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2013
A N N U A L
R E P O R T
MISSION STATEMENT
EXCO Resources, Inc. is a natural gas and oil company engaged
in the exploration, exploitation, acquisition, development and
production of onshore natural gas and oil properties. Our
operations are focused in certain key natural gas and oil-
producing regions of the United States.
Our primary goal is to build value for our shareholders by
enhancing the value of our assets through efficient operations,
a high-technology drilling program, development of our
properties and exploitation of unproved upside.
GUIDING PRINCIPLES
At EXCO, we achieve our mission within the framework
established by our guiding principles.
ETHICS
SAFETY
TEAMWORK
TECHNOLOGY
GROWTH
ETHICS
We are committed to transparency and conducting
our business ethically and lawfully. We are accountable
by taking responsibility for our actions and results.
SAFETY
We provide a safe place to work and protect
our environment.
TEAMWORK
We create a work environment that encourages
teamwork and cooperation by treating each other
with respect and understanding.
TECHNOLOGY
We pursue continuous improvement by encouraging
technological innovation in the achievement of our goals.
GROWTH
We work to produce a high return and deliver on
commitments to our shareholders.
HAYNESVILLE AND BOSSIER SHALES – East Texas / North Louisiana
Core Areas
• 70,000 net acres
• Gross well count: 447
• 724 Bcfe of proved reserves
EAGLE FORD SHALE - South Texas
• 47,800 net acres
• Gross well count: 140
• 91 Bcfe of proved reserves
MARCELLUS SHALE – Appalachia
• 145,000 net acres
• Gross well count: 124
• 126 Bcfe of proved reserves
2013 Highlights
Continued efficient
development of asset base
Closed $943 million of
strategic acquisitions
Reduced leverage through
$984 million of asset sales
Commenced rights offering
that raised $273 million
South Texas
East Texas /
North Louisiana
Appalachia
PROVED RESERVES
BREAKDOWN (Bcfe)*
181 Appalachia
91 South Texas
725 East Texas /
North Louisiana
* Proved Reserves reflect year-end SEC pricing
and excludes EXCO’s proportionate share of
XCO/HGI Partnership (125 Bcfe) & Other (2 Bcfe).
2013 Annual Report |• 1
DEAR FELLOW SHAREHOLDERS
Thank you for your interest in, and support of,
EXCO Resources. We appreciate that your decision
to invest in EXCO brings with it an expectation that
we will be stewards of your capital and deploy it in
a way to build long-term value for all of our investors.
We are deeply committed to that objective.
EXCO’s primary near-term focus is
In February, we formed a partnership
to capitalize on the experience of our
focused on conventional assets and we
technical and operations team to create
contributed our conventional non-shale
long-term value. EXCO currently operates
assets in East Texas and North Louisiana
more than 7,800 wells and has significant
and our shallow Canyon Sand and other
acreage positions in three strategic shale
assets in the Permian Basin of West Texas
plays in the United States. We believe
in exchange for $575 million in cash, a
we have great optionality and upside in
25% interest in the limited partnership
our drilling location inventory and will
and a 50% general partnership interest.
be beneficiaries of a macro improvement
The primary strategy of the partnership
in commodity prices. We expect a con-
is to efficiently manage its current asset
tinuing tightening of supply and demand
base and acquire conventional producing
in natural gas in the United States and
oil and natural gas properties to enhance
rising prices should be a great benefit
asset value and cash flow. In March 2013,
to an experienced, efficient and low-cost
the partnership closed its first acquisition
operator like EXCO Resources.
by acquiring incremental working inter-
2013 was a year of significant accomplish-
ments at EXCO. Through a combination
of efficient development of our asset
base, strategic acquisitions and divesti-
tures, and financing transactions, we
exited the year with a more diversified
asset portfolio that positions EXCO
ests for $131 million in properties already
operated by the partnership. This acquisi-
tion was funded with borrowings under
the partnership’s own credit facility. The
partnership’s operations are currently
funded with its cash flows from opera-
tions and, as necessary, its credit facility.
for future growth. EXCO completed
In July, we closed two strategic acquisi-
approximately $1 billion of asset sales in
tions that added to our core area in the
four separate transactions during the
Haynesville and established our oil pres-
year which helped us close $943 million
ence in the Eagle Ford for an aggregate
of strategic acquisitions. In addition, in
purchase price of $943 million. These
January 2014, we raised $273 million of
acquisitions were initially financed with
equity through a rights offering that
borrowings under our credit agree-
enhanced our liquidity and improved
ment. Subsequently, we have paid down
our balance sheet, providing us flexibility
the borrowings using proceeds from
to exploit our asset position. This letter
divestitures and our rights offering.
summarizes these accomplishments
and will help frame where EXCO is today
and where we are headed in the future.
2 | EXCO Resources, Inc.
The $281 million Haynesville acquisition
associated with the Eagle Ford develop-
included producing wells and oil, natural
ment while establishing a platform for
gas and mineral leases located in our core
future growth through the acquisitions of
Haynesville shale operating area in Caddo
oil-focused proved developed producing
and DeSoto Parishes, Louisiana. These
properties at attractive prices based on
properties increased our ownership
the offer process within the agreement.
interest in 170 wells that we operate on
We are applying our technical and opera-
approximately 5,500 net acres and also
tional expertise developed in the Haynes-
included operated interests in 11 produc-
ville to the Eagle Ford shale, and are
ing wells on approximately 4,000 addi-
realizing operational efficiencies as we
tional net acres. The acquisition added
move to a manufacturing mode in our
approximately 55 identified drilling loca-
tions to our drilling inventory and added
core Eagle Ford area. Since taking over
operations, both our drilling times and
to our contiguous Haynesville shale acre-
overall well costs have been reduced.
age, where we continue to be one of the
premier operators within this play. Our
operating team has drilled over 430 wells
in the Haynesville shale and has built a
competitive advantage through continu-
ous improvement as a leading low-cost
operator with a proven manufacturing
mode development capability. Our econ-
omies of scale in the Haynesville have
allowed us to efficiently develop our
assets and minimize our costs through
greater utilization of multi-well pads and
existing infrastructure and facilities.
The $662 million Eagle Ford acquisition
included producing wells and oil, natural
gas and mineral leases in the Eagle Ford
shale in Zavala, Dimmit and Frio counties
in South Texas. These properties included
operated interests in 120 wells on approx-
imately 53,500 net acres. The acquisition
added approximately 300 identified drill-
ing locations to our drilling inventory and
also provided farm-in opportunities on
additional acreage. We believe this acqui-
sition includes significant upside on the
undeveloped acreage while increasing our
exposure to oil production. In connection
with the acquisition, we entered into a
participation agreement and sold a 50%
interest in the undeveloped acreage we
acquired for $131 million. The participation
agreement allows us to diversify the risks
In November, we sold our equity interest
in our midstream company, TGGT, for
net cash proceeds of $240 million and a
4% equity interest in the buyer. We used
the proceeds to reduce the borrowings
incurred with our 2013 acquisitions. We
sold TGGT as the midstream business
is not core to our primary strategy of
focusing on the exploitation and develop-
ment of our shale resource plays.
In December, we commenced a common
stock rights offering and raised $273 mil-
JEFFREY D. BENJAMIN
Non-Executive
Chairman of the Board
HAROLD L. HICKEY
lion with the support of our broad share-
President and
holder base and our principal investors.
Chief Operating Officer
The proceeds allowed us to eliminate the
asset sale requirement under our credit
agreement related to our acquisitions
six months ahead of the July 2014 deadline
and helped us pay down our revolving
indebtedness.
Our position in the Marcellus shale con-
tinues to evolve with a combination of
appraisal and development wells primar-
ily in Armstrong, Jefferson, Sullivan and
Lycoming counties in Pennsylvania. We
currently hold 290,000 net acres in the
Appalachia basin, with approximately
145,000 of those net acres prospective
for the Marcellus shale. As of Decem-
ber 31, 2013, we operated approximately
5,800 vertical shallow wells in Appalachia
and 124 horizontal wells in the Marcellus
2013 Annual Report | 3
shale. During 2013, we turned to sales
For 2014, we continue to focus on effi-
20 gross wells. Our drilling program in
ciently developing our asset base and
this region has been limited in response
are having solid results replicating our
to lower realized gas prices from the
proven Haynesville efficiencies in the
widening of differentials. A significant
Eagle Ford. Managing our balance sheet,
amount of this acreage is held by produc-
maintaining ample liquidity and simplifying
tion allowing us flexibility in the timing of
our organ ization remain top priorities.
our drilling activities. Our Marcellus acre-
We continue to demonstrate fiscal disci-
age position includes over 1,500 drilling
pline and our 2014 capital expenditure
locations that provide us long-term
budget of approximately $370 million is
optionality and upside to improvements
designed to manage our capital expendi-
in technology and infrastructure and
tures in relation to our operating cash
rising natural gas prices.
flow. We recently closed the sale of our
On the operations side, our team drilled
and turned to sales 99 wells. Of the
99 wells, 51 were in the Haynesville shale,
where we have focused on improving
non-operated West Texas asset for
$68 million and used the proceeds to
further reduce the borrowings on
our revolving indebtedness.
the efficiency of our drilling and comple-
Finally, the Board has engaged an execu-
tion operations which has resulted in
tive recruiting firm to assist in identifying
significant reductions to our well costs.
the next CEO of EXCO Resources. We are
In DeSoto Parish, our average drilling
committed to attracting the right leader
and completion costs per well decreased
to capitalize on our current asset base
to $7.5 million per well during 2013, as
and operating team and build long-term
compared to $8.0 million per well during
value for our shareholders.
2012 and $9.5 million per well during 2011.
We continue to achieve improved drilling
times per well and we are currently
averaging 33 days from spud to rig
release for a typical 16,500-foot
Haynesville well in DeSoto Parish.
With the review of 2013, you can see
how EXCO significantly enhanced its
liquidity as we reduced debt by $581 mil-
lion from third quarter 2013 levels. We
are focused in three strong shale posi-
tions (Haynesville and Bossier, Eagle Ford
and Marcellus). We have built a solid
platform supported by an experienced
operating team with a demonstrated
ability to continuously drive down costs
and improve efficiencies. Our balance
sheet and liquidity have been strength-
ened in 2013 to protect against market
fluctuations and allow us to opportunis-
tically pursue growth opportunities.
We thank you for your support and
look forward to executing our strategy
for 2014 and beyond.
Sincerely,
JEFFREY D. BENJAMIN
Non-Executive Chairman of the Board
HAROLD L. HICKEY
President and Chief Operating Officer
4 | EXCO Resources, Inc.
NET DEBT
OUTSTANDING
($ IN MILLIONS)
$ 2,200
$ 2,000
$ 1,800
$ 1,600
$ 1,400
$ 1,200
$ 1,000
$ 800
$ 600
$ 400
$ 200
$
0
N E T P R O D U C T I O N – N E T D E B T
DEBT REDUCTION
NET
PRODUCTION
(Mmcfe/d)
600
500
400
300
200
100
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q4
2010
2011
2012
2013
2013
PF
NET PRODUCTION (Mmcfe/d)
NET DEBT OUTSTANDING
2013 Annual Report | 5
FORWARD-LOOKING
STATEMENTS AND
SEC AND NYSE
CERTIFICATIONS
The graph to the right compares
the cumulative total return (what
$100 invested on December 31, 2008
would be worth on December 31, 2013)
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.
6 | EXCO Resources, Inc.
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 accu-
rately predict, or over which we have no control. You are cautioned not to place undue
reliance on a forward-looking statement. When considering our forward-looking state-
ments, keep in mind the risk factors and other cautionary statements included in our
Annual Report on Form 10-K for the year ended December 31, 2013, and our other
periodic filings with the Securities and Exchange Commission (SEC).
Our revenues, operating results, financial condition and ability to borrow funds or
obtain additional capital depend substantially on prevailing prices for oil and natural gas.
Declines in oil or natural gas prices may materially adversely affect our financial condi-
tion, liquidity, ability to obtain financing and operating results. Lower oil or natural gas
prices also may reduce the amount of oil or natural gas that we can produce economi-
cally. A decline in oil and/or natural gas prices could have a material adverse effect on
the estimated value and estimated quantities of our oil and natural gas reserves, our
ability to fund our operations and our financial condition, cash flow, results of operations
and access to capital. Historically, oil and natural gas prices and markets have been
volatile, with prices fluctuating widely, and they are likely to continue to be volatile.
SEC AND NYSE CERTIFICATIONS
The Form 10-K, included herein, which was filed by the company with the SEC for the
fiscal year ending December 31, 2013, includes, as exhibits, the certifications of our
principal executive officer and principal financial officer required to be filed with the SEC.
Our chief executive officer also filed his 2013 annual CEO certification with the NYSE
confirming that the company has complied with the NYSE corporate governance
listing standards.
COMPARISON OF FIVE-YEAR CUMULATIVE
TOTAL RETURN
Assumes Initial Investment of $100
December 2013
EXCO Resources, Inc.
Crude Petroleum and
Natural Gas Index
NYSE Composite Index
$290
$240
$190
$140
$90
$40
12.31.08
12.31.09
12.31.10
12.31.11
12.31.12
12.31.13
12.31.08
12.31.09
12.31.10
12.31.11
12.31.12
12.31.13
PERIOD ENDING
EXCO Resources, Inc.
$ 100.00
$ 235.11
$ 216.86
$ 117.99
$ 78.17
$ 63.18
NYSE Composite Index
$ 100.00
$ 128.95
$ 146.69
$ 141.46
$ 164.45
$ 207.85
Crude Petroleum and Natural Gas Index
$ 100.00
$ 144.70
$ 169.75
$ 154.94
$ 144.38
$ 176.87
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, 2013
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 Stock, $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
NO
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES
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 21, 2014, the registrant had 272,782,408 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 $1,042,010,000.
______________________________
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Definitive Proxy Statement on Schedule 14A to be furnished to shareholders in
connection with its 2014 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
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Properties
Legal Proceedings
Item 4. Mine Safety Disclosures
PART II.
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Item 6.
Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Financial Statements and Supplementary Data
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III.
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accountant Fees and Services
Part IV.
Item 15. Exhibits and Financial Statement Schedules
2
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48
48
48
48
49
50
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80
128
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129
129
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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 27.
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.
As of December 31, 2013, our Proved Reserves were approximately 1.1 Tcfe, of which 90% were natural gas and 66%
were Proved Developed Reserves. As of December 31, 2013, the PV-10 and Standardized Measure of our Proved Reserves
was approximately $1.3 billion. For the year ended December 31, 2013, we produced 161.9 Bcfe of oil, natural gas and
natural gas liquids.
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 enhancing 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.
We hold significant acreage positions in three prominent shale plays in the United States:
• East Texas and North Louisiana - we currently hold approximately 70,000 net acres in the Haynesville/Bossier
shales;
South Texas - we currently hold approximately 47,800 net acres in the Eagle Ford shale; and
•
• Appalachia - we currently hold approximately 145,000 net acres prospective in the Marcellus shale.
We commenced our horizontal drilling program in the Haynesville/Bossier shales during 2008 and have gained
extensive amounts of technical and operational expertise within these formations. We have spud 430 operated horizontal wells
from the commencement of our drilling program through December 31, 2013. We also own working interests in 178
Haynesville/Bossier shale horizontal wells operated by others. We have accumulated significant amounts of contiguous
acreage and are one of the largest operators within this region. Our economies of scale have allowed us to efficiently develop
our assets and minimize our costs through greater utilization of multi-well pads and existing infrastructure and facilities.
During 2013, we acquired additional assets in our core area of the Haynesville shale including additional working interests in
our operated wells and operated interests in producing wells in sections with additional developmental opportunities.
During 2013, we acquired producing wells and non-producing leasehold interests in the Eagle Ford shale. We believe
this acquisition includes significant upside on the undeveloped acreage while increasing our exposure to oil production. In
addition, we entered into a farm-out agreement covering additional acreage adjacent to the acquired properties. In connection
with the closing of the acquisition of the Eagle Ford assets, we entered into a participation agreement with Kohlberg Kravis
Roberts & Co. L.P. ("KKR") to jointly develop the assets (“KKR Participation Agreement”). We believe this agreement will
allow 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
agreement. We intend to apply our technical and operational expertise from other shale plays to the Eagle Ford shale and
2
realize operational efficiencies as we move to a manufacturing mode in our core area. Since we closed on the acquisition of
the Eagle Ford assets, we have spud 26 operated horizontal wells in the Eagle Ford shale through December 31, 2013.
Our principal activities in the Marcellus shale are focused on technical evaluations of our acreage holdings and a
disciplined appraisal drilling program. In 2014, we are planning appraisal initiatives as we evaluate future development
activities. A substantial portion of our shale resource play acreage is held-by-production, which gives us flexibility to defer
drilling as we evaluate our development activities without the threat of losing valuable leases.
Evaluate complementary acquisitions that meet our strategic and financial objectives
We continue to evaluate acreage opportunities and acquisitions of producing properties in our shale areas. We believe
we can leverage our technical expertise and economies of scale to maximize our returns in these areas. Our acquisition history
over the last five years has been focused on shale resource plays with an emphasis on the acquisition of undeveloped acreage.
Undeveloped acreage acquisitions differ from acquisitions of producing properties as undeveloped acreage acquisitions do not
result in immediate production and cash flows or provide incremental borrowing base capacity under our credit agreement
(the "EXCO Resources Credit Agreement"). The acquisitions we closed in July 2013 consisted of producing properties and
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 2013, we executed several key transactions that improved our liquidity and financial flexibility.
We utilized the proceeds from these transactions to reduce indebtedness under the EXCO Resources Credit Agreement and
facilitate the acquisitions of the Haynesville and Eagle Ford assets. These transactions included the following:
•
•
•
•
sold our equity interest in TGGT Holdings, LLC (“TGGT”) to Azure Midstream Holdings LLC (“Azure”) for cash
proceeds of approximately $240.2 million and an equity interest of approximately 4% in Azure;
formed a partnership (“EXCO/HGI Partnership”) with Harbinger Group Inc. (“HGI”). We contributed our
conventional non-shale assets in East Texas and North Louisiana and our shallow Canyon Sand and certain other
assets in the Permian Basin of West Texas to the EXCO/HGI Partnership in exchange for net proceeds of
approximately $574.8 million and a 25.5% economic interest in the EXCO/HGI Partnership. The operations of the
EXCO/HGI Partnership are currently funded with its cash flows from operations and its credit facility ("EXCO/
HGI Partnership Credit Agreement");
sold an undivided 50% interest in the undeveloped Eagle Ford acreage we acquired to KKR for approximately
$130.9 million and entered into the KKR Participation Agreement to jointly develop these assets; and
sold an undivided 50% interest in certain undeveloped acreage with horizontal shale drilling opportunities in the
Permian Basin. We received $37.9 million in cash and the purchaser agreed to fund our share of drilling and
completion costs within the joint venture area up to $18.9 million. The private party was designated as the
operator under the joint development agreement. On February 13, 2014, we entered into a purchase and sale
agreement with the private party for the sale of our interest in the joint venture for approximately $65.0 million.
We closed a rights offering of our common stock and related private placement on January 17, 2014 which resulted in
the issuance of 54,574,734 shares of our common stock for proceeds of $272.9 million. We utilized the proceeds from the
rights offering to repay indebtedness under the EXCO Resources Credit Agreement. After giving effect to the repayment of
indebtedness with proceeds from the rights offering, the revolving commitment under the EXCO Resources Credit Agreement
had a $900.0 million borrowing base with unused borrowing capacity of $401.4 million.
Our board of directors approved a capital expenditure budget of $368.0 million for 2014. We expect the capital
expenditure program will be funded primarily by our operating cash flow. Our capital program was designed to minimize the
impact of production declines while managing our capital expenditures in relation to our operating cash flow. We believe our
2014 budget will increase our exposure to crude oil production as it includes $138.0 million of capital expenditures that are
focused on drilling and development activities for oil in our South Texas region. Our capital expenditure budget excludes the
EXCO/HGI Partnership, which funds its capital expenditures through internally generated cash flow and its credit agreement.
We are also evaluating potential transactions which would further enhance our liquidity, including additional
divestitures of non-core assets, and continuous evaluation of cost reduction initiatives in operating and general and
administrative costs.
3
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 mitigate the impact of volatility in commodity prices and allow us to achieve more predictable cash
flows.
Our strengths
We have a number of strengths that we believe will help us successfully execute our strategy.
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,
2013, we operated 7,863 of our 8,453 gross wells, or wells representing approximately 97% 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 will 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 led both public and private oil and natural gas companies and 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 2014
Our plans for 2014 primarily focus on the exploitation and development of our core assets. These plans include a
disciplined development program which will primarily be funded with cash flows from our operations. We expect our
development program will result in a decline in natural gas production while increasing our crude oil production. We will also
focus on improving our operating margins as a result of initiatives to manage our operating and general and administrative
costs. This will allow us to preserve our liquidity and capital resources in preparation for future growth, including purchases
of Eagle Ford assets under the KKR Participation Agreement beginning in 2015. Although our focus is on the exploitation
and development of our current asset base, we will also continue to evaluate complementary acquisitions if opportunities arise
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, 2013:
Areas
East Texas/North Louisiana
South Texas (4)
Appalachia
Permian and other
EXCO/HGI Partnership (5)
Total
Areas
East Texas/North Louisiana
South Texas (4)
Appalachia
Permian and other
Total
EXCO/HGI Partnership (7)
Total Proved Reserves (Bcfe)
(1)
PV-10 (in millions) (1) (2)
Average daily net production
(Mmcfe) (3)
725.1
$
90.6
181.1
2.3
125.2
1,124.3
$
526.1
455.1
157.9
9.2
104.0
1,252.3
318
44
65
2
25
454
Estimated drilling locations
(6)
Total gross acreage
Total net acreage
2,167
325
3,533
101
6,126
805
189,300
97,000
672,500
29,500
988,300
179,200
87,000
47,800
290,400
18,200
443,400
39,400
(1) The total Proved Reserves and PV-10 as of December 31, 2013 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, 2013 and ending on December 1,
2013, of $3.67 per Mmbtu for natural gas and $96.78 per Bbl for oil, in each case adjusted for geographical and
historical differentials. The price per barrel for NGLs was $39.92 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 because the tax characteristics of comparable companies can differ materially. The total Standardized
Measure, a measure recognized under GAAP, as of December 31, 2013 was $1.3 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, 2013. 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 week of the year
ended December 31, 2013.
(4) We plan on developing certain undeveloped acreage in the Eagle Ford shale as part of the KKR Participation
Agreement. Under this agreement, we will assign half of our working interest in a well to KKR 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 buybacks under
the KKR Participation Agreement within our Proved Reserves. The acreage in this region consists of 36,500 net acres
outside of our core area in Zavala County that are subject to KKR's right to participate in each proposed well. Our
acreage in the South Texas region does not include the undeveloped locations associated with the farmout agreement
with Chesapeake Energy Corporation ("Chesapeake").
5
(6)
(5) We own a 25.5% economic interest in the EXCO/HGI Partnership and proportionately consolidate the reserves. The
reserves of the EXCO/HGI Partnership include conventional shallow producing assets in East Texas and North
Louisiana and shallow Canyon Sand and other assets in the Permian Basin of West Texas.
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. Of the total drilling locations shown in the table,
approximately 510 are classified as proved excluding the proved locations of the EXCO/HGI Partnership. 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”).
(7) The total identified drilling locations for the EXCO/HGI Partnership shown in the table include approximately 58
locations classified as proved. The net acreage reported for the EXCO/HGI Partnership represents our 25.5% economic
interest. The acreage reported for the EXCO/HGI Partnership primarily consists of shallow rights in the same acreage
for which EXCO owns the deep rights.
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 5,500 foot laterals resulting in wells with 16,000 to 20,000 feet of total measured
depth.
Our development drilling program in the Haynesville shale play is concentrated in the Holly area in DeSoto Parish,
Louisiana and the Shelby area in East Texas. At December 31, 2013, we operated three drilling rigs focused on our Holly
area. During 2014, we plan to operate an average of four drilling rigs to drill approximately 42 gross (20.5 net) wells and
complete approximately 35 gross (18.3 net) wells. As of December 31, 2013, our average operated shale natural gas
6
production was approximately 775 gross (304.5 net) Mmcfe per day. Including non-operated volumes, our total net
production from the Haynesville and Bossier shales was 318.0 Mmcfe per day as of December 31, 2013.
Holly area
Our position in the Holly area consists of 29,700 net acres in DeSoto Parish, of which 99% net acres are held-by-
production. We continue to develop the Holly area in DeSoto Parish in a manufacturing mode utilizing multi-well pad
development. The multi-well pad design minimizes surface impact and provides for a more capital efficient gathering and
production system design compared to single well locations. At December 31, 2013, we had three drilling rigs running in the
area and a total of 369 gross operated horizontal wells flowing to sales. We recently modified our development plan from
eight wells per section to six wells per section in order to optimize our rate of return and value for each section. Our current
manufacturing process typically involves using three drilling rigs per 640-acre unit to simultaneously drill all wells in the unit,
followed by one to two fracture stimulation fleets to efficiently complete all wells in the unit. As of December 31, 2013, we
had 42 developed units and 37 undeveloped units. Our plans for 2014 are to develop seven of these units which includes
drilling 34 gross (17.3 net) wells.
