cash flows .................................................
Year ended December 31, 2013:
Future cash inflows ..............................................................................................................
Future production costs........................................................................................................
Future development costs ....................................................................................................
Future income taxes .............................................................................................................
Future net cash flows ...........................................................................................................
Discount of future net cash flows at 10% per annum ..........................................................
Standardized measure of discounted future net cash flows .................................................
Year ended December 31, 2012:
Future cash inflows ..............................................................................................................
Future production costs........................................................................................................
Future development costs ....................................................................................................
Future income taxes .............................................................................................................
Future net cash flows ...........................................................................................................
Discount of future net cash flows at 10% per annum ..........................................................
Standardized measure of discounted future net cash flows .................................................
$
$
$
$
$
$
Amount
6,097,207
2,094,796
1,124,873
—
2,877,538
1,334,951
1,542,587
5,176,030
2,207,230
904,116
—
2,064,684
812,411
1,252,273
3,187,480
1,824,702
266,726
—
1,096,052
399,905
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)
Year ended December 31, 2014:
Sales and transfers of oil and natural gas produced ................................................................................................
Net changes in prices and production costs.............................................................................................................
Extensions and discoveries, net of future development and production costs ........................................................
Development costs during the period ......................................................................................................................
Changes in estimated future development costs......................................................................................................
Revisions of previous quantity estimates ................................................................................................................
Sales of reserves in place.........................................................................................................................................
Purchase of reserves in place...................................................................................................................................
Accretion of discount before income taxes .............................................................................................................
Changes in timing and other....................................................................................................................................
Net change in income taxes.....................................................................................................................................
Net change ...............................................................................................................................................................
Year ended December 31, 2013:
Sales and transfers of oil and natural gas produced ................................................................................................
Net changes in prices and production costs.............................................................................................................
Extensions and discoveries, net of future development and production costs ........................................................
Development costs during the period ......................................................................................................................
Changes in estimated future development costs......................................................................................................
Revisions of previous quantity estimates ................................................................................................................
Sales of reserves in place.........................................................................................................................................
Purchase of reserves in place...................................................................................................................................
Accretion of discount before income taxes .............................................................................................................
Changes in timing and other....................................................................................................................................
Net change in income taxes.....................................................................................................................................
Net change ...............................................................................................................................................................
Year ended December 31, 2012:
Sales and transfers of oil and natural gas produced ................................................................................................
Net changes in prices and production costs.............................................................................................................
Extensions and discoveries, net of future development and production costs ........................................................
Development costs during the period ......................................................................................................................
Changes in estimated future development costs......................................................................................................
Revisions of previous quantity estimates ................................................................................................................
Sales of reserves in place.........................................................................................................................................
Purchase of reserves in place...................................................................................................................................
Accretion of discount before income taxes .............................................................................................................
Changes in timing and other....................................................................................................................................
Net change in income taxes.....................................................................................................................................
Net change ...............................................................................................................................................................
$
Amount
(464,369)
279,944
196,796
189,155
(254,737)
412,296
(148,226)
13,507
125,227
(59,279)
—
$
290,314
$
(450,415)
582,725
197,223
55,196
(251,484)
98,283
(315,758)
604,366
69,615
(33,625)
—
$
556,126
$
(339,125)
(1,258,493)
90,633
204,929
404,414
(336,142)
(3,604)
—
165,755
94,129
247,189
(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)
Property acquisition costs.............................
Exploration and development.......................
Capitalized interest.......................................
Total..............................................................
$
Total
228,553
16,366
31,106
2014
2013
2012
2011 and
prior
$
9,737
$
71,524
$
3,038
$
144,254
10,797
11,871
73
8,737
524
6,796
4,972
3,702
$
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
Item 10.
Directors, Executive Officers and Corporate Governance
PART III
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)
(c)
See "Index to Exhibits" for a description of our exhibits.
None.
121
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.
SIGNATURES
Date: February 25, 2015
EXCO RESOURCES, INC.
(Registrant)
122
Date: February 25, 2015
EXCO RESOURCES, INC.
(Registrant)
/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
Exhibit
Number
Description of Exhibits
INDEX TO EXHIBITS
2.1
2.2
2.3
2.4
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
4.6
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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
4.6
4.7
4.8
4.9
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
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.
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.
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.
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.
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.
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.*
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.*
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.*
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.*
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.*
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.*
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.*
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.*
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
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
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.
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.*
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.*
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.*
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.*
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.
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.
Amendment to Joint Development Agreement, dated October 14, 2014, by and among BG US Production
Company, LLC and EXCO Operating Company, LP, filed herewith.
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.
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.
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.
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.
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.
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.
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
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
10.37
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.
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.
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.
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.
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.
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.*
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.
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.
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.
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.
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.
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.
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
10.39
10.40
10.41
10.42
10.43
10.44
10.45
10.46
10.47
10.48
10.49
10.50
14.1
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.
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.
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.
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.
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.
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.
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.*
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.*
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.*
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.*
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.
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.*
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.*
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
14.3
21.1
23.1
23.2
23.3
23.4
31.1
31.2
32.1
99.1
99.2
99.3
99.4
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.
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.
Subsidiaries of registrant, filed herewith.
Consent of KPMG LLP, filed herewith.
Consent of Lee Keeling and Associates, Inc., filed herewith.