Shelby area
Our position in the Shelby area consists of 16,600 net acres in San Augustine, Nacogdoches and Shelby Counties, of
which 95% net acres are held-by-production. As of December 31, 2013, we had a total of 70 gross operated horizontal wells
flowing to sales. Our activity in this area has historically consisted of delineating the acreage, establishing infrastructure,
performing technical evaluations, testing different completion designs and evaluating different flowback methodologies. We
suspended our drilling program in this region during 2012 and 2013 in order to focus our resources on the Holly area of the
Haynesville shale. Based on our internal engineering and geological analysis and the recent success of other operators on
offset acreage using enhanced completion methods, we resumed our drilling program in this area during 2014. Additionally,
our ability to reduce drilling and completion costs in the Haynesville shale has significantly improved the economics of
drilling in this area. Our plans for 2014 include drilling 8 gross (3.8 net) wells which will include laterals as long as 7,000 feet,
more proppant per completed lateral foot and more restricted flowback. If the enhanced completion methods are successful on
our acreage, this program will provide attractive economics in the current price environment and provide a growth platform
for future development.
Haynesville shale operating effectiveness
We have focused on improving the efficiency of our drilling and completion operations which has resulted in
significant reductions to our well costs. In DeSoto Parish, our average drilling and completion costs per well decreased to
$7.5 million per well during 2013, as compared to $8.0 million per well during 2012 and $9.5 million per well during 2011.
We continue to achieve improved drilling times per well and we are currently averaging 33 days from spud to rig release for a
typical 16,500 foot Haynesville well in DeSoto Parish. In addition to our success in reducing well costs attributable to
drilling, we are also focused on cost effective and optimized completions. Approximately 40% of our well cost is incurred
during the completion phase. We utilize one to two fracture stimulation fleets and continue to see improved consistency and
efficiencies in our fracturing operations. We design our development program to flow natural gas directly to sales once the
unit is completed. This is possible due to close coordination with our midstream service provider, which installs gathering
lines in concert with our drilling operations in most of our development areas.
Our production operations team is focused on lowering our direct operating costs including water management,
efficient utilization of our personnel, equipment rentals and chemicals. The water management initiatives include establishing
fixed prices per barrel for disposal and connecting additional wells to a piped water disposal system which reduces the amount
of higher cost water disposal by truck. Though 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. The gas
cooler fleet used in our Haynesville program has been significantly reduced in size and in most cases we are using a single
cooler for gas streams from multiple wells for shorter periods of time. We plan to continue to efficiently manage our chemical
programs which will allow us reduce costs by minimizing well intervention work.
We are also focused on several initiatives to enhance and manage our base production. We are installing artificial lift
devices on a number of wells, administering an active foamer injection program and performing coiled tubing and slickline
cleanouts as necessary to enhance base production. We have also lowered the production tubing to a deeper landing point in
the wells to more efficiently unload fluids in the lateral. We are currently conducting a pipeline pressure study to evaluate
well performance in response to a lower pressured system. We are planning to transition a portion of our Holly field to a
7
lower system pressure by isolating a portion of the gathering system that will result in a reduction in line pressure. We are
working closely with our midstream service provider to plan and design the testing program and expect to implement the
project in 2014. We are also planning to perform our first refrac stimulation test in 2014. The test is designed to perform a
second fracture stimulation treatment in an existing well to re-stimulate the shale reservoir near the wellbore. This will
enhance the connection from the reservoir to the wellbore to increase productivity and more effectively produce the resources.
We have a Dallas based operations control center that is manned 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 including 120 producing
wells and undeveloped acreage. Our position in this region includes 47,800 net acres with an option to earn additional net
acres under the terms of a farmout agreement with Chesapeake 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. The total
measured depth of our wells 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 have acquired 3-D seismic data
over a large portion of our acreage to help assess the subsurface potential of the assets.
We drilled 23 gross (3.8 net) wells in the core area of Zavala County between the acquisition date and December 31,
2013. Our drilling was focused on moving to a manufacturing mode using multi-well pads 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. Of the wells we drilled in our core area between the acquisition date and December
31, 2013, we turned-to-sales 7 gross (1.2 net) wells with an average initial production rate of 570 barrels of oil per day. As of
December 31, 2013, our average operated shale oil production was approximately 15,200 gross (6,700 net) barrels of oil per
day from 130 wells.
Our 2014 development plan in the Eagle Ford shale is to drill 90 gross (15.2 net) wells with a five rig program. This
includes 84 gross (14.2 net) horizontal wells in our core area of Zavala County in connection with the KKR Participation
Agreement. We will continue to evaluate the farm-out acreage and plan to drill 6 gross (1.0 net) wells during 2014. We will
utilize one to two fracture stimulation fleets to turn to sales approximately 82 gross (14.3 net) wells during the year. We
expect to drill over 300 wells over approximately four years with our current development plan on 500 foot spacing between
laterals.
Eagle Ford shale operational effectiveness
We have utilized our expertise from other shale developments and have realized significant operational efficiencies in
our recently acquired Eagle Ford assets. We are currently averaging 15 days from spud to rig release and the current average
drilling and completion costs per well are approximately $6.9 million. Additionally, we recently secured a completion contract
that will reduce our fracture stimulation costs compared to the date of the acquisition. New wells typically flow for one year
or more before requiring artificial lift. We installed 21 additional pumping units in late 2013 and we expect to install 90
pumping units in 2014.
We renegotiated our salt water disposal contract which will reduce our disposal costs as compared to such costs in
place on the date of the acquisition. We re-piped and automated flare lines to mitigate downtime due to periodic high line
pressures, and are developing a long term solution to increase capacity of the gathering system for our core area and to align
with our development plan.
Our future plans include the construction and operation of multiple central facilities to reduce transportation costs
and operating expenses. We also plan to construct additional water containment and other facilities to recycle water to source
the completions in the core area. We are currently in the process of designing an electrical distribution network over the core
development area that will provide a more efficient cost structure to operate the field.
8
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 145,000 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, 2,800 net acres are scheduled to expire in 2014. As of December 31, 2013 we operated
a total of 5,801 vertical shallow wells flowing to sales with an average gross production rate of approximately 32 (13.1 net)
Mmcfe per day. As of December 31, 2013 we operated a total of 124 horizontal wells in the Marcellus shale with an average
gross production rate of approximately 179 (49.7 net) Mmcfe per day. Including non-operated volumes, our net production in
the Appalachia region was 64.5 Mmcfe per day as of December 31, 2013.
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
Our 2013 development program was a combination of appraisal and development wells in Northeast Pennsylvania,
which primarily included Sullivan and Lycoming Counties and our Central Pennsylvania area, which includes mainly
Armstrong and Jefferson Counties. Our drilling was focused on holding large, contiguous blocks of prospective acreage while
turning to sales our inventory of wells that were waiting on completion. During 2013, we spud 4 gross (1.7 net) wells and
turned to sales 20 gross (8.0 net) wells. We have reduced 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.
Our 2014 drilling plan includes 2 gross (0.5 net) operated appraisal wells in the Northeast Pennsylvania area. We have been
encouraged by the recent results of our wells turned-to-sales in this region and are currently evaluating our drilling plans
beyond 2014. A significant amount of our acreage is held-by-production, which allows us to control the timing of the
development of this region.
Marcellus shale operational effectiveness
During 2013, we reduced our average costs per well drilled in the Marcellus shale due to engineering design
improvements, operational efficiencies, more developed infrastructure and focused supply chain processes. These wells
included lateral lengths ranging from 3,000 to 6,000 feet. These reductions in costs will allow us to improve the economics of
drilling in this region; however our current strategy for these areas includes appraising and holding large contiguous blocks of
primary term acreage while consolidating our lease positions within these core areas.
Permian Basin
During 2012, we acquired approximately 15,000 prospective net acres with horizontal drilling potential in the
Permian Basin located in Irion County, Texas. During 2013, we sold 50% of this acreage for $37.9 million and the purchaser
agreed to fund our share of drilling and completion costs up to $18.9 million. We formed a joint venture with the purchaser to
develop the acreage in which they are designated as the operator. We also leased an additional 2,000 net acres within the joint
venture area during 2013 adjacent to the original acreage. The joint venture spud 5 gross (2.5 net) horizontal wells during
2013 targeting the Wolfcamp formation, and completed and turned-to-sales 2 gross (1.0 net) of these wells. As of
December 31, 2013, there was approximately $5.1 million remaining under the carry and this is expected to be exhausted
upon completion of the fifth well.
On February 13, 2014, we entered into a purchase and sale agreement with our joint venture partner for the sale of
our interest, including producing wells and undeveloped acreage, for approximately $65.0 million, subject to customary
purchase price adjustments and the receipt of certain third-party consents. The effective date of the transaction will be
January 1, 2014 and any amounts remaining under the drilling carry will be terminated upon closing of the acquisition. The
transaction is expected to close in the first half of 2014.
9
EXCO/HGI Partnership
We formed the EXCO/HGI Partnership during 2013 in which we own a 25.5% economic interest. The primary
strategy of the EXCO/HGI Partnership is to exploit its current asset base and acquire conventional producing oil and natural
gas properties to enhance asset value and cash flow. The EXCO/HGI Partnership’s primary assets include shallow
conventional properties in the East Texas/North Louisiana region and the Permian Basin. The net amounts for the drilling and
production results presented below represent our 25.5% economic interest in the EXCO/HGI Partnership.
Permian
The EXCO/HGI Partnership’s properties in the Permian Basin are located primarily in the Sugg Ranch field in Irion
County, Texas. The production from these properties is primarily from the Canyon Sand formation from depths of 6,700 to
7,900 feet. During the period from inception to December 31, 2013, the partnership drilled and completed 19 gross (4.6 net)
wells in the Sugg Ranch area. Economics for this drilling activity typically have high rates-of-return driven by oil and NGL
content. The partnership expects to run one operated rig intermittently at Sugg Ranch during 2014 targeting the Canyon Sand
formation. At December 31, 2013, production from the 444 operated partnership wells averaged approximately 5.0 gross (1.0
net) Mboe per day. This average production rate consisted of 0.3 net Mbbls of oil, 0.3 net Mmcf of natural gas, and 0.4 net
Mbbls of natural gas liquids per day.
East Texas/North Louisiana
The Vernon Field in Jackson Parish, Louisiana is the most significant producing field in the EXCO/HGI Partnership
and produces from the Cotton Valley and Bossier Sand formations at depths ranging from 12,000 to 15,000 feet. The other
Cotton Valley, Hosston, Travis Peak and Pettet formation properties are located in Caddo and DeSoto Parishes, Louisiana
primarily in four fields including Holly, Kingston, Caspiana, and Longwood, as well as acreage and production in Harrison,
Panola, and Gregg Counties in Texas, primarily across three fields including Carthage, Waskom and Danville. These
producing zones range in depth from 7,800 feet to 11,000 feet. At December 31, 2013, net operated production averaged
approximately 9.9 Mmcfe per day from Vernon Field and approximately 9.0 Mmcfe per day from other fields in East Texas/
North Louisiana. The primary focus in the East Texas/North Louisiana fields is to minimize operating expenses while
maintaining production. The EXCO/HGI Partnership’s capital projects in this region during 2014 will be focused on
recompletions in order to maximize recovery from these assets. In East Texas/North Louisiana, the EXCO/HGI Partnership
currently has 905 operated wells flowing to sales with a total operated production rate of approximately 107 gross (18.9 net)
Mmcfe per day.
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 our shale plays in Texas, Louisiana and Appalachia region.
As of December 31, 2013, we had approximately 70,000 net acres in our East Texas/North Louisiana region for the
Haynesville and Bossier shale formations, 47,800 net acres in our South Texas region for the Eagle Ford shale formation,
145,000 net acres in our Appalachia region prospective for the Marcellus shale formation, all of which are subject to hydraulic
fracturing operations. As of December 31, 2013, a total of 725.1 Bcfe of our Proved Reserves were located in our East Texas/
North Louisiana operating area, of which 724.2 Bcfe of Proved Reserves were associated with our Haynesville and Bossier
shale properties. As of December 31, 2013, a total of 90.6 Bcfe of our Proved Reserves were located in our South Texas
operating area, of which predominantly all of the Proved Reserves were associated with Eagle Ford shale assets. As of
December 31, 2013, a total of 181.1 Bcfe of our Proved Reserves were located in our Appalachia region, of which 126.2 Bcfe
of Proved Reserves were associated with our Marcellus shale properties.
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: Haynesville and Bossier shale formation -
approximately 15-25%; Eagle Ford shale formation - approximately 35-45%; and Marcellus shale formation - approximately
25-35%.
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
10
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, please read “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, 2013 were approximately 1.1 Tcfe, of which approximately 84% were related to
our shale properties. Of our Proved Reserves attributed to shale properties, approximately 77% were located in the
Haynesville/Bossier shale, 13% in the Marcellus shale and 10% in the Eagle Ford shale. Our non-shale Proved Reserves
represented approximately 16% of total Proved Reserves as of December 31, 2013, which consisted primarily of conventional
assets in the Appalachia region and our proportionate share of the conventional assets held by the EXCO/HGI Partnership in
the East Texas/North Louisiana and Permian regions.
The following table summarizes Proved Reserves as of December 31, 2013, 2012, and 2011. This information was
prepared in accordance with the rules and regulations of the SEC.
As of December 31,
2013
2012
2011
Oil (Mbbls)
Developed
Undeveloped
Total
Natural gas (Mmcf)
Developed
Undeveloped
Total
Natural gas liquids (Mbbls) (1)
Developed
Undeveloped
Total
Equivalent reserves (Mmcfe)
Developed
Undeveloped
Total
PV-10 (in millions) (2)
Developed
Undeveloped
Total
Standardized Measure (in millions) (3)
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
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
$
$
$
1,153.5
98.8
1,252.3
1,252.3
$
$
$
11
666.0
30.1
696.1
696.1
$
$
$
4,565
1,789
6,354
955,522
335,942
1,291,464
—
—
—
982,912
346,676
1,329,588
1,545.7
128.0
1,673.7
1,426.5
(1) Beginning in 2012, we began reporting our NGLs separately. In 2011, the NGLs were reported as a component of
(2)
natural gas.
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 NGLs price was computed using the
trailing 12 month average of realized prices.
December 31, 2013
December 31, 2012
December 31, 2011
Average spot prices
Oil (per Bbl)
Natural gas (per Mmbtu)
Natural gas liquid (per Bbl)
$
96.78
$
94.71
96.19
$
3.67
2.76
4.12
39.92
46.57
—
(3)
There is no difference in Standardized Measure and PV-10 for the years ended December 31, 2013 and 2012 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.
The following table provides a reconciliation of our PV-10 to our Standardized Measure as of December 31, 2013, 2012
and 2011:
(in millions)
PV-10
Future income taxes
Discount of future income taxes at 10% per annum
Standardized Measure
As of December 31,
2013
2012
2011
1,252.3
$
696.1
$
—
—
—
—
1,252.3
$
696.1
$
1,673.7
(390.8)
143.6
1,426.5
$
$
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 audit of the Proved Reserves prepared by EXCO's internal engineers.
Our Vice President of Engineering is a registered Professional Engineer with over 35 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, excluding the EXCO/HGI
Partnership after its formation, as of December 31, 2013, 2012 and 2011 have been prepared by Lee Keeling. The estimates of
12
Proved Reserves for the EXCO/HGI Partnership were prepared by Lee Keeling as of September 30, 2013 and updated by our
internal engineers as of December 31, 2013. 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, 2013. Our estimated Proved Reserves and future
net cash flows for our shale properties in all regions except South Texas were prepared by our internal engineers and audited
by NSAI as of December 31, 2013. Our estimated Proved Reserves and future net cash flows for our shale properties as of
December 31, 2012 were prepared by NSAI. Our estimated Proved Reserves and future net cash flows for our shale properties
as of December 31, 2011 were prepared by Haas Petroleum Engineering Services, Inc. Lee Keeling, Haas Petroleum
Engineering Services, Inc., 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. The estimates of future plugging and abandonment costs necessary to compute PV-10 and
Standardized Measure were computed internally.
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 current 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 20. 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.
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, 2013 and changes in our Proved Reserves during
2013. This discussion and analysis should be read in conjunction with “Note 20. 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, 2013 to December 31, 2013.
13
Proved Developed Reserves
Proved Undeveloped Reserves
Total Proved Reserves
The changes in reserves for the year are as follows:
January 1, 2013
Purchases of reserves in place
Discoveries and extensions
Revisions of previous estimates (1):
Reclassification to unproved reserves (2)
Changes in price
Other factors
Sales of reserves in place
Production
December 31, 2013
Oil (Mbbls)
Natural gas
(Mmcf)
Natural gas
liquids (Mbbls)
11,274
4,104
15,378
657,116
359,363
1,016,479
5,570
936,132
16,022
5,960
290,933
46,834
(190)
457
(3,029)
(8,224)
(1,188)
15,378
(1,509)
272,614
(105,186)
(270,018)
(153,321)
1,016,479
2,088
495
2,583
6,639
2,201
513
(196)
686
(545)
(6,472)
(243)
2,583
Equivalent
natural gas
(Mmcfe)
737,291
386,954
1,124,245
1,009,386
400,271
85,672
(3,825)
279,472
(126,630)
(358,194)
(161,907)
1,124,245
(1) Revisions of previous estimates include both reserves in place at the beginning of the year and acquisitions during the
year.
(2) Represents Proved Undeveloped Reserves reclassified to unproved reserves pursuant to the five year development rule
established by the SEC. This reclassification was a result of decisions not to commit development capital to certain
conventional properties held by the EXCO/HGI Partnership in the Permian Basin. While these locations previously
qualified as Proved Undeveloped Reserves as they directly offset a proved location, our planned capital programs do not
support development at this time.
Purchases of reserves in place
Purchases of reserves in place consisted primarily of our acquisition of Haynesville and Eagle Ford assets from
Chesapeake in July 2013. The acquisition in the Haynesville shale primarily added natural gas reserves from both an
incremental working interests in proved developed producing properties and new leases containing proved producing
properties and proved undeveloped locations in our core area of DeSoto Parish, Louisiana. The acquired Haynesville assets
added 260.0 Bcfe of Proved Reserves which consisted solely of natural gas reserves. The acquisition in the Eagle Ford shale
primarily added oil reserves from proved developed producing properties and undeveloped locations that we plan on
developing under a participation agreement with a joint venture partner. The acquired Eagle Ford assets added 115.7 Bcfe of
Proved Reserves which consisted of 83% oil, 8% natural gas and 9% natural gas liquid reserves. In addition, purchases of
reserves in place included 24.6 Bcfe of Proved Reserves for our proportionate share of the EXCO/HGI Partnership's
acquisition of shallow Cotton Valley assets. 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 2013 were 85.7 Bcfe. The additions in the Eagle Ford
shale were 36.5 Bcfe as a result of our development subsequent to the acquisition of these properties. The Marcellus shale
accounted for 33.6 Bcfe of the total additions as a result of our completion activities and limited appraisal drilling program.
The remaining additions included 10.2 Bcfe in the Haynesville shale, 3.9 Bcfe for conventional properties held by the EXCO/
HGI Partnership in the Permian Basin, and 1.5 Bcfe for shale properties in the Permian Basin.
Revisions of previous estimates
Our revisions of previous estimates included upward revisions to our Proved Reserve quantities of 279.5 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 the average of
prices for a trailing 12 month period. This change in price was primarily driven by the increase in the trailing 12 month
average of natural gas prices from $2.76 per Mmbtu for the year-ended December 31, 2012 to $3.67 per Mmbtu for the year
ended December 31, 2013.
14
The upward revisions due to changes in price were partially offset by downward revisions of 126.6 Bcfe in Proved
Reserve quantities due to performance and other factors. These revisions include 91.6 Bcfe from the Haynesville shale assets
due to a combination of operational issues including scaling, liquid loading due to high-line pressure and the impact of
drainage on new wells drilled directly offset to the unit wells. The majority of our Proved Developed Producing wells produce
into a high line pressure system and are showing signs of liquid loading. We have plans to reduce line pressure in the field and
expand our artificial lift program. In addition, most of these wells are drilled on 80 acre spacing with the closest offsets to the
original unit wells showing lower reserves compared to previous estimates. We have modified our spacing program from
eight wells per section to six wells per section in order to optimize our rate of return and value for each section. However,
these planned improvements will not be incorporated into our Proved Reserves until we have the data to support and
objectively quantify these amounts.
Sales of reserves in place
Sales of reserves in place consisted of our contribution of conventional properties to the EXCO/HGI Partnership and
the sale of undeveloped acreage in the Eagle Ford shale to KKR. The properties contributed to the EXCO/HGI Partnership
included Proved Reserves of 327.6 Bcfe (net of our 25.5% proportionate interest) for shallow producing assets in East Texas
and North Louisiana and shallow Canyon Sand and other assets in the Permian Basin of West Texas. The properties sold to
KKR included 30.6 Bcfe of proved undeveloped reserves in the Eagle Ford shale. We retained an interest in these properties
and they will be jointly developed under the KKR Participation Agreement. 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 2013 was 161.9 Bcfe, which included approximately 5.0 Bcfe in production from
extensions and discoveries that were not reflected in our Proved Reserves at January 1, 2013. Also, our production included
approximately 21.7 Bcfe from the Haynesville and Eagle Ford properties that were acquired during the year.
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, 2013:
Proved Undeveloped Reserves at January 1, 2013
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, 2013
Mmcfe
37,130
195,830
(50,932)
46,667
(64,277)
(3,825)
226,361
386,954
(1) Approximately 51% and 30% of the discoveries and extensions of Proved Undeveloped Reserves in 2013 occurred in
the Eagle Ford shale and Marcellus shale, respectively.
(2) Proved Undeveloped Reserves transferred to Proved Developed Reserves in 2013 were primarily in DeSoto Parish.
Capital costs incurred to convert Proved Undeveloped Reserves to Proved Developed Reserves were $72.0 million.
(3) Represents Proved Undeveloped Reserves reclassified to unproved pursuant to the five year development rule
established by the SEC. This reclassification was a result of decisions not to commit development capital to certain
conventional properties held by the EXCO/HGI Partnership in the Permian Basin. While these locations qualify as
Proved Undeveloped Reserves as they directly offset a proved location, our planned capital programs do not support
development at this time.
(4) The upward revisions are due primarily 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.
15
Impacts of changes in reserves on depletion rate and statements of operations in 2013
Our depletion rate decreased to $1.47 per Mcfe in 2013 from $1.52 per Mcfe in 2012. The decrease is primarily the
result of significant ceiling test impairments during 2012, which lowered our depletable base. This was partially offset by an
increase in our depletable base from the acquisition of the Haynesville and Eagle Ford assets and higher future development
costs due to an increase in proved undeveloped reserves resulting from higher natural gas prices. We expect this rate to
increase during 2014 as a result of a higher depletion rate associated with our oil producing assets in the South Texas region
and the downward revisions of reserve quantities to our properties in the Haynesville shale during the fourth quarter of 2013.
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:
Revenue
Production sold (Mbbl)
Average sales price per Bbl
Natural gas liquids:
Revenue
Production sold (Mbbl)
Average sales price per Bbl
Natural gas:
Revenue
Production sold (Mmcf)
Average sales price per Mcf
Costs and Expenses:
Average production costs per Mcfe (excluding severance and ad valorem
taxes)
Year Ended December 31,
2013
2012
2011
$
$
$
$
$
$
$
111,440
1,188
93.80
8,560
243
35.23
514,309
153,321
3.35
$
$
$
$
$
$
62,119
704
88.24
22,068
510
43.27
462,422
182,644
2.53
$
$
$
$
$
$
67,440
741
91.01
29,639
505
58.69
657,122
176,700
3.72
0.38
$
0.41
$
0.46
We had one field that exceeded 15% of our total Proved Reserves as of December 31, 2013. Our Haynesville shale field
represented approximately 65% of our total Proved Reserves. The following table provides additional information related to
our Haynesville shale field:
Haynesville Shale:
Natural gas production sold (Mmcf)
Average price per Mcf
Average production cost per Mcf (excluding severance and ad valorem taxes)
Our interest in productive wells
Year Ended December 31,
2013
2012
2011
120,090
136,910
130,028
$
$
3.39
0.15
2.47
0.12
$
3.64
0.08
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
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.
16
Producing region:
East Texas/North Louisiana
South Texas
Appalachia
Permian and other
EXCO/HGI Partnership
Total
At December 31, 2013
Gross wells (1)
Net wells
Oil
Natural gas
Total
Oil
Natural gas
Total
—
157
330
2
454
943
631
4
5,850
24
1,001
7,510
631
161
6,180
26
1,455
8,453
—
91.0
161.1
1.0
109.6
362.7
226.1
2.1
226.1
93.1
2,645.1
2,806.2
5.7
213.4
6.7
323.0
3,092.4
3,455.1
(1) As of December 31, 2013, we held interests in 2 gross wells with multiple completions.
As of December 31, 2013, we were the operator of 7,863 gross (3,394.6 net) wells, which represented approximately
97.4% 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 recently acquired properties 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, 2013, we had 4 gross (0.9 net) wells being drilled and 21 gross (4.4 net) wells being completed
or awaiting completion.
Year ended December 31, 2013 (1)
Year ended December 31, 2012
Year ended December 31, 2011
Year ended December 31, 2013 (2)
Year ended December 31, 2012
Year ended December 31, 2011
Productive
Gross
Dry
105
169
255
Productive
Gross
Dry
15
6
80
2
2
2
—
—
2
Development wells
Total
Productive
107
171
257
48.7
73.8
116.9
Exploratory wells
Total
Productive
15
6
82
7.7
2.2
26.9
Net
Dry
Net
Dry
0.5
1.9
1.9
—
—
2.0
Total
49.2
75.7
118.8
Total
7.7
2.2
28.9
(1) Our development wells in 2013 included the Haynesville shale in DeSoto Parish and Southern Caddo Parish, Louisiana,
the Eagle Ford shale in our core area in Zavala County, Texas, and the Marcellus shale in Armstrong and Lycoming
Counties in Pennsylvania. Additionally, the EXCO/HGI Partnership's development wells in 2013 included shallow
conventional properties in the Permian Basin. The dry holes drilled during 2013 included shallow conventional
properties held by the EXCO/HGI Partnership in the Permian Basin.
(2) Our exploratory wells in 2013 included certain wells drilled in the Eagle Ford shale under the farmout agreement with
Chesapeake outside of our core area in Zavala County, Texas and certain wells in the Marcellus shale in Jefferson,
Clarion and Sullivan Counties, Pennsylvania.
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
17
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 (1)
Appalachia
Permian and other
Total
At December 31, 2013
Developed
Undeveloped
Gross
Net
Gross
Net
148,100
87,700
376,700
6,200
618,700
70,300
44,300
171,000
4,400
290,000
41,200
9,300
295,800
23,300
369,600
16,700
3,500
119,400
13,800
153,400
EXCO/HGI Partnership (2)
170,000
37,600
9,200
1,800
(1) Our acreage in the South Texas region does not include the undeveloped locations associated with the farmout
agreement with Chesapeake.
(2) The net acreage reported for the EXCO/HGI Partnership represents our 25.5% economic interest. The acreage reported
for the EXCO/HGI Partnership primarily consists of shallow rights in the same acreage for which EXCO owns the deep
rights.
The primary terms of our oil and natural gas leases expire at various dates. Much 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 5,600, 27,500 and 9,600 net acres with
leases expiring in 2014, 2015 and 2016, respectively. Approximately 70% of the scheduled 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 2013, sales to BG Energy Merchants LLC and Chesapeake Energy Marketing Inc. accounted for approximately
48% and 14%, respectively, of 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. The loss of any significant customer may cause
a temporary interruption in sales of, or lower price for, our oil and natural gas. 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
18
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
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. Legislation
affecting the oil and natural gas industry is 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 production 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 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 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 profitability.
19
FERC matters
The availability, terms and cost of downstream transportation significantly affect sales of natural gas, oil and NGLs.
The interstate transportation and sale for resale is subject to federal regulation, including regulation of the terms, conditions and
rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission
("FERC"). Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by
making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory
basis. Federal and state regulations govern the rates and terms for access to intrastate natural gas pipeline transportation, while
states alone regulate gathering activities. With regard to oil and NGLs, the rates and terms and conditions of service for
interstate transportation is regulated by FERC. Tariffs for such transportation must be just and reasonable and not unduly
discriminatory. Oil and NGL 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 certain segments of the physical and futures 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
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.
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
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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
bill 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
regarding pipeline safety. As described in the notice, 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.
U.S. federal taxation
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:
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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 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.
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
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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.
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
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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.
We are unable to assure that more stringent laws and regulations protecting the environment will not be adopted and
that we will not incur material expenses in complying with them in the future. 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.
The EPA has adopted rules that require new major sources and major modifications of GHG to obtain its so-called
GHG “tailoring” rule that will phase in federal prevention of significant deterioration (“PSD”) permits, Major sources of GHG
also have to obtain Title V operating permits. Those rules including the “tailoring” rule which limits the number of GHG
sources subject to these permitting requirements by raising the threshold levels for what constitutes a major source of GHG.
Those permitting provisions, when they become applicable to our operations, could require controls or other measures to
reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. 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. 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.
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 the Company were to have a portion of its 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.
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. Many of our wells would not be
economical without the use of hydraulic fracturing to stimulate production from the well.
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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. 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 with final results expected in 2014. This study remains subject to review. 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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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
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
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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
We are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state
statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of
CERCLA and similar state statutes require that we organize 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 mineral records. We will conduct title
investigations and, in most cases, obtain a title opinion of local counsel 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 exploration failures,
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 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 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 general liability insurance per occurrence limit
is reached.
We also maintain control of well insurance and pollution insurance. Our control of well insurance has per occurrence
and combined single limits ranging from $3 million to $25 million and is subject to a $500,000 deductible per occurrence. Our
pollution insurance has a per occurrence and aggregate annual limit of $30 million and is subject to a $50,000 deductible per
occurrence.
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.
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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 may not cover
fines, penalties or costs and expenses related to government-mandated environmental clean-up responsibilities.
Our employees
As of December 31, 2013, we employed 755 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,” “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 foreign oil, natural gas and natural gas liquids;
future capital requirements and availability of financing;
our ability to meet our current and future debt service obligations;
disruption of credit and capital markets and the ability of financial institutions to honor their commitments;
estimates of reserves and economic assumptions;
geological concentration of our reserves;
risks associated with drilling and operating wells;
exploratory risks, primarily related to our activities in shale formations, including the Eagle Ford shale play in South
Texas;
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 for drilling and hydraulic fracturing activities;
political and economic conditions and events in oil-producing and natural gas-producing countries;
title to our properties;
litigation;
competition;
general economic conditions, including costs associated with drilling and operations of our properties;
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• marketing of oil and natural gas;
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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 stock.
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. 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.
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.
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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.
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.
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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
month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon
future conditions.
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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.
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.
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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, 2013, approximately
90% of our Proved Reserves were natural gas and approximately 95% of our production was natural gas. Historically, oil and
natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market
uncertainty and a variety of additional factors that are beyond our control. Factors that affect the prices we receive for our oil
and natural gas include:
•
•
•
•
•
•
•
•
•
supply and demand for oil and natural gas and expectations regarding supply and demand;
the level of domestic production;
the availability of imported oil and natural gas;
political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes,
continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and
production controls;
the cost and availability of transportation and pipeline systems with adequate capacity;
the cost and availability of other competitive fuels;
fluctuating and seasonal demand for oil, natural gas and refined products;
concerns about global warming or other conservation initiatives and the extent of governmental price controls and
regulation of production;
regional price differentials and quality differentials of oil and natural gas;
the availability of refining capacity;
technological advances affecting oil and natural gas production and consumption;
•
•
•
• weather conditions and natural disasters;
•
•
foreign and domestic government relations; and
overall economic conditions.
In the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. During
2013, the NYMEX price for natural gas fluctuated from a high of $4.46 per Mmbtu to a low of $3.11 per Mmbtu, while the
NYMEX West Texas Intermediate crude oil price ranged from a high of $110.53 per Bbl to a low of $86.68 per Bbl. For the
five years ended December 31, 2013, the NYMEX Henry Hub natural gas price ranged from a high of $6.07 per Mmbtu to a
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 $33.98 per Bbl. On December 31, 2013, the spot market price for natural gas at Henry Hub was $4.23 per Mmbtu, a
26% increase from December 31, 2012. On December 31, 2013, the spot market price for crude oil at Cushing was $98.42 per
Bbl, a 7% increase from December 31, 2012. For 2013, our average realized prices (before the impact of derivative financial
instruments) for oil and natural gas were $93.80 per Bbl and $3.35 per Mcf, respectively, compared with 2012 average realized
prices of $88.24 per Bbl and $2.53 per Mcf, respectively.
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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 in 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 2013, this differential ranged from a high of $21.98 per barrel to a low of $2.20 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 2013 ranged from a high of NYMEX less $0.02 per
Mmbtu to a low of NYMEX less $1.86 per Mmbtu. These differentials vary depending on factors such as supply, demand,
pipeline capacity, infrastructure, and weather.
There are risks associated with our drilling activity that could impact our results of operations and financial condition.
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 used in
our drilling and hydraulic fracturing activities. All of these risks could adversely affect 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.
The results of our drilling in new or emerging formations, including the Eagle Ford shale formation, 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. Further, part of our strategy for the Eagle Ford shale formation
involves the use of horizontal drilling and completion techniques that have been successful in other shale formations. 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.
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.
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
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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 depend on Chesapeake to market our oil and natural gas production in the Eagle Ford shale. If Chesapeake is unable or
otherwise fails to market our Eagle Ford production, our revenues could be adversely affected.
We have entered into marketing agreements with an affiliate of Chesapeake to sell all of the anticipated oil and natural
gas production associated with the acreage we acquired from Chesapeake in the Eagle Ford shale formation. If Chesapeake is
unable or otherwise fails to market the oil and natural gas we produce from the Eagle Ford shale formation, 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 or have a material adverse effect on our business, results of operations or financial
condition.
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.
We conduct a substantial portion of our operations through joint ventures with third parties, principally BG Group, HGI
and 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. In addition, we are required to present opportunities
related to the development of certain conventional assets to the EXCO/HGI Partnership. BG Group also has the right to elect to
participate in all acreage and other acquisitions in defined areas of mutual interest in the Haynesville and Appalachia regions. If
they elect not to participate in a particular transaction or transactions, we would bear the entire cost of the acquisition and all
development costs of the acquired properties.
Such joint venture arrangements may involve risks not otherwise present when exploring and developing properties
directly, including, for example:
•
•
•
•
•
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;
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•
•
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.
We may make significant capital expenditures and be subject to certain legal and financial terms as the result of our joint
ventures with BG Group that could adversely affect us.
We are a party to a joint venture with BG Group covering an undivided 50% interest in a substantial portion of our shale
assets in the East Texas/North Louisiana area including the Haynesville/Bossier shale, or the East Texas/North Louisiana JV.
The East Texas/North Louisiana JV operates as a joint venture pursuant to a joint development agreement under which EXCO
acts as the operator.
We are also party to a joint venture with BG Group covering our Marcellus shale acreage and shallow producing assets
in the Appalachia region ("Appalachia JV"). Pursuant to the agreements governing the Appalachia JV, EXCO and BG Group
agreed to jointly explore and develop their Appalachian properties, particularly the Marcellus shale. EXCO and BG Group each
own a 50% interest in the operating entity that operates the Appalachia JV’s properties subject to oversight from a management
board having equal representation from EXCO and BG Group. In addition, certain midstream assets owned by EXCO and BG
Group are party to a midstream joint venture in Appalachia through which they will pursue the construction and expansion of
gathering systems, pipeline systems and treating facilities for anticipated future production from the Marcellus shale. EXCO
has unconditionally guaranteed its subsidiaries’ performance of the joint venture agreements under the Appalachia joint
ventures.
Each of these joint ventures may require us to make significant capital expenditures. If we do not timely meet our
financial commitments under the respective joint venture agreements, our rights to participate in such joint ventures will be
adversely affected and other parties to the joint ventures may have a right to acquire a share of our interest in such joint
ventures proportionate to, and in satisfaction of, our unmet financial obligations.
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 years ended December 31, 2013 and 2012, we received cash receipts to settle our derivative financial instrument
contracts totaling $42.1 million and $202.1 million, respectively. For the year ended December 31, 2013, 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 $91.9 million. As of December 31, 2013, our oil and natural gas derivative financial instrument
contracts were in the net liability position of $6.5 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
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in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts
remain in place.
To fund the acquisitions of oil and natural gas assets in the Haynesville and Eagle Ford shale formations, we incurred 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.
To finance the acquisitions of the oil and natural gas assets in the Haynesville and Eagle Ford shale formations from
Chesapeake, we entered into the amended EXCO Resources Credit Agreement on July 31, 2013. As of January 31, 2014, the
revolving commitment under the EXCO Resources Credit Agreement had an available borrowing base of approximately $900.0
million, with approximately $491.0 million of outstanding indebtedness and $402.1 million of unused borrowing base, net of
letters of credit.
Our business may not generate sufficient cash flow from operations to enable us to repay our indebtedness, including our
7.5% senior unsecured notes due September 15, 2018 ("2018 Notes") and the EXCO Resources Credit Agreement, to fund
planned capital expenditures and to fund our other liquidity needs. If our cash flow, capital resources and planned asset sales
are insufficient to repay our debt obligations and finance capital expenditure programs, we may be forced to sell additional
assets, issue additional equity or debt securities or restructure our indebtedness. These options may not be available on
commercially reasonable terms, or at all. In addition, the sale of assets or issuance of debt securities would have to be
completed in compliance with the financial and other restrictive covenants in the EXCO Resources Credit Agreement and the
indenture governing the 2018 Notes.
If we cannot make scheduled payments on our indebtedness, we will be in default and holders of the 2018 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. Further, failing to comply with the financial and other restrictive
covenants in the EXCO Resources Credit Agreement or the indenture governing the 2018 Notes could result in an event of
default, which could adversely affect our business, financial condition and results of operations.
If we are unable to complete the joint development of our assets in the Eagle Ford shale formations 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, EXCO will assign half of its undivided 50% interest in such
well to KKR such that KKR will fund and own 75% of each well drilled and EXCO 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 via acquisitions of KKR’s producing properties.
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.
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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 exploration drilling are the main methods of replacing reserves. However,
development and exploration 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.
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.
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. 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.
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. To the extent that we
do not produce and deliver sufficient natural gas production, the requirements to pay for quantities not delivered could have a
material impact on our results of operations and liquidity.
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 products.
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 East Texas/North Louisiana
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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 the Haynesville/Bossier shale plays, 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, the value of our
common stock and our ability to pay dividends on our common stock.
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 stock.
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 Securities and Exchange Commission ("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.
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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 stock.
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 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 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.
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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 2014 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 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 gas companies; increase in the geological and geophysical amortization period for independent producers;
and implementation of a fee on non-producing federal oil and gas leases. 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.
The EPA has adopted GHG rules that require federal prevention of significant deterioration permit requirements for new
sources and modifications, and Title V operating permits for all sources, that have the potential to emit specific quantities of
GHGs. Those permitting provisions could require controls or other measures to reduce GHG emissions from new or modified
sources, and we could incur additional costs to satisfy those requirements. The EPA has also adopted rules establishing 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. We are subject to these rules and the applicable GHG reporting
requirements. Although these rules do not limit the amount of GHGs that can be emitted, they require us to incur costs to
monitor, recordkeep and report GHG emissions associated with our operations.
The adoption of derivatives legislation and regulations thereunder could have an adverse impact on our ability to hedge
risks associated with our business and could affect our business, financial condition or results of operations.
On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act
("Dodd-Frank Act"). The Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives
market and entities that participate in the market and requires the Commodities Future Trading Commission ("CFTC"), federal
regulators of banks and other financial institutions and the SEC to implement the new law by promulgating regulations relating
to derivatives transactions, including the derivatives transactions we use to hedge our exposure to commodity price volatility.
Under the Dodd-Frank Act and related reforms, over-the-counter derivatives dealers and other over-the-counter major market
participants could be subjected to substantial regulatory supervision. The reforms expand the power of the CFTC to regulate
derivatives transactions related to energy commodities, including oil and natural gas, to mandate clearance of derivatives
contracts through registered derivatives clearing organizations and to impose burdensome capital and margin requirements and
business conduct standards on over-the-counter derivatives transactions.
The Dodd-Frank Act also permits the CFTC to set position limits on certain derivatives instruments. In October 2011,
the CFTC issued a rule to implement position limits for certain futures and options contracts on certain commodities and for
swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). Following a challenge
in federal court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives
Association, the CFTC’s rule on position limits was vacated by the U.S. District Court for the District of Columbia in
September 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be
determined necessary and appropriate were satisfied. As a result, such position limits have not yet taken effect, although the
CFTC did issue a new set of proposed position limit rules in November 2013 and has taken the position that the Dodd-Frank
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Act requires the CFTC to impose such position limits. The impact of such regulations upon our business is not yet clear.
Certain of our hedging and trading activities, and those of our counterparties, may be subject to such position limits, which may
reduce our ability to enter into hedging transactions.
The reforms may also require us to comply with margin and clearing and trade-execution requirements in connection
with our derivatives activities, although whether and the extent to which these requirements will apply to our business is
uncertain at this time. Further, the reforms may also require our counterparties to spin off derivatives activities to separate
entities which may not be as creditworthy as the original counterparties.
The full impact of the Dodd-Frank Act and related reforms and regulatory requirements upon our business will not be
known until the regulations are implemented and the market for derivatives contracts has adjusted. If the reforms ultimately
require that we post margin for our hedging activities or require our counterparties to hold margin or maintain required
minimum capital levels, the cost of which could be passed through to us, or impose other requirements that are more
burdensome that current regulations, hedges could become significantly more expensive (including through requirements to
post collateral, which could adversely affect available liquidity), uneconomic or unavailable, which could lead to increased
costs, commodity price volatility, reductions in commodity prices, or any combination of the foregoing. Further, such
developments could reduce our ability to monetize or restructure our existing derivatives contracts, subject us to additional
capital or margin requirements, restrict our flexibility in conducting trading activity and taking commodity positions, and
increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives contracts as a result of the new
requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect
our ability to plan for and fund capital expenditures. In addition, the Dodd-Frank Act was intended, in part, to reduce the
volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity
instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation
and regulations is lower commodity prices. Individually and collectively, these factors could have a material adverse effect on
our ability to hedge risks and on our business, financial condition or results of operations.
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. 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 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 recently been taking action to assert 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 are expected in 2012, with final results expected in 2014. 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 recently 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
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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. 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.
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.
Given the short passage of time between the closing of the acquisition of Haynesville and Eagle Ford assets from
Chesapeake during July 2013 and the required ceiling test computation, we requested, and received, an exemption from the
SEC to exclude these acquired properties from the ceiling test assessments for a period of 12 months following the
corresponding acquisition dates. The request for exemption was made because the ceiling test requires companies using the full
cost accounting method to price period ending Proved Reserves using the simple average spot price for the trailing 12 month
period, which may not be indicative of actual market values. We will assess these acquisitions for impairment during the
requested exemption period. Further, if we cannot demonstrate that fair value exceeds the unamortized carrying costs during the
requested exemption periods prior to issuance of our financial statements, we are required to recognize an impairment.
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 years ended December 31, 2013, 2012, and 2011 we recognized impairments of $108.5 million, $1.3 billion and
$233.2 million, 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.
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, 2013, 2012 and 2011.
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.
We may experience a decline in revenues if we lose one of our significant customers.
For 2013, sales to BG Energy Merchants LLC accounted for approximately 48% of total consolidated revenues. BG
Energy Merchants LLC is a subsidiary of BG Group. In addition, approximately 14% of our total consolidated revenues were
to Chesapeake Energy Marketing Inc. Chesapeake Energy Marketing Inc. is a subsidiary of Chesapeake. The loss of any
significant customer may cause a temporary interruption in sales of, or a lower price for, our oil and natural gas.
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.
If third-party pipelines or other facilities interconnected to our gathering and transportation pipelines become unavailable
to transport or process natural gas, our revenues and cash flow could be adversely affected.
We depend upon third party pipelines and other facilities to provide gathering and transportation. Much of the natural
gas transported by our pipelines must be treated or processed before delivery into a pipeline for natural gas. If the processing
and treating plants to which we deliver natural gas were to become temporarily or permanently unavailable for any reason, or if
throughput were reduced because of testing, line repair, damage to pipelines, reduced operating pressures, lack of capacity or
other causes, our customers would be unable to deliver natural gas to end markets. If any of such events occur, they could
materially and adversely affect our business, results of operations and financial condition.
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We are currently involved in a search for a new chief executive officer and if this search is delayed or if we were to lose the
services of other key personnel, our business could be negatively impacted.
On November 20, 2013, Douglas H. Miller resigned from the positions of chief executive officer, chairman of the board
of directors and as a director. Our board of directors appointed Jeffrey D. Benjamin to serve as non-executive chairman of the
board of directors and initiated a search to identify a new chief executive officer. To the extent there is a 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 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
stock immediately prior to the ownership change multiplied by the long term tax-exempt interest rate, which is published
monthly by the 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,
43
including our chief financial officer and interim 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 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.
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.
Potential physical effects of climate change could adversely affect our operations and cause us to incur significant costs in
preparing for or responding to those effects.
In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect
on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and
quality. If such effects were to occur, our exploration and production operations, including the hydraulic fracturing of our wells,
have the potential to be adversely affected. Potential adverse effects could include disruption of our production activities,
including, for example, damages to our facilities from powerful winds or increases in our costs of operation or reductions in the
efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such effects.
Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting
the transportation or process related services provided by midstream companies, service companies or suppliers with whom we
have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that
may result from potential physical effects of climate change.
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 January 31, 2014 we had approximately $1.5 billion of indebtedness, excluding our proportionate share of
indebtedness for the EXCO/HGI Partnership, including $789.5 million of indebtedness subject to variable interest rates and
$750.0 million of indebtedness under the 2018 Notes. Our total interest expense, excluding amortization of deferred financing
costs and our proportionate share of interest expense for the EXCO/HGI Partnership, on an annual basis based on currently
available interest rates would be approximately $83.0 million and would change by approximately $5.4 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
("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 KKR Participation Agreement), capital expenditures or to meet our operating expenses or other
general corporate obligations;
44
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 levels, 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.
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 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 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. 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.
45
In addition, we conduct certain of our operations through our joint ventures and subsidiaries. Accordingly, repayment of
our indebtedness, including the 2018 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 or our other indebtedness, our joint ventures and subsidiaries do not have any obligation to pay amounts due on the
2018 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 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 stock;
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 specified financial ratios and
satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by
events beyond our control, and, as a result, we may be unable to meet these ratios and financial condition tests. These financial
ratio restrictions and financial condition tests 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 ratios or financial condition tests could result in a default
under the applicable indebtedness. The consolidated funded indebtedness to consolidated EBITDAX ratio, as defined in the
EXCO Resources Credit Agreement, is computed using a trailing 12 month computation. When oil and/or natural gas prices
decline for an extended period of time, our ability to comply with this covenant 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.
46
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 Stock
Our common stock price may fluctuate significantly.
Our common stock trades on the NYSE but an active trading market for our common stock may not be sustained. The
market price of shares of our common stock 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 stock 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
stock. In addition, the stock markets in general can experience considerable price and volume fluctuations.
The equity trading markets may be volatile, which could result in losses for our shareholders.
The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable
pricing of equity securities. The market price of our common stock could change in ways that may or may not be related to our
business, our industry or our operating performance and financial condition.
Our articles of incorporation permits us to issue preferred stock that may restrict a takeover attempt that you may favor.
Our articles of incorporation permit our board to issue up to 10,000,000 shares of preferred stock and to establish by
resolution one or more series of preferred stock and the powers, designations, preferences and participating, optional or other
special rights of each series of preferred stock. The preferred stock may be issued on terms that are unfavorable to the holders
of our common stock, 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 stock to convert their shares into shares of our common stock on terms that are dilutive to holders of our common
stock. The issuance of preferred stock in future offerings may make a takeover or change in control of us more difficult.
We may reduce or discontinue paying our quarterly cash dividend if our board of directors determines that paying a
dividend is no longer appropriate.
We currently have a quarterly cash dividend program on shares of our common stock. Any future dividend payments will
depend on our earnings, capital requirements, financial condition, prospects and other factors that our board of directors may
deem relevant. At any time, our board of directors may decide to reduce or discontinue paying our quarterly cash dividend. If
we do not pay dividends, our common stock may be less valuable because a return on your investment will only occur if our
stock price appreciates. In addition, the EXCO Resources Credit Agreement and the Indenture restrict our ability to pay
dividends.
47
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 stock.
As of January 17, 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
shares of common stock. 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;
•
• any amendment to our articles of incorporation.
the election of members of our board of directors; and
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 shares of our
common stock. 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 shares of common stock 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; Warrendale, Pennsylvania 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
Warrendale, Pennsylvania
Cranberry Township, Pennsylvania
Other
Approximate square
footage
Approximate monthly
payment
Expiration
203,000
56,000
22,300
$
$
$
352,500 December 31, 2015
112,000 October 31, 2016
29,100 December 31, 2014
We have described our oil and natural gas properties, oil and natural gas reserves, acreage, wells, production and drilling
activity in “Item 1. Business” of this Annual Report on Form 10-K.
Item 3.
Legal Proceedings
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.
48
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 stock
Our common stock trades 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 stock as reported by the NYSE:
2013
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2012
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Our shareholders
Price per share
High
Low
Dividends Declared
$
$
$
7.92
8.70
9.00
7.25
10.84
$
8.25
8.14
9.08
$
$
5.97
6.52
6.63
4.83
6.50
5.65
6.58
6.71
0.05
0.05
0.05
0.05
0.04
0.04
0.04
0.04
According to our transfer agent, Continental Stock Transfer & Trust Company, there were 263 holders of record of our
common stock on December 31, 2013 (including nominee holders such as banks and brokerage firms who hold shares for
beneficial holders and the restricted stock shareholders).
Our dividend policy
In 2013, we paid cash dividends of $0.20 per share ($0.05 per quarter) totaling $43.2 million. Any future declaration of
dividends, as well as the establishment of record and payment dates, is subject to limitations under the EXCO Resources
Credit Agreement, the indenture governing the 2018 Notes and the approval of EXCO's board of directors.
Issuer repurchases of common stock
The following table details our repurchases of common stock for the three months ended December 31, 2013:
Period
October 1, 2013 - October 31, 2013
November 1, 2013 - November 30, 2013
December 1, 2013 - December 31, 2013
Total
Total Number of
Shares
Purchased (1)
Average Price
Paid Per Share
Total Number of
Shares
Purchased as
Part of Publicly
Announced Plans
or Programs
Maximum Approximate
Dollar Value of Shares that
May Yet Be Purchased
Under the Plans or
Programs (in millions) (1)
— $
—
—
—
—
—
—
—
— $
—
—
—
192.5
192.5
192.5
(1) On July 19, 2010, we announced a $200.0 million share repurchase program.