Consent of Netherland, Sewell & Associates, Inc., filed herewith.
Consent of Ryder Scott Company, L.P., filed herewith.
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer of EXCO
Resources, Inc., filed herewith.
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Financial Officer of EXCO
Resources, Inc., filed herewith.
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.
2014 Report of Lee Keeling and Associates, Inc., filed herewith.
2014 Report of Netherland, Sewell & Associates, Inc., filed herewith.
2014 Report of Ryder Scott Company, L.P., filed herewith.
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
SEC AND NYSE CERTIFICATIONS
The Forms 10-K and 10-K/A, included herein, which were filed by the company with the SEC for the fiscal year ending December 31,
2014, include, as exhibits, the certifications of our principal executive officer and principal financial officer required to be filed with
the SEC. Our principal executive officer also filed his 2014 annual certification with the NYSE confirming that the company has
complied with the NYSE corporate governance listing standards.
DIRECTORS
JEFFREY D. BENJAMIN 1, 2, 3
Non-Executive Chairman of the Board –
EXCO Resources, Inc.
Senior Advisor –
Cyrus Capital Partners, LP
B. JAMES FORD 2, 3
Managing Director –
Oaktree Capital Management, L.P.
SAMUEL A. MITCHELL 1, 2, 3
Managing Director –
Hamblin Watsa Investment Counsel
WILBUR L. ROSS, JR. 2, 3
Chairman and Chief Strategy Officer –
WL Ross & Co. LLC
JEFFREY S. SEROTA 1, 2, 3
Independent Director
ROBERT L. STILLWELL 1, 2, 3
Retired General Counsel –
BP Capital LP
1 Audit Committee Member
2 Compensation Committee Member
3 Nominating and Corporate Governance Committee Member
OFFICERS
HAROLD L. HICKEY
Chief Executive Officer and President
WILLIAM L. BOEING
Vice President, General Counsel
and Secretary
RICHARD A. BURNETT
Vice President, Chief Financial Officer
and Chief Accounting Officer
JOE D. FORD
Vice President
of Human Resources
ROBERT R. GESSNER, JR.
Corporate Controller
RUSSELL D. GRIFFIN
Vice President of Environmental,
Health and Safety
HAROLD H. JAMESON
Vice President and Chief Operating Officer
DANIEL W. HIGDON
Vice President of Land
MICHAEL R. CHAMBERS, SR.
Vice President of Operations
and Asset Management
W. JUSTIN CLARKE
Assistant General Counsel,
Chief Compliance Officer
and Assistant Secretary
RONALD G. EDELEN
Vice President of Supply Chain
STEVE L. ESTES
Vice President of Marketing
CHRISTOPHER C. PERACCHI
Vice President of Finance
and Investor Relations, and Treasurer
STEPHEN E. PUCKETT
Vice President of Reservoir Engineering
MARCIA R. SIMPSON
Vice President of Engineering
ROBERT L. THOMAS
Chief Information Officer
SHAREHOLDER INFORMATION
Shareholder Relations
Christopher C. Peracchi
Vice President, Finance and
Investor Relations,
and Treasurer
214.368.2084
NYSE Symbol
XCO – Common Stock
Auditors
KPMG LLP
717 North Harwood Street
Suite 3100
Dallas, TX 75201
Legal Counsel
Haynes and Boone, LLP
2323 Victory Avenue
Suite 700
Dallas, TX 75219
Annual Meeting
The 2015 Annual Meeting
of Shareholders will be held
on Wednesday, August 5, 2015
at 10:00 a.m. local time at:
EXCO Resources, Inc.
12377 Merit Drive
First Floor Conference Center
Dallas, TX 75251
Stock Transfer Agent
Continental Stock Transfer &
Trust Company
Communications concerning
transfer or exchange requirements,
lost certificates, shareholdings
or changes of address should be
directed to:
17 Battery Place, 8th Floor
New York, NY 10004
212.509.4000
Number of Common Shareholders
27,326
(As of May 27, 2015)
EXCO Resources, Inc.
NYSE Composite Index
Crude Petroleum and
Natural Gas Index
TOTAL RETURN
Assumes Initial Investment of $100
December 2014
$200
$150
$100
$50
$0
The graph to the right compares
the cumulative total return (what
$100 invested on December 31, 2009
would be worth on December 31, 2014)
on the Company’s common stock
with the cumulative total return on
the NYSE Composite Index and the
Crude Petroleum and Natural Gas
SIC Code Index.
These historical comparisons
are not a forecast of the future
performance of our common
stock or the referenced indexes.
09.13.21
10.13.21
11.13.21
12.31.12
13.13.21
14.13.21
12.31.09
12.31.10
12.31.11
12.31.1 2
12.31.13
12.31.14
PERIOD ENDING
.cnI ,secruoseR OCXE
00.001$
42.29$
91.05$
52.33$
78.62$
$
13.11
xednI etisopmoC ESYN
00.001$
67.311$
07.901$
35.721$
02.161$
72.271$
Crude Petroleum and Natural Gas Index
$ 100.00
$ 108.66
$ 98.86
$ 100.44
$ 101.51
$
81.22
EXCO Resources, Inc.
12377 Merit Drive
Suite 1700
Dallas, Texas 75251
Phone 214.368.2084
Fax 214.368.2087
www.excoresources.com