49
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.
Selected consolidated financial and operating data
(in thousands, except per share amounts)
Statement of operations data (1):
Revenues:
Oil and natural gas
Midstream (2)
Total revenues
Cost and expenses:
Oil and natural gas production (3)
Midstream operating (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 (4)
(Gain) loss on divestitures and other operating
items (5)
Total cost and expenses
Operating income (loss)
Other income (expense):
Interest expense, net
Gain (loss) on derivative financial instruments
(6)
Other income (expense)
Equity income (loss) (2)
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:
Basic
Diluted
Statement of cash flow data:
Net cash provided by (used in):
35,330
585,835
177,629
35,580
18,960
221,438
Year Ended December 31,
2013
2012
2011
2010
2009
$
634,309
$
546,609
$
754,201
$
515,226
$
550,505
—
—
—
—
634,309
546,609
754,201
515,226
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
—
1,293,579
3,887
83,818
3,652
3,758
104,618
105,114
7,132
99,177
(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
(676,434)
1,177,061
(591,226)
(102,589)
(73,492)
(61,023)
(45,533)
(147,161)
66,133
219,730
146,516
(320)
(828)
(53,280)
(157,017)
22,204
—
969
28,620
22,230
(1,393,285)
—
788
32,706
192,201
22,596
—
$
$
$
$
22,204
$(1,393,285) $
22,596
0.10
0.10
0.20
$
$
$
(6.50) $
0.11
(6.50) $
$
0.16
0.10
0.16
327
16,022
117,332
673,534
1,608
671,926
3.16
3.11
0.14
$
$
$
$
$
$
$
$
232,025
126
(69)
84,921
(506,305)
9,501
(496,804)
(2.35)
(2.35)
0.05
215,011
230,912
214,321
214,321
213,908
216,705
212,465
215,735
211,266
211,266
50
Operating activities
Investing activities
Financing activities
Balance sheet data:
Current assets
Total assets
Current liabilities
Long-term debt
Shareholders' equity
$
350,634
(252,478)
(93,317)
$
514,786
(427,094)
(74,045)
$
428,543
(709,531)
268,756
$
339,921
(712,854)
348,755
$
433,605
1,235,275
(1,657,612)
$
305,854
$
361,866
$
678,008
$
520,460
$
402,088
2,408,628
2,323,732
3,791,587
3,477,420
2,358,894
349,170
237,931
287,399
285,698
212,914
1,858,912
1,848,972
1,887,828
1,588,269
1,196,277
147,905
149,393
1,558,332
1,540,552
859,588
Total liabilities and shareholders' equity
2,408,628
2,323,732
3,791,587
3,477,420
2,358,894
(1) We have completed numerous acquisitions and dispositions which impact the comparability of the selected financial data
between periods.
(2) Prior to the closing of the formation of TGGT on August 14, 2009, we designated our midstream operations as a separate
business segment. Following the formation of TGGT, our midstream operations were accounted for using the equity
method. 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.
(3) 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, $1.0 million and $2.8
million for the years ended December 31, 2011, 2010 and 2009, respectively. We had no share-based compensation
included in oil and natural gas production costs for the years ended December 31, 2013 and 2012.
(4) Share-based compensation calculated pursuant to ASC 718 included in general and administrative expenses was $10.7
million, $8.9 million, $10.9 million, $15.8 million and $16.2 million for the years ended December 31, 2013, 2012, 2011,
2010 and 2009, respectively.
(5) During 2013, we recognized a gain on the contribution of properties to the EXCO/HGI Partnership. During 2010 and
2009, we recognized gains on the sale transactions attributable to the formation of our joint ventures with BG Group.
(6) 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 “Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations-Critical accounting policies-Accounting for
derivatives” for a description of this accounting method.
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 enhancing financial
flexibility. We believe this will allow us to create long-term value for our shareholders.
Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines.
We attempt to offset the impact of this natural decline by implementing drilling and exploitation projects to identify and
develop additional reserves and adding reserves through complementary acquisitions.
51
Recent developments
EXCO/HGI Partnership
On February 14, 2013, we formed the EXCO/HGI Partnership with HGI. Pursuant to the agreements governing the
transaction, we contributed our conventional non-shale assets in East Texas and North Louisiana and our shallow Canyon Sand
and other assets in the Permian Basin of West Texas to the EXCO/HGI Partnership in exchange for net proceeds of $574.8
million, after final purchase price adjustments, and a 25.5% economic interest in the EXCO/HGI Partnership. HGI's economic
interest in the EXCO/HGI Partnership is 74.5%. The primary strategy of the EXCO/HGI Partnership is to exploit its current
asset base and acquire conventional producing oil and natural gas properties to enhance asset value and cash flow. Proceeds
from the formation of the EXCO/HGI Partnership were used to reduce our outstanding indebtedness under the EXCO
Resources Credit Agreement.
Immediately following the closing, the EXCO/HGI Partnership entered into an agreement to purchase the remaining
shallow Cotton Valley assets within our joint venture with 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 the EXCO/HGI Partnership. The transaction closed on March 5, 2013 and was funded with borrowings from the
EXCO/HGI Partnership Credit Agreement.
Haynesville and Eagle Ford Acquisitions
In July 2013, we closed the acquisition of oil and natural gas assets in the Haynesville and Eagle Ford shale formations
from Chesapeake for an aggregate purchase price of $942.9 million, after final purchase price adjustments ("Chesapeake
Properties").
We amended and restated the EXCO Resources Credit Agreement to facilitate these acquisitions, which increased the
borrowing base to $1.6 billion, including a $1.3 billion revolving commitment and a $300.0 million term loan. The credit
agreement included an asset sale requirement of $400.0 million, which was reduced to $28.9 million as of December 31, 2013
using proceeds from asset sales. The asset sale requirement was eliminated as a result of the repayment of outstanding
borrowings in January 2014. The repayments of indebtedness under asset sale requirement resulted in a corresponding
reduction in our borrowing base. See further discussion of the EXCO Resources Credit Agreement within "Note 6. Debt" in the
Notes to our Consolidated Financial Statements.
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 was funded with borrowings from the EXCO Resources Credit Agreement. 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 include operated
interests in 120 wells on approximately 53,500 net acres. The acquisition added approximately 300 identified drilling locations
to our drilling inventory. 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.
In connection with closing the acquisition of the Eagle Ford assets, we entered into a participation agreement with KKR,
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 KKR Participation Agreement were used to reduce
outstanding borrowings under the asset sale requirement of the EXCO Resources Credit Agreement, which also resulted in a
corresponding reduction in our borrowing base.
The KKR Participation Agreement provides that EXCO and KKR will jointly fund future costs to develop the Eagle
Ford assets. With respect to each well drilled, EXCO will assign half of its undivided 50% interest in such well to KKR such
that KKR will fund and own 75% of each well drilled and EXCO will fund and own 25% of each well drilled. On a quarterly
basis, EXCO and KKR will determine the development plan covering the following 12 months. EXCO will be required to
52
offer to purchase KKR's 75% working interest in wells drilled that have been on production for one year. These offers will be
made on a quarterly basis for groups of wells at a price defined in the KKR Participation Agreement, subject to specific well
criteria and return hurdles. We are required to make our first offer during the first quarter of 2015 for wells that have been on-
line for approximately one year. The parties have agreed on a minimum of 240 identified locations to be drilled over a five
year period.
TGGT Transaction
On November 15, 2013, EXCO and BG Group closed the conveyance of 100% of the equity interests in TGGT to Azure
for an aggregate sales price of approximately $910.0 million, subject to customary purchase price adjustments. The
consideration consisted of approximately $876.5 million in cash and an equity interest in Azure which was split equally
between EXCO and BG Group. The equity interest issued to EXCO was approximately 4% of the total outstanding equity
interests of Azure as of the closing date. EXCO and BG Group were granted an option for a period of one year to acquire an
additional equity interest in Azure equal to the equity interest issued at closing for approximately $16.8 million plus a premium
that will increase over time. We received $240.2 million in net cash proceeds at the closing of the transaction.
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 per 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 utilized the cash proceeds from the sale of TGGT to reduce outstanding borrowings under the asset sale requirement
of the EXCO Resources Credit Agreement, which also resulted in a corresponding reduction in our borrowing base. There was
$28.9 million outstanding under the asset sale requirement after the repayment of indebtedness using proceeds from the TGGT
transaction. We recorded an other than temporary impairment of $86.8 million to our investment in TGGT during the year
ended December 31, 2013 as a result of the carrying value exceeding the fair value.
Management Change
Douglas H. Miller resigned from serving as our chief executive officer, chairman of the board of directors and as a
director on November 20, 2013. Our board of directors appointed Jeffrey D. Benjamin to serve as non-executive chairman of
the board of directors and initiated a search to identify a new chief executive officer.
Rights Offering
On December 19, 2013, the Company granted subscription rights to holders of common stock 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 ("Rights Offering").
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 stock 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 common stock
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 common stock. 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 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 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. 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
53
outstanding common shares as of January 17, 2014. We used the proceeds to pay the remaining indebtedness related to the asset
sale requirement as well as a portion of the indebtedness outstanding under the revolving commitment under the EXCO
Resources Credit Agreement. Upon repayment of the asset sale requirement, the interest rate on the revolving commitment
decreased by 100 basis points. After giving effect to the Rights Offering and the related transactions under the Investment
Agreements, the available borrowing base on the revolving commitment under the EXCO Resources Credit Agreement was
$900.0 million with approximately $491.0 million of outstanding indebtedness and approximately $402.1 million of unused
borrowing base, net of letters of credit.
Critical accounting policies
In response to the SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting
Policies,” 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, accounting for derivatives, business combinations, share-based compensation, oil and natural gas properties,
goodwill, revenue recognition, asset retirement obligations and income taxes.
We prepared our consolidated financial statements for inclusion in this report in accordance with GAAP. GAAP
represents a comprehensive set of accounting and disclosure rules and requirements, and applying these rules and requirements
requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP
alternatives. The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent
in our application of GAAP.
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
54
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 in connection with our acquisitions. These derivative financial instruments are not held for trading
purposes. We do not designate our derivative financial instruments as hedging instruments and, as a result, we recognize the
change in the derivative's fair value as a component of current earnings.
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. We recognize
expense on a straight-line basis over the vesting period of the share-based compensation. EXCO uses the full cost method to
account for its oil and natural gas properties. As a result, we capitalize part of our share-based compensation that is attributable
to our acquisition, exploration, exploitation and development activities. Total share-based compensation for the year ended
December 31, 2013 was $18.0 million, of which $7.3 million was capitalized as part of our oil and natural gas properties. For
the years ended December 31, 2012 and 2011, a total of $16.4 million and $17.4 million, respectively, of share-based
compensation was incurred, of which $7.5 million and $6.4 million, respectively, was capitalized.
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, which include unproved oil and natural gas properties, properties under development, and major
development projects, collectively totaled $425.3 million and $470.0 million as of December 31, 2013 and 2012, 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 impaired approximately $1.0 million and $60.8 million of undeveloped properties during 2013 and 2012,
respectively, which were transferred to the depletable portion of the full cost pool during each year. The impairment was
recorded to reflect their estimated market price which included certain properties that were no longer part of our drilling plans.
There were no impairments of undeveloped properties during the year ended December 31, 2011.
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, a ceiling test impairment of oil and natural gas
properties is required. 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 average prices as prescribed by the SEC Release No. 33-8995, less estimated
55
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, 2013, the trailing 12 month reference prices were $3.67 per Mmbtu for
natural gas at Henry Hub and $96.78 per Bbl of oil for West Texas Intermediate ("WTI") at Cushing, Oklahoma. The price
used for NGL's was $39.92 per Bbl and was based on average realized prices in 2013. Each of the reference prices for oil,
natural gas and NGLs are further adjusted for quality factors and regional differentials to derive estimated future net revenues.
Under full cost accounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in
subsequent periods. Since we do not designate our derivative financial instruments as hedging instruments, we are not allowed
to use the impacts of the derivative financial instruments in our ceiling test computations.
As of December 31, 2013 pursuant to Rule 4-10(c)(4) of Regulation S-X, we were required to compute the ceiling test
using the simple average spot price for the trailing 12 month period for oil and natural gas. The computation resulted in the
carrying costs of our unamortized proved oil and natural gas properties, exceeding the December 31, 2013 ceiling test
limitation by approximately $156.6 million, including the recently acquired Chesapeake Properties. Our pricing for the
acquisitions of the Chesapeake Properties was based on models which incorporate, among other things, market prices based on
NYMEX futures as of the acquisition date. The ceiling test requires companies using the full cost accounting method to price
period ending proved reserves using the simple average spot price for the trailing 12 month period, which may not be indicative
of actual market values. Given the short passage of time between closing of these acquisitions and the required ceiling test
computation, the Company requested, and received, an exemption from the SEC to exclude the acquisition of the Chesapeake
Properties from the ceiling test assessments for a period of 12 months following the corresponding acquisition dates.
If we cannot demonstrate the fair value of the Chesapeake Properties exceeds the unamortized carrying costs during the
requested exemption periods prior to issuance of our financial statements, we are required to recognize an impairment. We
evaluated the Chesapeake Properties for impairment using discounted cash flow models based on internally generated oil and
natural gas reserves as of December 31, 2013. The Company's expectation of future prices is principally based on NYMEX
futures contracts, adjusted for basis differentials. We believe the NYMEX futures contract reflects an independent pricing point
for determining fair value.
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 years ended December 31, 2013, 2012, and 2011 we recognized impairments of $108.5 million, $1.3 billion, and
$233.2 million, respectively, to our proved oil and natural gas properties.
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. As a result of
testing, the fair value of our business exceeded the carrying value of net assets and we did not record an impairment charge for
the periods ended December 31, 2013, 2012 and 2011.
The contribution of oil and natural gas properties to the EXCO/HGI Partnership resulted in a significant alteration in our
depletion rate. 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. The balance of goodwill as of December 31,
2013 and 2012 was $163.2 million and $218.3 million, respectively.
56
Revenue recognition and natural 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, 2013, 2012 and 2011 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. Upon initial recognition of a liability, that cost should be capitalized as part of the related
long-lived asset and allocated to expense over the useful life of the asset. The costs of plugging and abandoning oil and natural
gas properties fluctuate with costs associated with the industry. 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. We must make certain estimates related to
the reversal of temporary differences, and actual results could vary from those estimates. 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 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.
57
Our results of operations
A summary of key financial data for the years ended December 31, 2013, 2012 and 2011 related to our results of
operations is presented below:
(dollars in thousands, except per unit prices)
2013
2012
2011
2013-2012
2012-2011
Year Ended December 31,
Year to year change
Production:
Oil (Mbbls)
Natural gas liquids (Mbbls)
Natural gas (Mmcf)
Total production (Mmcfe) (1)
Average daily production (Mmcfe)
1,188
243
153,321
161,907
444
704
510
182,644
189,928
519
741
505
176,700
184,176
505
484
(267)
(29,323)
(28,021)
(75)
(37)
5
5,944
5,752
14
Revenues before derivative financial instrument activities:
Oil
Natural gas liquids
Natural gas
Total revenues
$
$
111,440
$
62,119
$
67,440
$
49,321
$
8,560
514,309
22,068
462,422
29,639
657,122
(13,508)
51,887
634,309
$
546,609
$
754,201
$
87,700
$
(5,321)
(7,571)
(194,700)
(207,592)
Oil and natural gas derivative financial instruments:
Gain (loss) on derivative financial
instruments
$
(320) $
66,133
$
219,730
$
(66,453) $
(153,597)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)
$
93.80
$
88.24
$
91.01
$
5.56
$
Natural gas liquids (per Bbl)
Natural gas (per Mcf)
Natural gas equivalent (per Mcfe)
Costs and expenses:
35.23
3.35
3.92
43.27
2.53
2.88
58.69
3.72
4.10
(8.04)
0.82
1.04
Oil and natural gas operating costs
$
61,277
$
77,127
$
84,766
$
(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
21,971
100,645
237,899
7,876
91,878
102,589
$
0.38
0.14
0.62
1.47
0.05
0.57
27,483
102,875
288,401
14,755
83,818
73,492
$
0.41
0.14
0.54
1.52
0.08
0.44
23,875
86,881
344,947
18,009
104,618
61,023
0.46
0.13
0.47
1.87
0.10
0.57
(5,512)
(2,230)
(50,502)
(6,879)
8,060
29,097
$
(0.03) $
—
0.08
(0.05)
(0.03)
0.13
(2.77)
(15.42)
(1.19)
(1.22)
(7,639)
3,608
15,994
(56,546)
(3,254)
(20,800)
12,469
(0.05)
0.01
0.07
(0.35)
(0.02)
(0.13)
Net income (loss)
$
22,204
$
(1,393,285) $
22,596
$
1,415,489
$
(1,415,881)
(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 $10.7 million, $8.9 million and
$10.9 million for the years ended December 31, 2013, 2012 and 2011, respectively.
The following is a discussion of our financial condition and results of operations for the years ended December 31,
2013, 2012 and 2011.
The comparability of our results of operations for 2013, 2012 and 2011 was affected by:
58
•
•
•
•
the acquisitions of the Haynesville and Eagle Ford assets from Chesapeake during 2013, including the debt
refinancing to facilitate these acquisitions;
the formation of the EXCO/HGI Partnership during 2013;
the sale of our equity interest in TGGT during 2013;
fluctuations in oil, natural gas and NGLs 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, 2012 and 2011;
the Chief transaction, the Appalachia transaction and the Haynesville shale acquisition in 2011;
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 the amount of our debt.
•
General
The availability of a ready market and the prices for oil, natural gas and NGLs are dependent upon a number of factors
that are beyond our control. These factors include, among other things:
•
•
•
•
•
•
•
•
•
•
•
•
the level of domestic production and economic activity;
the domestic oversupply of natural gas;
the inability to export domestic oil and natural gas;
the level of domestic and industrial demand for natural gas for utilities and manufacturing operations;
the available capacity at natural gas storage facilities and quantities of inventories in storage;
the availability of imported oil and natural gas;
actions taken by foreign oil producing nations;
the cost and availability of natural gas pipelines with adequate capacity and other transportation facilities;
the cost and availability of other competitive fuels;
fluctuating and seasonal demand for oil, natural gas and refined products;
the extent of governmental regulation and taxation (under both present and future legislation) of the exploration,
production, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and substitute
fuels; and
trends in fuel use and government regulations that encourage less fuel use and encourage or mandate alternative
fuel use.
Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined
petroleum products, we cannot accurately predict the prices or marketability of oil and natural gas from any producing well in
which we have or may acquire an interest.
Marketing arrangements
We produce oil, natural gas and natural gas liquids. We do not refine or process the oil, natural gas or natural gas liquids
we produce. We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The majority
of our 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
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
59
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 natural gas
liquids 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 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.
Summary
For the years ended December 31, 2013, 2012 and 2011, we reported net income of $22.2 million, a net loss of $1.4
billion and net income of $22.6 million, respectively. The net income for the year ended December 31, 2013 was primarily the
result of income from operations and the gain on the divestiture of certain oil and natural gas properties and related assets in
connection with the formation of the EXCO/HGI Partnership. This was partially offset by the impairments of our oil and natural
gas properties and our investment in TGGT. The net loss for 2012 was primarily the result of impairments of our oil and natural
gas properties as well as lower revenues, both of which were the result of significant declines in natural gas prices in 2012. The
net income for 2011 was the result of increased revenues due to higher natural gas prices and gains on derivative financial
instruments, which were partially offset by impairments of our oil and natural gas properties.
Average natural gas equivalent prices for the year ended December 31, 2013 were $3.92 per Mcfe, compared with an
average natural gas equivalent price of $2.88 per Mcfe for 2012 and $4.10 per Mcfe for 2011.
We use oil and natural gas swap, basis swap and call option contracts to manage our exposure to commodity price
fluctuations, protect our returns on investments and achieve a more predictable cash flow from our operations. The realized and
unrealized changes in the fair value of derivative financial instruments resulted in net losses of $0.3 million for the year ended
December 31, 2013 and net gains of $66.1 million and $219.7 million for the years ended December 31, 2012, and 2011,
respectively.
Presentation of results of operations
Our discussion of production, revenues and direct operating expenses is based on our producing regions and the EXCO/
HGI Partnership. The EXCO/HGI Partnership includes conventional non-shale assets in East Texas, North Louisiana and the
Permian Basin. Prior to the formation of the EXCO/HGI Partnership on February 14, 2013, the operating results of the
properties contributed by EXCO were included within the "East Texas/North Louisiana" and "Permian and other" regions
within our discussion of production, revenues and direct operating expenses. The operating results of the EXCO/HGI
Partnership represent our proportionate interest subsequent to its formation on February 14, 2013.
We closed the acquisition of Haynesville and Eagle Ford assets from Chesapeake on July 12, 2013 and July 31, 2013,
respectively. Our results of operations reflect these assets subsequent to the closing dates of the respective acquisitions. The
Haynesville assets are included within our "East Texas/North Louisiana" region, and the Eagle Ford assets are included within
our "South Texas" region.
Oil and natural gas production, revenues and prices
We are presenting information on a pro forma basis to provide a more meaningful analysis of our on-going production
activity as a result of the formation of the EXCO/HGI Partnership and our recent acquisitions of the Chesapeake Properties.
These pro forma adjustments reflect the contribution of properties by EXCO in connection with the formation of the EXCO/
HGI Partnership, the EXCO/HGI Partnership's acquisition of shallow Cotton Valley assets from an affiliate of BG Group, and
the acquisition of the Chesapeake Properties. The pro forma adjustments reflect our production as if the aforementioned
transactions had occurred on January 1, 2011.
60
(in Mmcfe)
Producing region:
East Texas/North Louisiana
South Texas
Appalachia
Permian and other
EXCO/HGI Partnership
Total
(in Mmcfe)
Producing region:
East Texas/North Louisiana
South Texas
Appalachia
Permian and other
EXCO/HGI Partnership
Total
(in Mmcfe)
Producing region:
East Texas/North Louisiana
South Texas
Appalachia
Permian and other
EXCO/HGI Partnership
Total
Year Ended December 31, 2013
Production
EXCO/HGI pro
forma adjustments
Chesapeake
Properties pro
forma adjustments
Pro forma
production
123,218
6,197
22,816
1,139
8,537
161,907
(3,094)
—
—
(972)
1,361
(2,705)
20,031
7,248
—
—
—
27,279
140,155
13,445
22,816
167
9,898
186,481
Year Ended December 31, 2012
Production
EXCO/HGI pro
forma adjustments
Chesapeake
Properties pro
forma adjustments
Pro forma
production
164,779
—
16,153
8,996
—
189,928
(27,811)
—
—
(8,830)
11,564
(25,077)
38,004
8,410
—
—
—
46,414
174,972
8,410
16,153
166
11,564
211,265
Year Ended December 31, 2011
Production
EXCO/HGI pro
forma adjustments
Chesapeake
Properties pro
forma adjustments
Pro forma
production
162,693
—
12,408
9,075
—
184,176
(31,485)
—
—
(5,562)
17,767
(19,280)
26,053
2,107
—
—
—
28,160
157,261
2,107
12,408
3,513
17,767
193,056
The following table 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
Permian and other
EXCO/HGI Partnership
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
61
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 the EXCO/HGI
Partnership 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 Haynesville assets acquired from Chesapeake. During the year ended December 31,
2013, we operated an average of three horizontal rigs in the East Texas/North Louisiana region, as compared to an average of
eight rigs during the year ended December 31, 2012. Additionally, there was a large inventory of wells that were waiting on
completion at the end of 2011 that were completed and turned-to-sales during the 2012 fiscal year. This resulted in 84 wells
turned-to-sales during 2012 compared to 51 wells turned-to-sales during 2013. 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 natural gas liquids 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 the EXCO/HGI Partnership. Our proportionate share of the EXCO/HGI Partnership'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
the Chesapeake Properties, which was partially offset by lower revenues arising from the contribution of properties to the
EXCO/HGI Partnership and normal production declines. Our average natural gas sales price increased 32.4% 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. Also, our average sales price for natural gas in 2013 was negatively impacted by lower prices received
from our purchasers for natural gas production in the South Texas region due to higher deductions for gathering and
transportation costs. Our average sales price of oil per Bbl increased 6.3% 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 for oil in the South Texas region is
most closely correlated to the Louisiana Light Sweet ("LLS") price index. LLS prices have historically traded at a premium to
WTI, however this differential narrowed during 2013. Our average sales price of natural gas liquids per Bbl decreased 18.6%
to $35.23 per Bbl for the year ended December 31, 2013 from $43.27 per Bbl for the year ended December 31, 2012.
Our production volumes in shale operations are impacted by curtailed volumes of oil and natural gas due to operational
requirements associated with drilling, fracture stimulation and other operations on nearby horizontal wells, seasonal supply and
demand conditions from end users and general maintenance and repairs to our wells. While these curtailed volumes are
typically for short periods of time, they may have impacts to our revenues, cash flows and results of operations.
The following table and discussion presents our production, revenue and average sales prices for the years ended
December 31, 2012 and 2011:
Year Ended December 31,
2012
2011
Year to year change
(dollars in thousands, except
per unit rate)
Production
(Mmcfe)
Revenue
$/Mcfe
Production
(Mmcfe)
Revenue
$/Mcfe
Production
(Mmcfe)
Revenue
$/Mcfe
Producing region:
East Texas/North
Louisiana
South Texas
Appalachia
Permian and other
EXCO/HGI Partnership
164,779
$ 420,579
$ 2.55
162,693
$ 608,218
$ 3.74
2,086
$ (187,639) $ (1.19)
—
16,153
8,996
—
—
47,379
78,651
—
—
2.93
8.74
—
—
12,408
9,075
—
—
52,319
93,664
—
—
4.22
10.32
—
—
3,745
(79)
—
—
(4,940)
(15,013)
—
—
(1.29)
(1.58)
—
Total
189,928
$ 546,609
$ 2.88
184,176
$ 754,201
$ 4.10
5,752
$ (207,592) $ (1.22)
Production in our East Texas/North Louisiana region for the year ended December 31, 2012 increased by 2.1 Bcfe from
2011. This increase is the result of the continued development of our shale assets in this region during 2011 and 2012.
This increase was partially offset by normal production declines of 4.8 Bcfe in our Vernon Field and other shallow conventional
wells in the region. The increase in Appalachia area is the result of the horizontal drilling program in the Marcellus shale. Our
production in the Permian Basin remained flat as a result of a continued one drilling rig program focused on conventional
assets.
62
For the year ended December 31, 2012, oil and natural gas revenues were $546.6 million, a 27.5% decrease from the oil
and natural gas revenues of $754.2 million for the year ended December 31, 2011. The decrease in revenues is primarily a result
of declines in the realized prices of oil, natural gas and NGLs, which were partially offset by increases in production. The
average sales price of oil decreased 3.0% to $88.24 per Bbl for the year ended December 31, 2012 from $91.01 per Bbl for the
year ended December 31, 2011. The average sales price of NGLs decreased 26.3% to $43.27 per Bbl for the year
ended December 31, 2012 from $58.69 per Bbl for the year ended December 31, 2011. The average sales price of natural gas
decreased 32.0% to $2.53 per Mcf for the year ended December 31, 2012 as compared to $3.72 per Mcf for the year
ended December 31, 2011.
The prices received for our oil and natural gas production are largely a function of market supply and demand. Demand
is impacted by general economic conditions, estimates of oil and natural gas in storage, weather and other seasonal conditions.
Market conditions involving over or under supply of oil or natural gas can result in substantial price volatility. Historically,
commodity prices have been volatile and we expect the volatility to continue in the future. Changes in oil and natural gas prices
have a significant impact on our oil and natural gas revenues, cash flows, quantities of estimated Proved Reserves and related
liquidity. Assuming our year ended December 31, 2013 average production levels remain constant, a change in the average sales
price of $0.10 per Mcf of natural gas sold would result in an increase or decrease in revenues and cash flows of approximately
$15.3 million, a change in the average sales price of $1.00 per Bbl of NGLs would result in an increase or decrease in revenues
and cash flows of approximately $0.2 million and a change in the average sales price of $1.00 per Bbl of oil sold would result in
an increase or decrease in revenues and cash flow of approximately $1.2 million, without considering the effects of derivative
financial instruments.
Oil and natural gas operating costs
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 the EXCO/HGI Partnership. 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 the Chesapeake Properties.
As shown in the tables below, oil and natural gas operating costs for the year ended December 31, 2013 were $0.38 per
Mcfe, a decrease of 7.3% from 2012. The net decrease in oil and natural gas operating costs per Mcfe is attributable to the
contribution of properties to EXCO/HGI Partnership, 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.
63
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
Permian and other
EXCO/HGI Partnership
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
$
$
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)
(per Mcfe)
Producing region:
East Texas/North
Louisiana
South Texas
Appalachia
Permian and other
EXCO/HGI Partnership
Total
Our oil and natural gas operating costs for the year ended December 31, 2012 and 2011 were $77.1 million and $84.8
million, respectively. The decrease in total oil and natural gas operating expenses for 2012 as compared to 2011 was primarily
due to the implementation of cost saving initiatives throughout our organization. Examples of these actions include shutting in
marginal producing wells with high-cost water production, decreased compression expenditures and modification of our
chemical treating programs.
As shown in the tables below, on a per Mcfe basis, oil and natural gas operating costs for 2012 decreased by $0.05 per
Mcfe from 2011. The net decreases in both our East Texas/North Louisiana and Appalachia regions were primarily due to the
combination of increased production in 2012 and implementation of numerous cost savings initiatives. The Permian Basin
operating expenses per Mcfe increased due to higher field maintenance and general service costs associated with oil and NGL
production in 2012.
64
Year Ended December 31,
2012
2011
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
$ 39,897
$
9,497
$ 49,394
$ 46,915
$ 10,282
$ 57,197
$ (7,018) $
(785) $
(7,803)
—
14,882
12,539
—
—
—
312
—
—
14,882
12,851
—
—
15,733
11,491
—
—
—
345
—
—
15,733
11,836
—
—
(851)
1,048
—
—
—
(33)
—
—
(851)
1,015
—
(in thousands)
Producing region:
East Texas/North
Louisiana
South Texas
Appalachia
Permian and other
EXCO/HGI Partnership
Total
$ 67,318
$
9,809
$ 77,127
$ 74,139
$ 10,627
$ 84,766
$ (6,821) $
(818) $
(7,639)
Year Ended December 31,
2012
2011
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
$
0.24
$
0.06
$
0.30
$
0.29
$
0.06
$
0.35
$
(0.05) $
— $
—
0.92
1.39
—
—
—
0.03
—
—
0.92
1.42
—
—
1.27
1.27
—
—
—
0.04
—
—
1.27
1.31
—
—
(0.35)
0.12
—
—
—
(0.01)
—
(0.05)
—
(0.35)
0.11
—
(per Mcfe)
Producing region:
East Texas/North
Louisiana
South Texas
Appalachia
Permian and other
EXCO/HGI Partnership
Total
$
0.36
$
0.05
$
0.41
$
0.40
$
0.06
$
0.46
$
(0.04) $
(0.01) $
(0.05)
Gathering and transportation
We report gathering and transportation costs in accordance with FASB ASC 605-45, Revenue Recognition. 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
contain revenues which are reported under two separate bases. 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 and $86.9 million, or $0.47 per Mcfe for the year ended December 31, 2011. The increases in gathering and
transportation expense on a per Mcfe basis from 2011 to 2013 were primarily due to higher costs associated with unused firm
transportation volumes.
We have entered into firm transportation agreements with pipeline companies to facilitate sales of our Haynesville
production and report these firm transportation costs as a component of gathering and transportation expenses. At the end of
2013, our firm transportation agreements covered an average of 1.1 Bcf per day through 2016, with average minimum gathering
and transportation expenses of approximately $135.3 million per year. For the years 2017 through 2021, our firm transportation
agreements range from covering an average of 1.0 Bcf per day in 2017 and trend down to 333 Mmcf per day in 2021, with
average annual minimum gathering and transportation expenses ranging from approximately $132.9 million per year in 2017
and trending down to $40.7 million in 2021. These volumes and expenses represent our gross commitments under these
contracts and a portion of these costs will be incurred by all working interest owners.
65
Production and ad valorem taxes
(in thousands, except per unit
rate)
Producing region:
East Texas/North
Louisiana
South Texas
Appalachia
Permian and other
EXCO/HGI Partnership
Production
and ad
valorem
taxes
$
9,287
4,962
2,653
815
4,254
Year Ended December 31,
2013
2012
2011
% of
revenue
Taxes $/
Mcfe
Production
and ad
valorem
taxes
% of
revenue
Taxes $/
Mcfe
Production
and ad
valorem
taxes
% of
revenue
Taxes $/
Mcfe
2.2% $
0.08
$
17,501
4.2% $
0.11
$
14,851
2.4% $
0.09
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
—
—
1,694
7,330
—
—%
3.2%
7.8%
—%
—
0.14
0.81
—
Total
$
21,971
3.5% $
0.14
$
27,483
5.0% $
0.14
$
23,875
3.2% $
0.13
Production and ad valorem taxes were $22.0 million, $27.5 million and $23.9 million for the years ended 2013, 2012,
and 2011, respectively. 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 the EXCO/HGI Partnership and the decrease in the State of
Louisiana severance tax rate to $0.118 per Mcf in July 2013 for wells that did not have a severance tax holiday. These decreases
were partially offset by higher production and ad valorem taxes associated with our liquids production in the South Texas
region. The increase for the year ended December 31, 2012 compared to 2011 was primarily attributable to higher production
volumes, higher ad valorem taxes based on our continued development in the Haynesville shale, and the enactment of the
Pennsylvania impact fee. This increase was partially offset by the decrease in the State of Louisiana severance tax rate from
$0.164 to $0.148 per Mcf in July 2012 for wells that did not have a severance tax holiday.
Production and ad valorem tax rates per Mcfe were $0.14, $0.14 and $0.13 for 2013, 2012 and 2011, respectively. The
rate per Mcfe stayed consistent on a consolidated basis for the year ended December 31, 2013 compared 2012, however there
were offsetting fluctuations amongst our producing regions. The rate per Mcfe in the East Texas/North Louisiana region
decreased from 2012 primarily due to the contribution of properties to the EXCO/HGI Partnership, which typically have a
higher rate per Mcfe compared to our shale properties in the region since these assets do not currently receive severance tax
holidays. The rate per Mcfe in the Appalachia region decreased due to higher production in relation to the number of wells spud
during the year that would be subject to the Pennsylvania impact fee. This decrease was offset by higher production and ad
valorem taxes per Mcfe associated with our liquids production in the South Texas region. The rate per Mcfe increased by $0.01
on a consolidated basis for the year ended December 31, 2012 compared to 2011. The increase was primarily due to the
enactment of the Pennsylvania impact fee during 2012 and higher ad valorem taxes as a result of our development in the
Haynesville shale.
In our East Texas/North Louisiana area, 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. During the period from July 1, 2012 to June 30, 2013,
wells that did not have a severance tax holiday were charged a severance tax rate of $0.148 per Mcf. Prior to the adjustment of
the severance tax rate in July 2012, wells that did not have a severance tax holiday were charged a severance tax rate of $0.164
per Mcf.
In February 2012, the Commonwealth of Pennsylvania enacted a comprehensive reform to Pennsylvania’s Oil and Gas
Act ("Act"), which requires an impact fee to be paid on all unconventional wells spud. The fees range from $190,000 to
$355,000 per well, based on a price tier calculation to be paid annually for up to 15 years. The fee is payable for all wells spud
in a single year by April 1st of the following year. The Act contains a retroactive fee to be assessed on all unconventional wells
spud prior to December 31, 2011. Our retroactive fee of $2.0 million was paid in September 2012, and was recorded in (Gain)
loss on divestitures and other operating items on our Consolidated Statement of Operations for the year ended December 31,
2012. The estimated on-going fee, which is recorded in Production and ad valorem taxes on the Consolidated Statement of
Operations, is computed using the prior year’s trailing 12 month NYMEX natural gas price. For the years ended December 31,
2013 and 2012, we recorded $1.6 million and $1.8 million as our estimated impact fees, respectively.
66
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 products sold. While severance tax holidays are available in Texas as our production increases, our realized
severance and ad valorem tax rates may become more sensitive to prices.
Depletion, depreciation and amortization
The depletion, depreciation and amortization rate per Mcfe produced varies significantly for each of the periods
presented due to acquisitions, divestitures and impairments of our oil and natural gas 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. This was partially offset by an increase in our depletable base from the acquisition of the Chesapeake Properties and
higher future development costs due to an increase in proved undeveloped reserves resulting from higher natural gas prices. The
depletion rate for the year ended December 31, 2012 was $1.52 per Mcfe, a $0.35 decrease from the year ended December 31,
2011. The decrease is primarily the result of impairments of our oil and natural gas properties, which lowered our depletable
base. We expect this rate to increase during 2014 as a result of a higher depletion rate associated with our oil producing assets in
the South Texas region and the downward revisions of reserve quantities to our properties in the Haynesville shale during the
fourth quarter of 2013.
Our depreciation and amortization costs for the year ended December 31, 2013 decreased by $6.9 million, or 46.6%,
compared to the same period in 2012. The decrease was due to contribution of gathering assets to the EXCO/HGI Partnership
and the sale of other corporate assets in the prior year. Our depreciation and amortization costs for the year ended December 31,
2012 decreased by $3.3 million, or 18.1%, from 2011. The decrease was primarily due to the sale of other corporate assets
during 2012.
Accretion of discount on asset retirement obligations was $2.5 million, $3.9 million and $3.7 million for the years ended
December 31, 2013, 2012 and 2011, respectively. The decrease for the year ended December 31, 2013 compared to prior years
was the result of the contribution of properties to the EXCO/HGI Partnership.
Impairment of oil and natural gas properties
For the years ended December 31, 2013, 2012, and 2011, we recorded impairments of our oil and natural gas properties
of $108.5 million, $1.3 billion and $233.2 million, respectively. The impairments for the year ended December 31, 2013 were
primarily due to continued 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 impairments of our oil and natural gas properties during 2012 and 2011 were due to the significant
decline in natural gas prices.
General and administrative
The following table presents our general and administrative expenses for the years ended December 31, 2013, 2012 and
2011:
(in thousands, except per unit rate)
General and administrative costs:
Year Ended December 31,
Year to year change
2013
2012
2011
2013-2012
2012-2011
Gross general and administrative expense
$
147,432
$
152,057
$
175,030
$
(4,625) $
(22,973)
Technical services and service agreement
charges
Operator overhead reimbursements
Capitalized salaries and share-based
compensation
General and administrative expense
General and administrative expense per Mcfe
(26,846)
(10,462)
(25,242)
(20,544)
(29,061)
(18,407)
(1,604)
10,082
(18,246)
(22,453)
$
$
91,878
0.57
$
$
83,818
0.44
$
$
(22,944)
104,618
0.57
$
$
4,207
8,060
0.13
$
$
3,819
(2,137)
491
(20,800)
(0.13)
67
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 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 the EXCO/HGI Partnership, 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 the EXCO/HGI Partnership;
decreased capitalized salaries and share-based compensation 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 of our former President and Chief Financial Officer, as well as the
resignation of our former Chairman and Chief Executive Officer. 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 the Chesapeake Properties, as well as higher engineering and technology costs.
Significant components of the changes in general and administrative expense for the year ended December 31, 2012
compared to 2011 were a result of:
•
•
•
•
•
•
•
decreased personnel costs of $15.1 million primarily related to a reduction in employee headcount, a decrease in
contract labor costs and lower cash bonus payments in 2012;
decreased share-based compensation expenses of $1.0 million related to a reduction in employee headcount and
decrease in the number of options granted in 2012;
decreased travel costs of $1.9 million as part of our cost reduction efforts;
decreased office expenses of $0.8 million, employee development costs of $1.9 million, relocation costs of $1.6
million, environmental and safety costs of $0.9 million and information technology costs of $1.7 million, all of
which were primarily related to our emphasis on cost reductions and reduced drilling activity;
increased operated overhead recoveries of $2.1 million arising from additional wells drilled in 2012 and 2011;
higher legal expenses of $0.6 million and $1.0 million in engineering expenses related to technical evaluation
software licenses; and
lower technical service recoveries of $3.8 million arising from decreased employee costs in 2012.
(Gain) loss on divestitures and other operating items
Our (gain) loss on divestitures and other operating items for the year ended December 31, 2013 was a net gain of $177.5
million, compared with net losses of $17.0 million and $23.8 million for the years ended December 31, 2012 and 2011,
respectively. 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 the EXCO/HGI Partnership. Partially offsetting the gain were $3.0
million of transaction costs associated with the acquisition of Haynesville and Eagle Ford assets, $6.7 million of expenses
related to various lawsuits including the underpayment of royalties and the allocation of post-production costs, and various
other transactions. The net loss of $17.0 million for the year ended December 31, 2012 included the retroactive Pennsylvania
impact fee discussed in Production and ad valorem taxes, resolution of various title defect adjustments, legal settlements, and
losses related to equipment sales and inventory impairments. We elected to report the retroactive portion of the Pennsylvania
impact fee as a component of other operating items as the retroactive amount would disproportionately impact comparisons
between periods. The net loss of $23.8 million for 2011 included expenses related to various lawsuits, the impairment of
treating facilities in our Vernon Field, impairments of inventory items and costs associated with the former acquisition proposal
that was terminated in July 2011.
Interest expense, net
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 associated with the EXCO Resources
Credit Agreement. We incurred $21.0 million in accelerated deferred financing costs during 2013 primarily as a result of the
68
amendments to the EXCO Resources Credit Agreement and the reduction in our borrowing base from the repayment of
outstanding borrowings with the proceeds from the contribution of properties to the EXCO/HGI Partnership, sale of assets to
KKR, and sale of our equity interest in TGGT. The increase in interest expense, net was also the result of a reduction in
capitalized interest related to lower balance of unproved oil and natural gas properties. The increase in our average interest rate
under the EXCO Resources Credit Agreement as a result of the asset sale requirement and the term loan was partially offset by
lower average borrowings during 2013 compared to prior year.
Our interest expense, net for the year ended December 31, 2012 increased $12.5 million from December 31, 2011 due to
higher average outstanding borrowings under the EXCO Resources Credit Agreement and decreases of capitalized interest
related to the lower balances of our unproved oil and natural gas properties. The increases were offset by a $1.4 million
decrease in other interest expense related to a $1.2 million fee paid in 2011 in connection with the formation of the TGGT credit
facility.
The following table presents our interest expense for the years ended December 31, 2013, 2012 and 2011:
(in thousands)
Interest expense:
2018 Notes
Year Ended December 31,
Period to period change
2013
2012
2011
2013-2012
2012-2011
$
57,485
$
57,394
$
57,309
$
91
$
85
Revolving credit facility under EXCO Resources
Credit Agreement
Term Loan under EXCO Resources Credit Agreement
EXCO/HGI Partnership Credit Agreement
Amortization and write-off of deferred financing costs
Capitalized interest
Other
26,858
6,261
2,335
28,169
(18,729)
210
31,068
23,517
—
—
8,644
(23,809)
195
—
—
8,700
(30,083)
1,580
(4,210)
6,261
2,335
19,525
5,080
15
Total interest expense
$
102,589
$
73,492
$
61,023
$
29,097
$
7,551
—
—
(56)
6,274
(1,385)
12,469
Cash interest payments for the years ended December 31, 2013, 2012 and 2011 were $88.9 million, $86.3 million and
$78.1 million, respectively.
Derivative financial instruments
Our oil and natural gas derivative financial instruments resulted in a net loss of $0.3 million and net gains of $66.1
million and $219.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. The net loss during 2013
compared to the gains during the years ended December 31, 2012 and 2011 were the result of declines in the price of natural gas
in prior years. 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:
Natural gas equivalent per Mcfe
Cash settlements on derivative financial instruments, per
Mcfe
Net price per Mcfe, including derivative financial
instruments
$
$
Year Ended December 31,
Period to period change
2013
2012
2011
2013-2012
2012-2011
3.92
$
2.88
$
4.10
$
1.04
$
(1.22)
0.26
1.06
0.74
(0.80)
0.32
4.18
$
3.94
$
4.84
$
0.24
$
(0.90)
Our total cash settlements for 2013 were $42.1 million, or $0.26 per Mcfe compared to cash settlements of $202.1
million, or $1.06 per Mcfe in 2012 and $135.4 million, or $0.74 per Mcfe, in 2011. As noted above, the significant fluctuations
between settlements on our derivative financial instruments demonstrate the volatility in commodity prices.
We expect to continue our comprehensive derivative financial instrument program as part of our overall business strategy
to enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment,
69
and manage our capital structure. We expect that our revenues will continue to be significantly impacted in future periods by
changes in the value of our derivative financial instruments as a result of volatility in oil and natural gas prices and the amount
of future production volumes subject to derivative financial instruments.
Equity income (loss)
Our equity income (loss) for the years ended December 31, 2013, 2012 and 2011 was a net loss of $53.3 million, net
income of $28.6 million and $32.7 million, respectively. The decrease for the year ended December 31, 2013 compared to the
year ended December 31, 2012 was primarily due to the $86.8 million other than temporary impairment of our investment in
TGGT in 2013. Equity loss from our investment in OPCO increased $4.7 million from the prior year 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.
The decrease for the year ended December 31, 2012 compared to the year ended December 31, 2011 was primarily due
to lower equity income of $4.3 million from our investment in TGGT. During 2012, TGGT recognized asset impairments
totaling approximately $50.8 million (a net reduction of $25.4 million to our equity income) as a result of costs associated with
restoration of infrastructure facilities in Red River Parish, Louisiana and certain abandonments of capital projects arising from
reduced upstream drilling programs. The impact of these impairments was partially offset by higher operating margins as a
result of effective cost-cutting initiatives.
See "Note 14. Equity investments" in the Notes to our Consolidated Financial Statements for further information related
to our investments accounted for under the equity method. The sale of TGGT during the fourth quarter of 2013 will have a
significant impact on our equity income (loss) in future periods.
Income taxes
The following table presents a reconciliation of our income tax provision (benefit) for the years ended December 31,
2013, 2012 and 2011.
(in thousands)
2013
2012
2011
Federal income taxes (benefit) provision at statutory rate of 35% $
7,772
$
(487,649) $
7,909
Year Ended December 31,
Increases (reductions) resulting from:
Goodwill
Adjustments to the valuation allowance
Non-deductible compensation
State taxes net of federal benefit
Other
Total income tax provision
16,382
(28,865)
1,328
3,239
144
$
— $
—
544,949
1,893
(59,406)
213
— $
—
(11,665)
1,760
1,554
442
—
During 2013, our taxable income was offset by the utilization of net operating losses and a corresponding decrease to
previously recognized valuation allowances against deferred tax assets. The net result was no income tax provision for 2013.
During 2012, our net loss was significantly impacted by ceiling test write downs. The tax benefits arising from the
ceiling test 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.
During 2011, our taxable income was offset by the utilization of net operating losses and a corresponding decrease to
previously recognized valuation allowances against deferred tax assets. The net result was no income tax provision for 2011.
As of December 31, 2013, 2012, and 2011, there were no unrecognized tax benefits, including interest and penalties, that
would be required to be recognized in our financial statements.
We file income tax returns in the U.S. federal jurisdictions and various state jurisdictions. With few exceptions, we are no
longer subject to U.S. federal and state and local examinations by tax authorities for years before 2005. 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.
70
Pro forma financial information
As discussed in "Note 3. Acquisitions, divestitures and other significant events" in the Notes to our Consolidated
Financial Statements, the EXCO/HGI Partnership was formed on February 14, 2013, which resulted in the reduction of our
economic interest in certain oil and natural gas properties contributed to the partnership. On March 5, 2013, the EXCO/HGI
Partnership purchased the remaining shallow Cotton Valley assets in the East Texas/North Louisiana JV from an affiliate of BG
Group. During the third quarter of 2013, we closed the acquisitions of oil and natural gas properties in the Haynesville and
Eagle Ford shale formations from Chesapeake. The following table presents selected pro forma operating and financial
information for the years ended December 31, 2013, 2012 and 2011 as if these transactions had occurred on January 1, 2011:
(dollars in thousands, except per unit rate)
Historical EXCO
Year ended December 31, 2013
EXCO/HGI
Partnership pro
forma adjustments
Chesapeake
Properties pro
forma adjustments
Pro forma EXCO
Production:
Total production (Mmcfe)
Average production (Mmcfe/d)
Revenues:
161,907
444
(2,705)
(7)
27,279
75
Oil and natural gas revenues
$
634,309
$
(12,657) $
150,319
$
Average realized price ($/Mcfe)
3.92
4.68
Expenses:
Direct operating costs
Per Mcfe
Production and ad valorem taxes
Per Mcfe
Gathering and transportation (1)
Per Mcfe
Excess of revenues over operating expenses
61,277
0.38
21,971
0.14
100,645
0.62
450,416
(3,489)
1.29
(1,545)
0.57
(782)
0.29
(6,841)
121,790
565,365
(dollars in thousands, except per unit rate)
Historical EXCO
Year ended December 31, 2012
EXCO/HGI
Partnership pro
forma adjustments
Chesapeake
Properties pro
forma adjustments
Pro forma EXCO
Production:
Total production (Mmcfe)
Average production (Mmcfe/d)
Revenues:
189,928
519
(25,077)
(69)
46,414
127
Oil and natural gas revenues
$
546,609
$
(111,276) $
168,677
$
186,481
512
771,971
4.14
80,352
0.43
26,391
0.14
99,863
0.54
211,265
577
604,010
2.86
76,219
0.36
23,321
0.11
94,983
0.45
5.51
22,564
0.83
5,965
0.22
—
—
3.63
28,173
0.61
9,217
0.20
—
—
131,287
409,487
Average realized price ($/Mcfe)
2.88
4.44
Expenses:
Direct operating costs
Per Mcfe
Production and ad valorem taxes
Per Mcfe
Gathering and transportation (1)
Per Mcfe
Excess of revenues over operating expenses
(29,081)
1.16
(13,379)
0.53
(7,892)
0.31
(60,924)
77,127
0.41
27,483
0.14
102,875
0.54
339,124
71
(dollars in thousands, except per unit rate)
Historical EXCO
Year ended December 31, 2011
EXCO/HGI
Partnership pro
forma adjustments
Chesapeake
Properties pro
forma adjustments
Pro forma EXCO
Production:
Total production (Mmcfe)
Average production (Mmcfe/d)
Revenues:
184,176
505
(19,280)
(53)
28,160
77
Oil and natural gas revenues
$
754,201
$
(155,743) $
101,343
$
Average realized price ($/Mcfe)
4.10
8.08
Expenses:
Direct operating costs
Per Mcfe
Production and ad valorem taxes
Per Mcfe
Gathering and transportation (1)
Per Mcfe
Excess of revenues over operating expenses
84,766
0.46
23,875
0.13
86,881
0.47
558,679
(36,525)
1.89
(13,967)
0.72
(8,375)
0.43
(96,876)
3.60
8,600
0.31
3,204
0.11
—
—
89,539
551,342
193,056
529
699,801
3.62
56,841
0.29
13,112
0.07
78,506
0.41
(1)
The oil and natural gas revenues for the Chesapeake Properties are presented net of gathering and treating expenses.
The pro forma information is not necessarily indicative of what actually would have occurred if the transaction had been
completed as of January 1, 2011, nor is it necessarily indicative of future consolidated results.
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 in 2014 and
future years 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 sales of oil and natural gas properties or other assets, including our ability to obtain
financing in order to fund the acquisition of properties under the KKR Participation Agreement;
reductions to our borrowing base; and
our ability to maintain compliance with debt covenants.
Recent events affecting liquidity
In July 2013, we closed the acquisition of oil and natural gas assets in the Haynesville and Eagle Ford shale
formations from Chesapeake. We amended and restated the EXCO Resources Credit Agreement to facilitate these
acquisitions, which increased the borrowing base to $1.6 billion, including a $1.3 billion revolving commitment and a $300.0
million term loan. The amendment to the EXCO Resources Credit Agreement also included a $400.0 million asset sale
requirement. The interest rate on borrowings under the revolving commitment of the EXCO Resources Credit Agreement was
72
increased by 100 basis points while the asset sale requirement was outstanding. Proceeds from the sale of properties under the
KKR Participation Agreement on July 31, 2013 and proceeds from the sale of our equity interest in TGGT on November 15,
2013 were used to reduce outstanding borrowings under the EXCO Resources Credit Agreement. After giving effect to these
transactions, the EXCO Resources Credit Agreement borrowing base and outstanding borrowings were reduced by $371.1
million and our asset sale requirement was reduced to $28.9 million as of December 31, 2013.
We closed the Rights Offering and related private placement on January 17, 2014 which resulted in the issuance of
54,574,734 shares of our common stock for net proceeds of $272.9 million. We used the net proceeds to pay indebtedness
under the EXCO Resources Credit Agreement, including payment in full of the remaining indebtedness related to the asset
sale requirement as well as a portion of the indebtedness outstanding under the revolving commitment under the EXCO
Resources Credit Agreement. Upon repayment of the asset sale requirement, the interest rate on the revolving commitment
decreased by 100 basis points. The repayments of indebtedness under asset sale requirement resulted in a corresponding
reduction in our borrowing base. After giving effect to the Rights Offering and the related transactions under the Investment
Agreements, the available borrowing base on the revolving commitment under the EXCO Resources Credit Agreement was
$900.0 million with approximately $491.0 million of outstanding indebtedness and approximately $402.1 million of unused
borrowing base, net of letters of credit. We expect to receive approximately $65.0 million upon closing of the sale of our
interest in a joint venture including producing wells and undeveloped acreage in the Permian Basin. This transaction is
expected to close in the first or second quarter of 2014, and we plan to utilize the proceeds to repay indebtedness under the
EXCO Resources Credit Agreement.
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. The next borrowing base redetermination for the EXCO Resources Credit
Agreement will occur in April 2014. 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. Accordingly, our ability to effectively manage our capital
budget 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, 2013 as well as on a pro forma
basis as if the closing of the Rights Offering had occurred on December 31, 2013. The pro forma information is not
considered to be complete and excludes the impact of all other transactions subsequent to December 31, 2013.
(in thousands)
Cash (1) (2)
Revolving credit facility under the EXCO Resources Credit Agreement
Asset sale requirement under the EXCO Resources Credit Agreement
Term loan under the EXCO Resources Credit Agreement (3)
2018 Notes (4)
Total debt (5)
Net debt
Borrowing base (6)
Unused borrowing base (7)
Unused borrowing base plus cash (1) (7)
December 31, 2013
Pro forma
$
$
$
$
$
$
66,518
$
735,000
28,866
298,500
750,000
1,812,366
1,745,848
1,228,866
158,112
224,630
$
$
$
$
$
66,518
490,992
—
298,500
750,000
1,539,492
1,472,974
1,200,000
402,120
468,638
Includes restricted cash of $20.6 million at December 31, 2013.
(1)
(2) Excludes our proportionate share of cash related to the EXCO/HGI Partnership of $4.5 million at December 31, 2013.
(3) Excludes unamortized discount of $2.8 million at December 31, 2013.
(4) Excludes unamortized discount of $7.3 million at December 31, 2013.
(5) Excludes our proportionate share of the debt related to the EXCO/HGI Partnership of $88.5 million as of December 31,
2013.
Includes the borrowing base for the revolving commitment and term loan under the EXCO Resources Credit Agreement.
(6)
(7) Net of $6.9 million in letters of credit and $1.5 million in repayments for the term loan under the EXCO Resources
Credit Agreement as of December 31, 2013.
73
Debt covenants
As of December 31, 2013, our consolidated debt consisted of the EXCO Resources Credit Agreement, the 2018 Notes
and our 25.5% proportionate share of the EXCO/HGI Partnership Credit Agreement (see "Note 6. Long-Term Debt" in the
Notes to our Consolidated Financial Statements for a further description of each agreement). While our proportionate share of
the EXCO/HGI Partnership's debt is consolidated, we are not a guarantor of the debt.
As of December 31, 2013, EXCO and the EXCO/HGI Partnership were in compliance with the financial covenants
contained in their respective credit agreements, which are presented in the following table. Management believes the
following table contains important information related to our liquidity and compliance with the financial covenants of each
agreement. However, the information is not complete and is qualified in its entirety by the terms of the EXCO Resources
Credit Agreement and the EXCO/HGI Partnership Credit Agreement.
(dollars in millions)
EXCO Resources:
As of December 31, 2013
Borrowing
base
Outstanding
Covenant type (2)
Required
ratio (3)
Actual
ratio
EXCO Resources Credit Agreement (1)
$
1,228.9
$
1,062.4
Current ratio
Leverage ratio
EXCO/HGI Partnership:
EXCO/HGI Partnership Credit Agreement (4)
$
400.0
$
347.0
Current ratio
Leverage ratio
> 1.0
< 4.5
> 1.0
< 4.5
1.5
3.6
3.0
3.6
(1)
The borrowing base presented within this table for the EXCO Resources Credit Agreement includes both the revolving
commitment and the term loan. 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 interest rate grid was increased by 100 bps per annum until the asset sale
requirement was repaid in January 2014. The revolving credit facility portion of the EXCO Resources Credit Agreement
matures on July 31, 2018. The interest rate on the term loan portion of the EXCO Resources Credit Agreement is
LIBOR (with a floor of 100 bps) plus 400 bps (or ABR plus 300 bps). The term loan portion of the EXCO Resources
Credit Agreement matures on August 19, 2019.
(2) As defined in the respective credit agreements.
(3) Maximum leverage permitted, or minimum coverage required per the respective credit agreement.
(4)
Interest rates range from LIBOR plus 175 bps to 275 bps or (ABR plus 75bps to 175 bps) depending on borrowing base
usage. The EXCO/HGI Partnership Credit Agreement matures on February 14, 2018.
The 2018 Notes mature in September 2018 and have a fixed interest rate of 7.5%. The indenture governing the 2018
Notes contains incurrence covenants which restrict our ability to incur additional indebtedness or pledge assets.
There are certain risks arising from the depressed oil and/or natural gas prices that could impact our ability to meet debt
covenants in future periods. In particular, our leverage ratio, as defined in the EXCO Resources Credit Agreement, is
computed using a trailing 12 month computation of EBITDAX and only includes operations from non-guarantor subsidiaries
and unconsolidated joint ventures to the extent that cash is distributed to entities under the credit agreement. Our results of
operations, cash flows from operations and Proved Reserves were reduced by the 74.5% economic interest in the EXCO/HGI
Partnership acquired by HGI in the first quarter of 2013. As a result, our ability to maintain compliance with this covenant is
negatively impacted when oil and/or natural gas prices and/or production decline over an extended period of time. In addition,
our recent acquisitions in the Eagle Ford and Haynesville shale formations resulted in a significant increase in our
consolidated indebtedness. Our ability to maintain compliance with our financial covenants is dependent on our ability to
effectively integrate these properties as well as their future development and production.
Furthermore, the increase in our indebtedness may limit our ability to pay dividends as a result of covenants within the
EXCO Resources Credit Agreement which states that we may declare and pay cash dividends on our common stock in an
amount not to exceed a cumulative total of $50.0 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.
74
As of December 31, 2013, we had approximately 18% of the revolving commitment available under the EXCO Resources
Credit Agreement. As a result of the repayment of indebtedness from the proceeds of the Rights Offering and related private
placement, we had approximately 45% of the revolving commitment available under the EXCO Resources Credit Agreement
as of January 17, 2014. As a result of the issuance of additional shares of our common stock in connection with the Rights
Offering, we will be required to reduce our dividends in order to maintain compliance with the annual limitation of $50.0
million under the EXCO Resources Credit Agreement unless we are able to amend the related covenant.
Capital commitments
We entered into the KKR Participation Agreement to mitigate the impact of development expenditures on our capital
resources and liquidity. EXCO is required to offer to purchase KKR's 75% 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 KKR Participation Agreement, subject to specific well criteria and return hurdles. 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 KKR 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 KKR’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. KKR is required to accept the offer if it exceeds the required return. If the
PV-10 value exceeds KKR’s required return on investment, then EXCO and KKR 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. KKR has a right to retain
an undivided 15% of their collective interest in the quarterly tranche of wells included in each offer. These acquisitions are
expected to increase the borrowing base under the revolving commitment of the EXCO Resources Credit Agreement, and the
acquisitions are expected to be funded with borrowings under the EXCO Resources Credit Agreement, cash flows from
operations, or alternative financing arrangements.
During 2013, we spud 23 wells under the KKR Participation Agreement and these wells are expected to be included
within the first quarterly buyback in the first quarter of 2015. The timing of these buybacks is dependent upon the date these
wells are turned-to-sales and the downtime during the year preceding the offer process. KKR's share of the average
development and completion costs per well to be included within the first quarterly buyback is approximately $3.5 million.
During 2013, there were 7 wells turned-to-sales and KKR's share of the revenues less operating expenses for these wells was
$5.7 million. Prior to buybacks in future periods, our average working interest in wells developed under this agreement is
approximately 17% and KKR's average working interest is approximately 50%. The remaining working interest is held by
other third-party owners and is not part of the buyback program. During 2014, we expect to spud 84 wells which will be
included in future buybacks beginning in the second quarter of 2015.
While we are required to make offers to purchase KKR's interest on certain wells, we may not have sufficient funds or
borrowing capacity under the EXCO Resources Credit Agreement to complete the acquisitions. 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 via acquisitions of KKR's producing properties. See Item “1A—Risk Factors. If we are unable to complete
the joint development of our assets in the Eagle Ford shale formations with KKR, we may need to find alternative sources of
capital, which may not be available on favorable terms, if at all.”
Historical sources and uses of funds
Our primary sources of cash in 2013 were cash flows from operations, borrowings under the EXCO Resources Credit
Agreement and proceeds from the sale of assets. We utilized borrowings under the EXCO Resources Credit Agreement to fund
the acquisition of the Chesapeake Properties. We have focused on efficiently managing our capital expenditures as part of our
increased development program due to our recent acquisitions.
Net increases (decreases) in cash are summarized as follows:
75
(in thousands)
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing activities
Net increase (decrease) in cash
Operating activities
Year Ended December 31,
2013
2012
$
$
350,634
(252,478)
(93,317)
4,839
$
$
514,786
(427,094)
(74,045)
13,647
$
$
2011
428,543
(709,531)
268,756
(12,232)
The primary factors impacting our cash flows from operations generally include: (i) levels of production from our oil
and natural gas properties, (ii) prices we receive from sales of oil, natural gas and natural gas liquids production, including
settlement proceeds or payments related to our oil and natural gas derivatives, (iii) operating costs of our oil and natural gas
properties, (iv) costs of our general and administrative activities and (v) interest expense. Our cash flows from operating
activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes.
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 Chesapeake Properties and higher realized oil and natural gas prices were partially offset by lower production
primarily due to our contribution of properties to the EXCO/HGI Partnership.
Net cash provided by operating activities for the year ended December 31, 2012 was $514.8 million compared with
$428.5 million for the year ended December 31, 2011. The increase in 2012 was primarily attributable to the higher settlement
proceeds on our derivatives and favorable working capital conversions, offset by lower average prices received.
Investing activities
Our investing activities consist primarily of drilling and development expenditures, acquisitions and divestitures. Our
recent acquisition of the Chesapeake Properties was directed toward producing properties with additional undeveloped upside
potential. Future acquisitions are dependent on oil and natural gas prices, availability of producing properties and attractive
acreage, acceptable rates of return and availability of borrowing capacity under the EXCO Resources Credit Agreement or from
other capital sources.
For the year ended December 31, 2013, our cash flows used in investing activities were $252.5 million, as compared
with $427.1 million of cash flows used in investing activities for the year ended December 31, 2012. Our property acquisitions
during 2013 were primarily attributable to the acquisition of the Chesapeake Properties of $942.9 million and our proportionate
share of the EXCO/HGI Partnership'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 the EXCO/HGI Partnership, the sale of our equity investment in TGGT of $236.6 million, net
of commissions and fees, the sale of undeveloped acreage to KKR 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, compared with
$709.5 million of cash flows used in investing activities for the year ended December 31, 2011. The decrease was primarily
attributable to reductions in our drilling program in response to a decline in natural gas prices. Cash flows from investing
activities for the year ended December 31, 2011 included a $125.0 million distribution from TGGT and receipt of $391.0
million from BG Group for its 50% share of acquisitions in our Appalachia and East Texas/North Louisiana areas.
Financing activities
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 borrowings of approximately $1.0 billion under the EXCO Resources
Credit Agreement to fund the acquisition of the Chesapeake Properties and the additional borrowings of the EXCO/HGI
Partnership to fund the acquisition of shallow Cotton Valley assets from an affiliate of BG Group. These borrowings were
offset by total repayments of our EXCO Resources Credit Agreement of approximately $1.0 billion which consisted of the
application of proceeds from the contribution of properties to the EXCO/HGI Partnership, the sale of undeveloped acreage to
76
KKR, the sale of TGGT, cash flows from operations and other asset sales. We utilized borrowings under the EXCO Resources
Credit Agreement to pay deferred financing costs associated with the amendment to facilitate the acquisition of the Chesapeake
Properties. We paid $43.2 million of dividends on our common stock 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 stock during 2012.
For the year ended December 31, 2011, our cash flows provided by financing activities were $268.8 million. The cash
flows provided by financing activities primarily consisted of net borrowings of $298.5 million under the EXCO Resources
Credit Agreement to fund the acquisitions of properties in the Marcellus shale and the Haynesville shale. We also received
$12.1 million for the issuance of common stock as a result of the exercise of stock options by employees. We paid $34.2
million of dividends on our common stock during 2011.
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 the KKR Participation Agreement 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 continued to emphasize cost containment and reducing our drilling and
completion costs. We began our development program in the 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 the EXCO/HGI Partnership during 2013. Our lease purchases during 2012 were
primarily in the Permian Basin on acreage with horizontal drilling potential.
During 2011, our oil and natural gas property acquisitions consisted of the acquisition of Haynesville shale assets as
wells as Marcellus shale assets including $459.4 million we funded for the Chief transaction in 2010 as the necessary consents
to acquire those assets were not received from third parties until January 11, 2011. Our developmental capital expenditures
were primarily focused on the Haynesville shale concentrated on DeSoto Parish and the Shelby area, and the early stages of our
appraisal and development programs in the Marcellus shale. We also had a limited development program in the Permian Basin
focused on conventional assets which were contributed to the EXCO/HGI Partnership during 2013. Our lease purchases during
2011 primarily consisted of undeveloped acreage in the Haynesville/Bossier shale and Marcellus shale.
The following table presents our capital expenditures for the years ended December 31, 2013, 2012 and 2011. These
capital expenditures exclude the EXCO/HGI Partnership, which funded its capital expenditures through internally generated
cash flow and credit agreement.
(in thousands)
Capital expenditures:
Year Ended December 31,
2013
2012
2011
Oil and natural gas property acquisitions (1) (2)
$
942,946
$
3,349
$
Lease purchases (3)
Development capital expenditures
Seismic
Field operations, gathering and water pipelines
Corporate and other
Total capital expenditures
14,835
265,120
10,217
12,379
37,287
46,678
403,342
2,480
1,044
48,303
755,520
63,367
855,451
10,146
6,495
65,747
$
1,282,784
$
505,196
$
1,756,726
77
(1)
(2)
(3)
The oil and natural gas property acquisitions of $942.9 million during 2013 included the Eagle Ford and Haynesville
assets acquired from Chesapeake. 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 KKR.
Excludes reimbursements from BG Group of $359.1 million in 2011. There were no reimbursements from BG Group in
2013 and 2012.
Excludes reimbursements from BG Group $2.1 million in 2012 and $31.9 million in 2011. There were no reimbursements
from BG Group in 2013.
2014 capital budget
Our board of directors approved a capital budget of $368.0 million for 2014, of which $294.0 million is allocated to
development and completion activities. Our developmental activities in the East Texas/North Louisiana region are primarily
focused on our core area in DeSoto Parish as well as a limited drilling program in the Shelby area. In the South Texas region,
our developmental activities will primarily be focused on our core area as part of the participation agreement with KKR. We
believe the capital budget is appropriate for current commodity prices and our capital structure. Our capital program was
designed to manage our capital expenditures in relation to our operating cash flow. These capital expenditures exclude the
EXCO/HGI Partnership, which funds its capital expenditures through internally generated cash flow and its credit agreement,
and also exclude any capital expenditures for our joint development of shale properties in the Permian Basin. The 2014 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
42
90
2
—
134
20.5
15.2
0.5
—
36.2
$
18.3
14.3
0.5
—
$
173
109
12
—
33.1
$
294
$
11
29
5
29
74
$
$
184
138
17
29
368
(1)
(2)
The wells spud and completed within this table only include those operated by EXCO.
Includes $18 million of capitalized interest.
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 and call option contracts.
As of December 31, 2013, we had derivative financial instruments in place for the volumes and prices shown below:
(in thousands, except prices)
NYMEX gas volume -
Mmbtu
Weighted average contract
price per Mmbtu
NYMEX oil volume -
Bbls
Weighted average contract
price per Bbl
Swaps:
2014
2015
Basis Swaps:
2014
2015
Call options:
2014
2015
4.22
4.31
—
—
4.29
4.29
84,060
$
28,288
—
—
20,075
20,075
78
1,644
$
548
183
91
365
365
95.03
91.78
6.03
6.10
100.00
100.00
We proportionately consolidate the derivative financial instruments entered into by the EXCO/HGI Partnership.
However, we are not liable in the event of default on the EXCO/HGI Partnership's derivative contracts. As of December 31,
2013, our proportionate share of the EXCO/HGI Partnership's natural gas derivative swap contracts included approximately
15,000 Mmbtu per day at an average price of $4.15 during 2014. Our proportionate share of the EXCO/HGI Partnership's oil
derivative swap contracts included approximately 255 Bbls per day at an average price of $91.87 during 2014. The EXCO/HGI
Partnership had derivative financial instruments that covered approximately 77% of production volumes during the period from
its inception until December 31, 2013.
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, 2013, 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, 2013:
(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)
$
31,866
$
6,000
$
741,000
$
283,500
$
1,062,366
2018 Notes (2)
Firm transportation services (3)
Other fixed commitments (4)
Drilling contracts
Operating leases and other
—
136,376
14,532
40,286
8,055
—
269,469
30,525
—
6,536
750,000
262,000
8,625
—
140
—
190,678
5,929
—
—
750,000
858,523
59,611
40,286
14,731
Total contractual obligations (5) (6)
$ 231,115
$ 312,530
$ 1,761,765
$
480,107
$
2,785,517
(1)
(2)
(3)
The EXCO Resources Credit Agreement includes both the revolving commitment and the term loan. The revolving
commitment included the asset sale requirement of $28.9 million which was repaid on January 17, 2013. 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
revolving credit facility portion of the EXCO Resources Credit Agreement matures on July 31, 2018. The interest rate on
the term loan portion of the EXCO Resources Credit Agreement is LIBOR (with a floor of 100 bps) plus 400 bps (or ABR
plus 300 bps). The term loan portion of the EXCO Resources Credit Agreement matures on August 19, 2019.
The 2018 Notes are due on September 15, 2018. The annual interest obligation is $56.3 million.
Firm transportation services reflect contracts whereby EXCO commits to transport a minimum quantity of natural gas on
a shippers’ pipeline. Whether or not EXCO delivers the minimum quantity, we pay the fees as if the quantities were
delivered.
(4) Other fixed commitments are primarily related to completion service contracts and minimum sales commitments under
(5)
(6)
marketing contracts.
Excludes commitments of our equity method investees as neither EXCO nor any of its subsidiaries are guarantors of these
commitments. OPCO’s total commitments as of December 31, 2013, which consisted primarily of firm transportation
contracts, drilling contracts and completion services, totaled $39.1 million.
Excludes commitments of the EXCO/HGI Partnership as neither EXCO nor any of its subsidiaries are guarantors of these
commitments. The EXCO/HGI Partnership's total commitments as of December 31, 2013, which consisted primarily of
borrowings under the EXCO/HGI Partnership Credit Agreement, totaled $347.7 million.
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.
79
This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our
market risk sensitive instruments were entered into for hedging and investment purposes, not for trading purposes.
Commodity price risk
Our objective in entering into derivative financial instruments is to manage our exposure to commodity price
fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our financing
activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the
benefits we would realize if oil and natural gas prices increase. When prices for oil and natural gas are volatile, a significant
portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to
changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made
or received on monthly settlements of contracts or if we terminate a contract prior to its expiration.
Our most significant market risk exposure is in the pricing applicable to our oil and natural gas production. Realized
pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices for natural gas. 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, 2013, 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 $91.9 million. 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, 2013, our exposure to interest rate changes related primarily to borrowings under the EXCO Resources
Credit Agreement and the EXCO/HGI Partnership Credit Agreement. The interest rate per annum on the 2018 Notes is fixed at
7.5%. Interest is payable on borrowings under the EXCO Resources Credit Agreement based on a floating rate as more fully
described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our liquidity, capital
resources and capital commitments.” At December 31, 2013, we had approximately $1.1 billion in outstanding borrowings
under the EXCO Resources Credit Agreement, including the revolving commitment and the term loan, and $88.5 million for
our proportionate share of outstanding borrowings under the EXCO/HGI Partnership Credit Agreement. A 1% change in
interest rates (100 bps) based on the variable borrowings as of December 31, 2013 would result in an increase or decrease in
our interest expense of approximately $8.6 million per year. The interest we pay on these borrowings is set periodically based
upon market rates.
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
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2013 and 2012
Consolidated Statements of Operations for the years ended December 31, 2013, 2012, and 2011
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012, and 2011
Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 2013, 2012, and
2011
Notes to consolidated financial statements
80
81
82
83
85
86
87
88
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, 2013. 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 (1992). Based on management's assessment, management believes that, as of December 31, 2013, 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, 2013 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:
Dallas, Texas
February 26, 2014
/s/ Mark F. Mulhern
Executive Vice President, Chief Financial
Officer and interim Chief Accounting
Officer
81
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
EXCO Resources, Inc.:
We have audited the accompanying consolidated balance sheets of EXCO Resources, Inc. and subsidiaries as of December 31,
2013 and 2012, 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, 2013. We also have audited EXCO Resources, Inc.’s internal control over
financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992)
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, 2013 and 2012, and the results of its operations and its cash flows
for each of the years in the three-year period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
Dallas, Texas
February 26, 2014
/s/ KPMG LLP
82
EXCO RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands)
Assets
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable, net:
Oil and natural gas
Joint interest
Other
Inventory
Derivative financial instruments
Other
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 assets
Accumulated depreciation and amortization
Gathering assets, net
Office, field and other equipment, net
Deferred financing costs, net
Derivative financial instruments
Goodwill
Other assets
Total assets
See accompanying notes.
December 31,
2013
December 31,
2012
$
50,483
$
20,570
128,352
70,759
18,022
3,087
8,226
6,355
305,854
57,562
45,644
70,085
84,348
69,446
15,053
5,705
49,500
22,085
361,866
347,008
425,307
470,043
3,554,210
(2,183,464)
1,796,053
2,715,767
(1,945,565)
1,240,245
33,473
(10,338)
23,135
27,204
28,807
6,829
130,830
(34,364)
96,466
20,725
22,584
16,554
163,155
218,256
29
28
$ 2,408,628
$ 2,323,732
83
EXCO RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share and share data)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities
Revenues and royalties payable
Accrued interest payable
Current portion of asset retirement obligations
Income taxes payable
Derivative financial instruments
Current maturities of long-term debt
Total current liabilities
Long-term debt
Deferred income taxes
Derivative financial instruments
Asset retirement obligations and other long-term liabilities
Commitments and contingencies
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and
outstanding
Common stock, $0.001 par value; 350,000,000 authorized shares; 218,783,540 shares
issued and 218,244,319 shares outstanding at December 31, 2013; 218,126,071 shares
issued and 217,586,850 shares outstanding at December 31, 2012
Subscription rights, $0.001 par value, 54,574,734 issued and outstanding at December 31,
2013
Additional paid-in capital
Accumulated deficit
Treasury stock, at cost; 539,221 shares at December 31, 2013 and December 31, 2012
Total shareholders’ equity
Total liabilities and shareholders’ equity
See accompanying notes.
December 31,
2013
December 31,
2012
$
132,188
$
83,240
154,862
18,144
191
—
11,919
31,866
349,170
134,066
17,029
1,200
—
2,396
—
237,931
1,858,912
1,848,972
—
9,671
42,970
—
26,369
61,067
—
—
215
55
—
—
215
—
3,219,748
(3,064,634)
(7,479)
147,905
3,200,067
(3,043,410)
(7,479)
149,393
$ 2,408,628
$ 2,323,732
84
EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
2012
2011
2013
$
111,440
$
62,119
$
8,560
514,309
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
—
22,068
462,422
546,609
77,127
27,483
102,875
303,156
1,346,749
3,887
83,818
17,029
(73,492)
66,133
969
28,620
22,230
(1,393,285)
—
67,440
29,639
657,122
754,201
84,766
23,875
86,881
362,956
233,239
3,652
104,618
23,819
(61,023)
219,730
788
32,706
192,201
22,596
—
22,596
1,962,124
(1,415,515)
923,806
(169,605)
$
$
$
22,204
$
(1,393,285) $
0.10
$
(6.50) $
215,011
214,321
0.11
213,908
0.10
$
(6.50) $
0.10
230,912
214,321
216,705
(in thousands, except per share data)
Revenues:
Oil
Natural gas liquids
Natural gas
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.
85
EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Operating Activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Year Ended December 31,
2013
2012
2011
$
22,204
$
(1,393,285) $
22,596
Depletion, depreciation and amortization
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 of derivative financial instruments
Deferred income taxes
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
Deposit on acquisitions
Other
Net cash used in investing activities
Financing Activities:
Borrowings under credit agreements
Repayments under credit agreements
Proceeds from issuance of common stock
Payment of common stock dividends
Deferred financing costs and other
Net cash provided by (used in) financing activities
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:
Capitalized share-based compensation
Capitalized interest
Issuance of common stock for director services
Accrued restricted stock dividends
Debt assumed upon formation of EXCO/HGI Partnership, net
Issuance of subscription rights
See accompanying notes.
86
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)
1,004,523
(1,022,785)
1,712
(43,214)
(33,553)
(93,317)
4,839
45,644
50,483
88,936
—
$
$
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)
(74,045)
13,647
31,997
45,644
86,298
—
$
$
7,288
$
7,513
$
18,729
93
214
58,613
55
23,809
597
300
—
—
$
$
$
362,956
11,012
3,652
240,039
(32,706)
(219,730)
135,417
—
9,759
(479)
(79,359)
(5,961)
(18,653)
428,543
(984,085)
(753,286)
449,683
5,792
(1,707)
111,171
464,151
(1,250)
(709,531)
706,000
(407,500)
12,063
(34,238)
(7,569)
268,756
(12,232)
44,229
31,997
78,125
1,458
6,406
30,083
70
129
—
—
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
EXCO RESOURCES, INC.
(in thousands)
Shares
Amount
Shares
Amount
Shares
Amount
Common Stock
Subscription Rights
Treasury Stock
Additional
paid-in
capital
Accumulated
deficit
Total
shareholders’
equity
Balance at December
31, 2010
Issuance of common
stock
Share-based
compensation
Restricted stock issued,
net of cancellations
Common stock
dividends
Net income
Balance at December
31, 2011
Issuance of common
stock
Share-based
compensation
Restricted stock issued,
net of cancellations
Common stock
dividends
Net loss
Balance at December
31, 2012
Issuance of common
stock
Share-based
compensation
Restricted stock issued,
net of cancellations
Common stock
dividends
Issuance of subscription
rights
Net income
Balance at December
31, 2013
See accompanying notes.
213,736
$
214
— $
946
—
2,563
—
—
1
—
—
—
—
—
—
—
—
—
217,245
$
215
— $
266
—
615
—
—
—
—
—
—
—
—
—
—
—
—
218,126
$
215
— $
228
—
429
—
—
—
—
—
—
—
—
—
—
—
—
—
54,575
—
218,783
$
215
54,575
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
55
—
55
(539) $ (7,479) $
3,151,513
$
(1,603,696) $
1,540,552
—
—
—
—
—
—
—
—
—
—
12,132
17,418
—
—
—
—
—
—
(34,367)
22,596
12,133
17,418
—
(34,367)
22,596
(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
87
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 acquisition, exploration, exploitation, development
and production of onshore U.S. oil and natural gas properties. Our principal operations are conducted in certain key U.S. oil and
natural gas areas including Texas, Louisiana and the Appalachia region. The following is a brief discussion of our producing
regions and the EXCO/HGI Partnership.
• East Texas/North Louisiana
The East Texas/North Louisiana region is primarily comprised of our Haynesville and Bossier shale assets. We have a
joint venture with BG Group, plc ("BG Group") covering an undivided 50% interest in certain Haynesville/Bossier
shale assets in East Texas and North Louisiana ("East Texas/North Louisiana JV"). We previously held certain
conventional shallow producing assets that we contributed to the EXCO/HGI Partnership, as defined below, upon its
formation on February 14, 2013. 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 our Eagle Ford shale assets in South Texas. The South
Texas region also includes assets in the Pearsall shale and the Austin Chalk and Buda 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 producing assets and Marcellus shale
properties 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 owned by a jointly owned operating entity ("OPCO") that operates the Appalachia JV's properties. We own
a 50% interest in OPCO.
• Permian and other
Our Permian and other region is comprised of properties in the Permian Basin with horizontal drilling potential and
conventional assets in the Mid-Continent region. Our shallow assets in the Permian Basin were contributed to the
EXCO/HGI Partnership on February 14, 2013. 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. We formed a joint venture with the private party to develop our acreage with horizontal drilling potential in the
Permian Basin. The private party will serve as the operator. On February 13, 2014, we entered into a purchase and
sale agreement with the private party for the sale of our interest in the joint venture including producing wells and
undeveloped acreage. See further discussion in "Note 3. Acquisitions, divestitures and other significant events".
• EXCO/HGI Partnership
A joint venture formed on February 14, 2013, with Harbinger Group Inc. ("HGI") in which we own a 25.5% economic
interest in conventional shallow producing assets in East Texas and North Louisiana and shallow Canyon Sand and
other assets in the Permian Basin ("EXCO/HGI Partnership").
The accompanying Consolidated Balance Sheets as of December 31, 2013 and 2012, Consolidated Statements of
Operations, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders’ Equity for the
years ended December 31, 2013, 2012 and 2011 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").
88
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, 2013 and
2012 and the Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Changes in Shareholders'
Equity for the years ended December 31, 2013, 2012 and 2011. 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.
During the year ended December 31, 2013, we sold our equity interest in TGGT Holdings, LLC ("TGGT") which
previously made up the majority of our midstream segment. See further discussion of this transaction in "Note 14. Equity
investments". Our remaining midstream investments are not considered to be significant and do not meet the disclosure
requirements for a separate reportable business segment.
We report our interests in oil and natural gas properties using the proportional consolidation method of accounting. Also,
we report our 25.5% interest in the EXCO/HGI Partnership using proportional consolidation. From January 1, 2013 to February
13, 2013, our operating results reflect 100% of our interest in the properties we contributed to the EXCO/HGI Partnership.
From February 14, 2013 to December 31, 2013, our operating results reflect 25.5% of our interest in the properties we
contributed to the EXCO/HGI Partnership.
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 the East Texas/North Louisiana JV. Funds held in this escrow
account are restricted and can be used solely for drilling and operations for the East Texas/North Louisiana JV.
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, 2013
and 2012. 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, 2013, 2012 and 2011, sales to BG Energy Merchants LLC accounted for
approximately 48%, 36% and 36%, respectively, of total consolidated revenues. BG Energy Merchants LLC is a subsidiary of
BG Group. For the year ended December 31, 2013, Chesapeake Energy Marketing Inc. accounted for approximately 14% of
total consolidated revenues. Chesapeake Energy Marketing Inc. is a subsidiary of Chesapeake Energy Corporation
("Chesapeake").
89
Derivative financial instruments
In connection with the incurrence of debt related to our acquisition, exploration, exploitation, development and
production activities, our management has adopted a policy of entering into oil and natural gas derivative financial instruments
to mitigate the impacts of commodity price fluctuations and to 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.
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, which include unproved oil and natural gas properties, properties under development, and major
development projects, collectively totaled $425.3 million and $470.0 million as of December 31, 2013 and 2012, 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 impaired approximately $1.0 million and $60.8 million of undeveloped properties during 2013 and 2012,
respectively, which were transferred to the depletable portion of the full cost pool during each year. The impairment was
recorded to reflect the estimated market price which included certain properties that were no longer part of our drilling plans.
There were no impairments of undeveloped properties during the year ended December 31, 2011.
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, 2013, the trailing 12 month reference prices were $3.67 per Mmbtu for
natural gas at Henry Hub, and $96.78 per Bbl of oil for West Texas Intermediate at Cushing, Oklahoma. The price used for
NGL's was $39.92 per Bbl and was based on the trailing 12 month average of realized prices. Each of the reference prices for
oil, natural gas and NGLs are further adjusted for quality factors and regional differentials to derive estimated future net
revenues. Under full cost accounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in
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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.
As of December 31, 2013 pursuant to Rule 4-10(c)(4) of Regulation S-X, we were required to compute the ceiling test
using the simple average spot price for the trailing 12 month period for oil and natural gas. The computation resulted in the
carrying costs of our unamortized proved oil and natural gas properties, exceeding the December 31, 2013 ceiling test
limitation by approximately $156.6 million, including the recently acquired Haynesville and Eagle Ford properties from
Chesapeake ("Chesapeake Properties"). Our pricing for the acquisitions of the Chesapeake Properties was based on models
which incorporate, among other things, market prices based on NYMEX futures as of the acquisition date. The ceiling test
requires companies using the full cost accounting method to price period-ending proved reserves using the simple average spot
price for the trailing 12 month period, which may not be indicative of actual market values. Given the short passage of time
between closing of these acquisitions and the required ceiling test computation, the Company requested, and received, an
exemption from the Securities and Exchange Commission ("SEC") to exclude the acquisition of the Chesapeake Properties
from the ceiling test assessments for a period of 12 months following the corresponding acquisition dates.
If we cannot demonstrate the fair value of the Chesapeake Properties exceeds the unamortized carrying costs during the
requested exemption periods prior to issuance of our financial statements, we are required to recognize an impairment. We
evaluated the Chesapeake Properties for impairment using discounted cash flow models based on internally generated oil and
natural gas reserves as of December 31, 2013. The Company's expectation of future prices is principally based on NYMEX
futures contracts, adjusted for basis differentials. We believe the NYMEX futures contract reflects an independent pricing point
for determining fair value.
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 years ended December 31, 2013, 2012 and 2011 we recognized impairments of $108.5 million, $1.3 billion and
$233.2 million, respectively, to our proved oil and natural gas properties.
Gathering assets
Gathering assets are capitalized at cost and depreciated on a straight line basis over their estimated useful lives of 20 to
40 years.
During 2011, we sold certain treating facilities in our Vernon Field and recognized a $6.8 million impairment to write the
book values down to the selling price.
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. 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. As a result of
91
testing, the fair value of our business exceeded the carrying value of net assets and we did not record an impairment charge for
the periods ending December 31, 2013, 2012 and 2011.
The contribution of oil and natural gas properties to the EXCO/HGI Partnership resulted in a significant alteration in our
depletion rate. 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. The balance of goodwill as of December 31,
2013 and 2012 was $163.2 million and $218.3 million, respectively.
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.
The following is a reconciliation of our asset retirement obligations for the periods indicated:
(in thousands)
2013
2012
2011
Asset retirement obligations at beginning of period
$
61,864
$
58,088
$
50,292
December 31,
Activity during the period:
Liabilities incurred during the period
Revisions in estimated assumptions
Liabilities settled during the period
Adjustment to liability due to acquisitions (1)
Adjustment to liability due to divestitures (2)
Accretion of discount
Asset retirement obligations at end of period
Less current portion
Long-term portion
514
1,268
(187)
5,566
(28,585)
2,514
42,954
191
971
—
(338)
—
(744)
3,887
61,864
1,200
$
42,763
$
60,664
$
3,765
—
(291)
1,684
(1,014)
3,652
58,088
732
57,356
(1) Adjustment to liability due to acquisitions consisted of $3.0 million from the acquisition of Eagle Ford assets, $1.9
million from our proportionate share of the EXCO/HGI Partnership acquisition of the Cotton Valley assets and $0.6
million from the acquisition of Haynesville assets.
(2) Adjustment to liability due to divestitures consisted primarily of $28.3 million from the contribution of our certain
conventional assets to the EXCHO/HGI Partnership.
Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not
readily available in public markets. 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, 2013, 2012 and 2011 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
92
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 $100.6 million, $102.9 million and $86.9 million for the years ended
December 31, 2013, 2012 and 2011, 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, 2013, 2012 and 2011, we capitalized $18.2 million, $22.5 million
and $22.9 million, respectively. The capitalized amounts include $7.3 million, $7.5 million and $6.4 million of share-based
compensation for the years ended December 31, 2013, 2012 and 2011, respectively.
Overhead reimbursement fees
We have classified fees from overhead charges billed to working interest owners of $10.5 million, $20.5 million and
$18.4 million, for the years ended December 31, 2013, 2012 and 2011, respectively, as a reduction of general and
administrative expenses in the accompanying Consolidated Statements of Operations. Our share of these charges was $5.8
million, $10.3 million and $9.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, and are classified
as oil and natural gas production costs.
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 the East Texas/North Louisiana JV and the Appalachia JV. In connection with the formation of the
EXCO/HGI Partnership, we entered into an agreement to perform certain operational, managerial, and administrative services.
The EXCO/HGI Partnership reimburses us for costs incurred in connection with the performance of these services based on an
agreed upon service fee. For the years ended December 31, 2013, 2012 and 2011, general and administrative expenses were
reduced by $26.8 million, $25.2 million and $29.1 million, respectively, for recoveries of fees for our personnel and services
provided to our joint ventures. 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 restricted stock awards. Diluted EPS
is computed in the same manner as basic EPS after assuming issuance of common stock for all potentially dilutive equivalent
shares, whether vested or exercisable.
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 and restricted stock, 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 or restricted stock.
Our 2005 Long-Term Incentive Plan, as amended ("2005 Incentive Plan") provides for the granting of options and other
equity incentive awards of our common stock in accordance with terms within the agreements. New shares will be issued for
93
any options exercised or awards granted. Under the 2005 Incentive Plan, we have only issued stock options and restricted
stock, although the plan allows for other share-based awards.
Recent accounting pronouncement
In February 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-04, Liabilities (Topic 405):
Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at
the Reporting Date ("ASU 2013-04"). ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of
obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the
reporting date, except for obligations addressed within existing guidance in GAAP. The update is effective for interim and
annual periods beginning after December 15, 2013 and is required to be applied retrospectively to all prior periods presented
for those obligations that existed upon adoption of ASU 2013-04. We do not expect our adoption of ASU 2013-04 to have an
impact on our consolidated financial condition and results of operations.
3.
Acquisitions, divestitures and other significant events
2013 Acquisitions, divestitures and other significant events
EXCO/HGI Partnership
On February 14, 2013, we formed the EXCO/HGI Partnership. 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 the EXCO/HGI Partnership, 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
the EXCO/HGI Partnership is 74.5%. The primary strategy of the EXCO/HGI Partnership is to exploit its current asset base
and acquire conventional producing oil and natural gas properties to enhance asset value and cash flow.
The contribution of oil and natural gas properties to the EXCO/HGI Partnership resulted in a significant alteration in our
depletion rate. 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, the EXCO/HGI Partnership entered into an agreement to purchase the remaining
shallow Cotton Valley assets within the East Texas/North Louisiana JV 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 the EXCO/HGI Partnership. The transaction closed on March 5, 2013 and was funded with borrowings
from the EXCO/HGI Partnership's credit agreement ("EXCO/HGI Partnership Credit Agreement").
Acreage 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. In addition to the
cash consideration received at closing, the purchaser agreed to fund our share of drilling and completion costs within the joint
venture area up to $18.9 million. As of December 31, 2013, there was approximately $5.1 million remaining under the carry.
On February 13, 2014, we entered into a purchase and sale agreement with the private party for the sale of our interest in
the joint venture including producing wells and undeveloped acreage for approximately $65.0 million, subject to customary
purchase price adjustments and the receipt of certain third-party consents. The effective date of the transaction will be January
1, 2014 and any amounts remaining under the drilling carry will be terminated upon closing of the acquisition. The transaction
is expected to close in the first half of 2014.
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
94
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. The acquisition added approximately 300 identified
locations to our drilling inventory. 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:
Purchase Price Allocation (in thousands):
Assets acquired:
Unproved oil and natural gas properties
Proved developed and undeveloped oil and natural gas properties
Liabilities assumed:
Accounts payable and accrued liabilities
Revenues and royalties payable
Asset retirement obligations
Total purchase price
Haynesville
Acquired Properties
Eagle Ford
Acquired Properties
$
2,319
$
282,918
—
(3,526)
(610)
$
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 their short-term nature. The revenues and royalties payable related to the Eagle Ford acquisition
will be settled outside of the final settlement statement in the first quarter of 2014. We have accrued for the revenues and
royalties payable as well as recorded a related receivable from Chesapeake based on our estimate of the expected settlement.
Pro forma results of operations - The following table reflects the unaudited pro forma results of operations as though the
acquisition of the Chesapeake Properties had occurred on January 1, 2012:
(in thousands, except for per share data)
Oil and natural gas revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
95
Year Ended December 31,
2013
2012
$
$
$
$
784,628
38,663
0.18
0.17
$
$
$
$
715,286
(1,398,169)
(6.52)
(6.52)
KKR Participation Agreement
In connection with closing the acquisition of the Eagle Ford assets, we entered into the 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 KKR 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.
The KKR Participation Agreement provides that EXCO and KKR will jointly fund future costs to develop the Eagle
Ford assets. With respect to each well drilled, EXCO will assign half of its undivided 50% interest in such well to KKR such
that KKR will fund and own 75% of each well drilled and EXCO will fund and own 25% of each well drilled. On a quarterly
basis, EXCO and KKR will determine the development plan covering the following 12 months. EXCO will be required to offer
to purchase KKR's 75% working interest in wells drilled that have been on production for one year. These offers will be made
on a quarterly basis for groups of wells at a price defined in the KKR Participation Agreement, subject to specific well criteria
and return hurdles. KKR is required to accept the offer if it exceeds the required return. We are required to make our first offer
during the first quarter of 2015 for wells that have been on-line for approximately one year.
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%. For further discussion see "Note 14. Equity investments".
2012 Acquisitions, divestitures and other significant events
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.
2011 Acquisitions, divestitures and other significant events
Chief transaction
On December 21, 2010, we funded the acquisition of undeveloped acreage and oil and natural gas properties in the
Marcellus shale from Chief Oil & Gas LLC and related parties for approximately $459.4 million, subject to post-closing title
adjustments and customary post-closing purchase price adjustments ("Chief Transaction"). The $459.4 million preliminary
purchase price was initially funded into an escrow account pending receipt of a waiver from a third party, which was received
on January 11, 2011. Upon receipt of that waiver, the properties were released to us. On February 7, 2011, BG Group elected to
participate in the Chief Transaction and funded $229.7 million for their 50% share of the preliminary purchase price. During
the third quarter of 2011 we completed post-closing adjustments on the Chief Transaction resulting in a final purchase price of
$454.4 million ($227.2 million net to us).
Appalachia transaction
On March 1, 2011, we jointly closed the purchase of Marcellus shale acreage with BG Group, which also included
certain shallow production primarily in Jefferson and Clarion counties in Pennsylvania for $82.0 million ($41.0 million net to
us).
Haynesville shale acquisition
On April 5, 2011, we purchased land, mineral interests and other assets in DeSoto Parish, Louisiana for $225.2 million.
On May 12, 2011, BG Group elected to participate for its 50% share of the transaction and funded us $112.6 million.
TGGT incident
During May 2011, an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana
resulting in an immediate shut-down of the facility. The facility was placed back into service late in the first quarter of 2012.
TGGT recognized impairments related to the facility in 2012 totaling $34.9 million ($17.4 million net to us). The impairments
reduced equity income.
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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 charges or gains only arise from payments made or received on monthly settlements of contracts or if we
terminate a contract prior to its expiration.
We account for our derivative financial instruments in accordance with ASC 815, which 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 fair value. ASC 815 requires that changes in the derivative’s 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 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 Consolidated Balance Sheets
and their financial impact in our 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,
2013
December 31,
2012
$
8,226
$
49,500
6,829
(11,919)
(9,671)
(6,535) $
16,554
(2,396)
(26,369)
37,289
$
The Effect of Derivative Financial Instruments
(in thousands)
Gain (loss) on derivative financial instruments
Year Ended December 31,
2013
2012
2011
$
(320) $ 66,133
$ 219,730
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 Consolidated Balance Sheets fair value amounts.
Our oil and natural gas derivative instruments are comprised of swap, basis swap and call option contracts. Swap
contracts allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. Basis
swap 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 West Texas Intermediate oil prices ("WTI"). Call options
are financial contracts that 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.
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 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. We proportionately consolidate the derivative
financial instruments entered into by the EXCO/HGI Partnership, however the contracts of the EXCO/HGI Partnership involve
separate master netting agreements with their counterparties and we are not liable in the event of default.
97
The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments
(including our 25.5% proportionate interest in the EXCO/HGI Partnership's derivative financial instruments) as of
December 31, 2013:
(in thousands, except prices)
Natural gas:
Swaps:
2014
2015
Call options:
2014
2015
Total natural gas
Oil:
Swaps:
2014
2015
Basis Swaps
2014
2015
Calls options:
2014
2015
Total oil
Total oil and natural gas derivative financial instruments
Volume Mmbtu/
Bbl
Weighted average
strike price per
Mmbtu/Bbl
Fair value at
December 31,
2013
84,060
$
28,288
20,075
20,075
1,644
$
548
183
91
365
365
4.22
4.31
4.29
4.29
95.03
91.78
6.03
6.10
100.00
100.00
$
$
$
2,941
4,742
(4,581)
(7,017)
(3,915)
(1,555)
1,079
411
242
(909)
(1,888)
(2,620)
(6,535)
At December 31, 2012, we had outstanding derivative contracts to mitigate our exposure to price volatility covering
216,263 Mmmbtu of natural gas and 1,095 Mbbls of oil. At December 31, 2013, the average forward NYMEX WTI oil prices
per Bbl for the calendar years 2014 and 2015 were $96.14, and $88.75, respectively, the average forward NYMEX Louisiana
Light Sweet ("LLS"), oil prices per barrel for the calendar years 2014 and 2015 were $99.90, and $92.18, respectively, and the
average forward NYMEX Henry Hub natural gas prices per Mmbtu for the calendar years 2014 and 2015 were $4.17 and
$4.14, respectively.
Our derivative financial instruments covered approximately 57% and 44% of production volumes for the years ended
December 31, 2013 and 2012.
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:
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.
98
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 for such assets
or liabilities. During the years ended December 31, 2013 and 2012 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,
2013 and 2012.
(in thousands)
Oil and natural gas derivative financial instruments
(in thousands)
Oil and natural gas derivative financial instruments
December 31, 2013
Level 1
Level 2
Level 3
Total
— $
(6,535) $
— $
(6,535)
December 31, 2012
Level 1
Level 2
Level 3
Total
— $
37,289
$
— $
37,289
$
$
We evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative
counterparties, but report them on a gross basis on the Consolidated Balance Sheets. Net derivative asset values are determined
primarily by quoted futures prices and utilization of the counterparties’ credit-adjusted risk-free rate curves and net derivative
liabilities are determined by utilization of our credit-adjusted risk-free rate curve or the credit-adjusted risk-free rate curve of
the EXCO/HGI Partnership. The credit-adjusted risk-free rates of our counterparties are based on an independent market-
quoted credit default swap rate curve for the counterparties’ debt plus the London Interbank Offered Rate ("LIBOR") curve as
of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted
credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the
reporting period. In addition, the credit-adjusted risk-free rate for the EXCO/HGI Partnership is based on the cost of debt plus
the LIBOR curve as of the end of the reporting period.
The valuation of our commodity price derivatives, represented by oil and natural gas swaps, basis swaps and call option
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 estimated 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 and call option contracts for notional Mmbtus of natural
gas at posted price indexes, including NYMEX Henry Hub ("HH") swap and call 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 call 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.
The carrying values of our borrowings under the revolving commitment of the EXCO Resources Credit Agreement and
EXCO/HGI Partnership Credit Agreement approximate fair value, as these are subject to short-term floating interest rates that
approximate the rates available to us for those periods.
The estimated fair values of our 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes") and the term loan
under the EXCO Resources Credit Agreement ("Term Loan"), at December 31, 2013 and December 31, 2012 are presented
below. The estimated fair values of the 2018 Notes and the Term Loan have been calculated based on market quotes.
99
(in thousands)
2018 Notes
Term Loan
(in thousands)
2018 Notes
December 31, 2013
Level 1
Level 2
Level 3
Total
$
714,000
$
298,500
— $
—
— $
714,000
—
298,500
December 31, 2012
Level 1
Level 2
Level 3
Total
$
716,250
$
— $
— $
716,250
Other fair value measurements
We recorded an other than temporary impairment of $86.8 million to our investment in TGGT in 2013 as a result of the
carrying value exceeding the fair value. We considered third-party offers in determining the fair value. The inputs used in
determining the fair value as part of the impairment calculation are considered to be Level 2 within the fair value hierarchy.
See further discussion of our investment in TGGT in "Note 14. Equity investments".
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
Total debt excluding the EXCO/HGI Partnership
EXCO/HGI Partnership Credit Agreement
Total debt
Less amounts due within one year
Total debt due after one year
December 31,
2013
December 31,
2012
$
763,866
$
1,107,500
298,500
(2,780)
750,000
(7,293)
—
—
750,000
(8,528)
1,802,293
1,848,972
88,485
—
1,890,778
1,848,972
31,866
—
$
1,858,912
$
1,848,972
Terms and conditions of each of these debt obligations are discussed below.
EXCO Resources Credit Agreement
On July 31, 2013, we amended and restated the EXCO Resources Credit Agreement which increased our borrowing base
to $1.6 billion, including a $1.3 billion revolving commitment and a $300.0 million term loan commitment. The amendment to
the EXCO Resources Credit Agreement included a $400.0 million asset sale requirement which was eliminated as a result of
the repayment of outstanding borrowings in January 2014. The maturity date of the revolving commitment of the EXCO
Resources Credit Agreement is July 31, 2018.
On August 19, 2013, the EXCO Resources Credit Agreement was amended to reflect a term loan that ranks pari passu in
right of payment and of security with the revolving loans. The term loan has a maturity date of August 19, 2019 unless a
permitted refinancing of the 2018 Notes does not occur prior to March 15, 2018, in which case the term loan will have a
maturity date of July 31, 2018. We have scheduled principal payments on the term loan in the amount of $0.8 million due and
payable on the last day of March, June, September and December of each year beginning on September 30, 2013. As of
December 31, 2013, $298.5 million in principal was outstanding on the term loan. The unamortized discount on the term loan
at December 31, 2013 was $2.8 million.
Proceeds from the sale of properties under the KKR Participation Agreement on July 31, 2013 and proceeds from the
sale of our equity interest in TGGT on November 15, 2013 were used to reduce outstanding borrowings under the EXCO
Resources Credit Agreement. After giving effect to these transactions, the EXCO Resources Credit Agreement borrowing base
and outstanding borrowings were reduced by $371.1 million and our asset sale requirement was reduced to $28.9 million as of
December 31, 2013. As discussed in "Note 17. Rights Offering", on January 17, 2014, we received proceeds of $272.9 million
100
from the rights offering of our common stock ("Rights Offering"), which we used to pay down the remaining indebtedness
related to the asset sale requirement as well as a portion of the indebtedness outstanding under the revolving commitment under
the EXCO Resources Credit Agreement. Upon repayment of the asset sale requirement, the interest rate on the revolving
commitment decreased by 100 basis points. After giving effect to the Rights Offering and the related transactions, the available
borrowing base on the revolving commitment under the EXCO Resources Credit Agreement was $900.0 million with
approximately $491.0 million of outstanding indebtedness and approximately $402.1 million of unused borrowing base, net of
letters of credit.
As of December 31, 2013, the revolving commitment under the EXCO Resources Credit Agreement had an available
borrowing base of approximately $928.9 million, with $763.9 million of outstanding indebtedness and $158.1 million of
unused borrowing base, net of letters of credit.
Under the EXCO Resources Credit Agreement, the next borrowing base redetermination for the revolving commitment
will occur in April 2014. Subsequent redeterminations will occur semi-annually with us and the lenders having the right to
request interim unscheduled redeterminations in certain circumstances. The interest rate grid for the revolving commitment
under the EXCO Resources Credit Agreement ranges from LIBOR plus 175 bps to 275 bps (or alternate base rate ("ABR") plus
75 bps to 175 bps), depending on our borrowing base usage. The interest rate grid was increased by 100 bps per annum until
the asset sale requirement was eliminated in January 2014. On December 31, 2013, the one month LIBOR was 0.2%, which
resulted in an interest rate of approximately 3.7% on the revolving commitment. The term loan bears interest at LIBOR, with a
floor of 100 bps, plus 400 bps (or ABR plus 300 bps). The interest rate on the term loan was approximately 5.0% as of
December 31, 2013.
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 stock, of which $7.5 million has been
repurchased to date. The repurchase of our common stock was prohibited until the asset sale requirement was eliminated in
January 2014. There were no share repurchases during 2013, 2012 and 2011.
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 stock and provides that we may declare and pay cash dividends on our common stock in an amount
not to exceed a cumulative total of $50.0 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.
As of December 31, 2013, we were in compliance with the financial covenants contained in the EXCO Resources Credit
Agreement, which require that we:
• maintain a consolidated current ratio (as defined in the EXCO Resources Credit Agreement) of at least 1.0 to 1.0 as
•
of the end of any fiscal quarter; and
not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO
Resources Credit Agreement) to be greater than 4.5 to 1.0 at the end of any fiscal quarter.
The amendment to the EXCO Resources Credit Agreement also added that a breach of any financial covenants with
respect to any term loans shall not be considered an event of default unless the aggregate revolving loans and letters of credit
then outstanding is equal to or greater than $10.0 million and until the earlier of: (i) 90 days after the date such event of default
arises, unless waived by the revolving lenders having a revolving exposure representing at least 66 2/3% of the aggregate
revolving loans, letters of credit and unused commitments prior to such 90th day, and (ii) the date on which the administrative
agent or such revolving lenders cause such indebtedness to become due prior to July 31, 2018.
While we believe our existing capital resources, including our cash flow from operations and borrowing capacity under
the EXCO Resources Credit Agreement are sufficient to conduct our operations through 2014 and into 2015, there are certain
risks arising from depressed oil and natural gas prices and declines in production volumes that could impact our ability to meet
101
debt covenants in future periods. In particular, our ratio of consolidated funded indebtedness to consolidated EBITDAX, as
defined in the EXCO Resources Credit Agreement, is computed using the trailing 12 month EBITDAX and only includes
operations from non-guarantor subsidiaries and unconsolidated joint ventures to the extent that cash is distributed to entities
under the credit agreement. As a result, our ability to maintain compliance with this covenant may be negatively impacted when
oil and/or natural gas prices remain depressed for an extended period of time.
2018 Notes
The 2018 Notes are guaranteed on a senior unsecured basis by a majority of EXCO’s subsidiaries, with the exception of
certain non-guarantor subsidiaries, our jointly-held equity investments with BG Group and the EXCO/HGI Partnership. 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, 2013, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on
the 2018 Notes at December 31, 2013 was $7.3 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 stock;
pay dividends on our capital stock (over $50.0 million per annum) 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.
•
EXCO/HGI Partnership Credit Agreement
In connection with its formation, the EXCO/HGI Partnership entered into the EXCO/HGI Partnership Credit Agreement
with an initial borrowing base of $400.0 million, of which $230.0 million was drawn at closing. The EXCO/HGI Partnership
entered into the First Amendment to the EXCO/HGI Partnership Credit Agreement on March 5, 2013, which increased the
borrowing base to $470.0 million as a result of the acquisition of the shallow Cotton Valley assets from an affiliate of BG
Group. The borrowing base is redetermined semi-annually, with the EXCO/HGI Partnership and the lenders having the right to
request interim unscheduled redeterminations in certain circumstances. On December 3, 2013, the borrowing base was reduced
to $400.0 million in conjunction with the semi-annual redetermination. The EXCO/HGI Partnership Credit Agreement matures
on February 14, 2018.
Borrowings under the EXCO/HGI Partnership Credit Agreement are secured by properties owned by the EXCO/HGI
Partnership and we do not guarantee the EXCO/HGI Partnership's debt. The EXCO/HGI Partnership is not a guarantor to the
EXCO Resources Credit Agreement or the 2018 Notes. As of December 31, 2013, $347.0 million was drawn under this
agreement and our proportionate share of the obligation was $88.5 million. The interest rate grid ranges from LIBOR plus 175
bps to 275 bps (or ABR plus 75 bps to 175 bps), depending on the percentages of drawn balances to the borrowing base as
defined in the agreement. On December 31, 2013, the interest rate on the outstanding borrowings was approximately 2.7%.
Borrowings under the EXCO/HGI Partnership 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 EXCO/HGI Partnership Credit Agreement, of
the oil and natural gas properties evaluated by the lenders for purposes of establishing the borrowing base. The EXCO/HGI
Partnership is permitted to have derivative financial instruments covering no more than 100% of the forecasted production from
proved developed producing reserves (as defined in the agreement) for any month during the first two years of the forthcoming
five year period, 90% of the forecasted production from proved developed producing reserves for any month during the third
year of the forthcoming five year period and 85% of the forecasted production from proved developed producing reserves for
any month during the fourth and fifth years of the forthcoming five year period.
102
As of December 31, 2013, the EXCO/HGI Partnership was in compliance with the financial covenants contained in the
EXCO/HGI Partnership Credit Agreement, which require that it:
• maintain a consolidated current ratio (as defined in the agreement) of at least 1.0 to1.0 as of the end of any fiscal
•
quarter; and
not permit the ratio of consolidated funded indebtedness (as defined in the agreement) to consolidated EBITDAX
(as defined in the agreement) to be greater than 4.5 to1.0 at the end of any fiscal quarter.
The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit
Agreement, the indenture governing the 2018 Notes and the EXCO/HGI Partnership Credit Agreement.
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
We lease our offices and certain equipment. Our rental expenses were approximately $5.9 million, $6.8 million and $8.2
million for the years ended December 31, 2013, 2012 and 2011, respectively. We have also entered into various drilling rig
contracts primarily to develop our Haynesville and Eagle Ford shale assets. These contracts are short-term in nature and are
dependent on our planned drilling program.
We have entered into firm transportation agreements with pipeline companies to facilitate sales from our Haynesville
shale production and report these firm transportation costs as a component of gathering and transportation expenses. At the end
of 2013, our firm transportation agreements covered an average of 1.1 Bcf per day through 2016, with average annual
minimum gathering and transportation expenses of approximately $135.3 million per year. For the years 2017 through 2021,
our firm transportation agreements range from covering an average of 1.0 Bcf per day in 2017 and trend down to 333 Mmcf per
day in 2021, with average annual minimum gathering and transportation expenses ranging from approximately $132.9 million
per year in 2017 and trending down to $40.7 million in 2021. These volumes and expenses represent our gross commitments
under these contracts and a portion of these costs will be incurred by other working interest owners. 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.
Our future minimum obligations under these agreements for office and equipment leases, drilling rig contracts, firm
transportation services and other fixed commitments at December 31, 2013 are presented in the table below. The commitments
do not include those of our equity method investments.
(in thousands)
Firm transportation
services
Other fixed
commitments
Drilling contracts
Operating leases and
other
Total
2014
2015
2016
2017
2018
Thereafter
Total
$
136,376
$
14,532
$
40,286
$
8,055
$
136,040
133,429
132,860
129,140
190,678
17,299
13,226
5,428
3,197
5,929
—
—
—
—
—
4,978
1,558
140
—
—
$
858,523
$
59,611
$
40,286
$
14,731
$
199,249
158,317
148,213
138,428
132,337
196,607
973,151
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.
103
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 matched 100% of employee contributions. Our matching contributions
were $8.8 million, $9.4 million and $9.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.
10.
Earnings per share
We account for earnings per share in accordance with ASC 260-10 which requires companies to present two calculations
of EPS: basic and diluted. Basic EPS for the years ended December 31, 2013, 2012 and 2011 equals the net income divided by
the weighted average common shares outstanding during the periods. Weighted average common shares outstanding is equal to
the weighted average of all shares outstanding for the period, excluding restricted stock awards. Diluted EPS for the years
ended December 31, 2013, 2012 and 2011 is computed in the same manner as basic earnings per share after assuming the
issuance of common stock for all potentially dilutive common stock equivalents, which include stock options, restricted stock
awards and subscription rights, whether exercisable or not. The computation of diluted EPS excluded 55,524,191, 17,242,306
and 7,251,289 antidilutive common share equivalents for the years ended December 31, 2013, 2012 and 2011, respectively.
The antidilutive common share equivalents for the year ended December 31, 2013 primarily consisted of subscription rights
outstanding as well as out-of-the-money stock options. The antidilutive common share equivalents for the years ended
December 31, 2012 and 2011 primarily related to out-of-the-money stock options.
The following table presents the basic and diluted earnings (loss) per share computations for the years ended
December 31, 2013, 2012 and 2011:
(in thousands, except per share data)
Basic net income (loss) per common share:
Net income (loss)
Weighted average common shares outstanding
Net income (loss) per basic common share
Diluted net income (loss) per common share:
Net income (loss)
Weighted average common shares outstanding
Dilutive effect of:
Stock options
Restricted shares
Subscription rights
Weighted average common shares and common share equivalents outstanding
Year Ended December 31,
2013
2012
2011
$
$
$
22,204
$
(1,393,285) $
215,011
214,321
0.10
$
(6.50) $
22,204
$
(1,393,285) $
215,011
214,321
—
420
15,481
230,912
—
—
—
214,321
22,596
213,908
0.11
22,596
213,908
2,797
—
—
216,705
0.10
Net income (loss) per diluted common share
$
0.10
$
(6.50) $
11.
Stock options and awards
Description of plan
As of December 31, 2013 and 2012, there were 21,118,292 and 2,682,249 shares, respectively, available for issuance
under the 2005 Incentive Plan. Under the plan we grant both options and restricted stock. Effective June 11, 2013, our
shareholders voted to increase the total shares authorized for issuance under the 2005 Incentive Plan from 28,500,000 to
45,500,000 shares, increasing the number of shares available for grant by 17,000,000. Option grants count as one share against
the total number of shares we have available for grant and restricted stock 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 stock have voting rights and upon vesting the right to receive all accrued and unpaid dividends.
104
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 and restricted stock awards as of December 31,
2013 was $23.6 million. Of this amount, $7.0 million related to unvested options will be recognized over a weighted average
period of 2.5 years and $16.6 million related to unvested restricted stock awards will be recognized over a weighted average
period of 2.1 years.
The following is a reconciliation of our share-based compensation expense for the years ended December 31, 2013, 2012
and 2011:
(in thousands)
2013
2012
2011
General and administrative expense
Lease operating expense
Total share-based compensation expense
Share-based compensation capitalized
Total share-based compensation
$
$
10,748
$
8,926
$
—
10,748
7,288
—
8,926
7,513
18,036
$
16,439
$
10,872
140
11,012
6,406
17,418
Year Ended December 31,
The total tax benefit attributable to our share-based compensation for the year ended December 31, 2011 was $1.2
million. We did not recognize a tax benefit attributable to our share-based compensation for the years ended December 31,
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 5.1 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.
105
The following table summarizes stock option activity related to our employees under the 2005 Incentive Plan for the
years ended December 31, 2013, 2012 and 2011:
Stock Options
Weighted average
exercise price per
share
Weighted average
remaining terms
(in years)
Aggregate
intrinsic value
Options outstanding at
December 31, 2010
Granted
Forfeitures
Exercised
Options outstanding at
December 31, 2011
Granted
Forfeitures
Exercised
Options outstanding at
December 31, 2012
Granted
Forfeitures
Exercised
Options outstanding at
December 31, 2013
Options exercisable at
December 31, 2013
16,478,926
$
831,600
698,700
941,658
15,670,168
146,500
1,543,933
256,940
14,015,795
2,886,500
4,969,877
220,675
11,711,743
9,839,918
$
$
13.68
11.79
17.88
12.81
13.44
8.00
16.12
7.66
13.20
7.48
11.32
7.66
12.69
13.64
5.1
4.3
$
$
—
—
The weighted average fair value of stock options on the date of the grant during the years ended December 31, 2013,
2012 and 2011 was $3.53, $3.96 and $5.92, respectively. The total intrinsic value of stock options exercised for the years ended
December 31, 2013, 2012 and 2011 was $0.2 million, $0.1 million and $6.0 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 stock 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
Risk-free rate of return
Volatility
Dividend yield
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 %
2011
3.8 to 7.5 years
0.67 - 3.09 %
55.77 - 72.83 %
0.77 - 1.15 %
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
stock 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 stock awards
Our service-based restricted stock awards are valued at the closing price of our stock on the date of grant and vest over a
range of three to five years. A summary of our service-based restricted stock activity for the years ended December 31, 2013,
2012 and 2011 are as follows:
106
Non-vested shares outstanding at December 31, 2010
Granted
Vested
Forfeited
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
Market-based restricted stock awards
Shares
Weighted average grant date fair
value per share
— $
2,589,709
—
(27,300)
2,562,409
$
926,900
(370,448)
(312,496)
2,806,365
$
556,700
(832,706)
(602,045)
1,928,314
$
—
11.75
—
14.71
11.72
7.57
12.89
11.89
10.16
7.15
10.47
9.84
9.26
On August 13, 2013, EXCO’s officers were granted a market-based restricted stock award for shares of common stock.
The total number of units 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 units will be vested following any 30
consecutive trading days in which the company’s common stock equals or exceeds $15.00 per share. Shares vest over a two
year period and are subject to other vesting provisions depending on when the attainment date occurs.
The grant date fair value of our market-based restricted stock awards was determined using a Monte Carlo model which
uses company-specific inputs to generate different stock price paths. A summary of our market-based restricted stock activity
for the year ended December 31, 2013 is as follows:
Non-vested shares outstanding at December 31, 2012
Granted
Vested
Forfeited
Non-vested shares outstanding at December 31, 2013
12.
Income taxes
Shares
Weighted average grant date fair
value per share
— $
736,000
—
(261,400)
474,600
$
—
6.36
—
6.36
6.36
The income tax provision attributable to our income (loss) before income taxes for the years ended December 31, 2013,
2012 and 2011, consisted of the following:
107
(in thousands)
Current:
Federal
State
Total current income tax (benefit)
Deferred:
Federal
State
Valuation allowance
Total deferred income tax (benefit)
Total income tax (benefit)
Year ended December 31,
2013
2012
2011
$
$
$
$
— $
—
— $
— $
—
— $
25,626
$
(485,543) $
3,239
(28,865)
—
— $
(59,406)
544,949
—
— $
—
—
—
10,111
1,554
(11,665)
—
—
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 2033. NOL and alternative minimum
tax credits available for utilization as of December 31, 2013 were approximately $1.9 billion and $1.5 million, respectively.
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 asset (liabilities):
Derivative financial instruments
Other
Valuation allowance
Net current deferred tax assets (liabilities)
Non-current deferred tax assets:
December 31,
2013
December 31,
2012
$
— $
5,332
(5,332)
—
—
152
(152)
—
604,437
11,173
398,350
6,291
—
—
85
1,020,336
(919,986)
100,350
(4,931)
(80,825)
(14,594)
(100,350)
—
Net operating loss and AMT credits carryforwards
$
737,399
$
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:
Oil and natural gas properties, gathering assets, and equipment
Investments in partnerships
Derivative financial instruments
Total non-current deferred tax liabilities
Net non-current deferred tax assets (liabilities)
16,060
47,491
9,812
2,102
73,328
85
886,277
(886,277)
—
$
$
— $
—
—
—
— $
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, 2013, 2012 and 2011 is presented in the
108
following table:
(in thousands)
Year Ended December 31,
2013
2012
2011
Federal income taxes (benefit) provision at statutory rate of 35%
$
7,772
$
(487,649) $
7,909
Increases (reductions) resulting from:
Goodwill
Adjustments to the valuation allowance
Non-deductible compensation
State taxes net of federal benefit
Other
Total income tax provision
16,382
(28,865)
1,328
3,239
144
$
— $
—
544,949
1,893
(59,406)
213
— $
—
(11,665)
1,760
1,554
442
—
During 2013, our taxable income was offset by utilization of net operating losses and a corresponding decrease to
previously recognized valuation allowances against deferred tax assets. The net result was no income tax provision for 2013.
During 2012, our net loss was greatly impacted by the ceiling test impairments 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.
During 2011, our taxable income was offset by utilization of net operating losses and a corresponding decrease to
previously recognized valuation allowances against deferred tax assets. The net result was no income tax provision for 2011.
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, 2013, 2012 and 2011, 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 income tax returns in the U.S. federal jurisdictions and various state jurisdictions. With few exceptions, we are
no longer subject to U.S. federal and state and local examinations by tax authorities for years before 2005. 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.
13.
Related party transactions
TGGT and OPCO
TGGT provided us with gathering, treating and well connection services in the ordinary course of business as well as
purchased natural gas from us in certain areas. Also, we previously provided administrative services to TGGT for which we
were reimbursed. On November 15, 2013, we sold our equity investment in TGGT to Azure. See further discussion of this
transaction in "Note 14. Equity Investments". Transactions with Azure after November 15, 2013 are not included in the tables
below as Azure no longer meets the disclosure requirements as a related party. OPCO serves as the operator of our wells in the
Appalachia JV. 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, 2013, 2012 and 2011 these transactions included the following:
109
(in thousands)
Amounts paid:
Year Ended December 31,
2013
2012
2011
TGGT
OPCO
TGGT
OPCO
TGGT
OPCO
Gathering, treating and well connection fees (1)
$ 160,167
$
— $ 218,902
$
— $ 199,449
$
—
Advances to operator
Total
Amounts received:
Natural gas purchases
—
28,378
—
76,729
—
69,111
$ 160,167
$ 28,378
$ 218,902
$ 76,729
$ 199,449
$ 69,111
$
7,251
$
— $ 15,340
$
— $ 27,948
$
—
General and administrative services
18,413
43,632
18,258
52,206
15,730
47,337
Purchase of gathering and other assets
Other
Total
—
52
—
—
—
1,905
—
—
3,422
2,147
—
—
$ 25,716
$ 43,632
$ 35,503
$ 52,206
$ 49,247
$ 47,337
(1) Represents the gross billings from TGGT.
As of December 31, 2013 and 2012, the amounts owed under the service agreements were as follows:
(in thousands)
Amounts due to EXCO
Amounts due from EXCO (1)
December 31, 2013
December 31, 2012
OPCO
TGGT
OPCO
$
2,283
$
2,483
$
2,956
—
12,540
—
(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 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
As discussed in "Note 6. Debt", the EXCO Resources Credit Agreement was amended to reflect a term loan on August
19, 2013. Investment accounts managed by Invesco Advisers, Inc. are lenders under the term loan. Invesco Advisers, Inc. is an
indirect owner of WL Ross & Co. LLC. Wilbur L. Ross, Jr., the Chairman and Chief Executive Officer at WL Ross & Co. LLC,
serves on EXCO’s board of directors. Invesco Advisers, Inc. holds approximately 10% of total borrowings under the term loan
and does not act as an administrative agent or serve in any other administrative capacity to the EXCO Resources Credit
Agreement. After giving effect to the closing of the Rights Offering and related private placement, as discussed in "Note 17.
Rights Offering", investment entities managed by WL Ross & Co. LLC beneficially own approximately 18.7% of EXCO’s
outstanding shares of common stock.
14.
Equity investments
We hold equity investments in entities which are described below.
• We own a 50% interest in OPCO, which operates the Appalachia JV properties, subject to oversight from a
management board having equal representation from EXCO and BG Group. We use the equity method of
accounting for our equity investment in OPCO.
• We own a 50% interest in the Appalachia Midstream JV, which holds interests in midstream assets in the Marcellus
shale. We use the equity method of accounting for our equity investment in Appalachia Midstream JV.
• We own a 50% interest in an entity that manages certain surface acreage which is accounted for by the equity
method of accounting.
• We own approximately 4% of the equity interests in Azure which holds interests in midstream assets in East Texas
and North Louisiana. We use the cost method of accounting for our equity investment in Azure. We previously
110
owned a 50% interest in TGGT, which held interests in midstream assets in East Texas and North Louisiana. We
sold our equity investment in TGGT to Azure on November 15, 2013, which is described below.
On November 15, 2013, EXCO and BG Group closed the conveyance of 100% of the equity interests in TGGT to Azure
for an aggregate sales price of approximately $910.0 million, of which approximately $876.5 million was paid in cash and the
remaining portion was paid in the form of an equity interest in Azure, which was split equally between EXCO and BG Group.
The equity interest issued to EXCO is approximately 4% of the total outstanding equity interests of Azure as of the closing
date. EXCO and BG Group were also granted an option for a period of one year to acquire an additional equity interest in
Azure equal to the equity interest issued at closing for approximately $16.8 million plus a premium that will increase over time.
After the repayment of TGGT's indebtedness as of the closing date, we received $240.2 million in net cash proceeds
from Azure after final purchase price adjustments. We also incurred expenses of $3.6 million to third-parties in connection with
the transaction which primarily consisted of commissions and financial advisory fees. We recorded an equity investment of
$13.4 million, net of a discount for a control premium, in Azure which will be 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 asset sale
requirement of the EXCO Resources Credit Agreement, which also resulted in a corresponding reduction in our borrowing
base. 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.
The following tables present summarized consolidated financial information of our equity method investments and a
reconciliation of our investment to our proportionate 50% interest. Our equity investment in Azure is not included in the tables
below as it is accounted for under the cost method of accounting.
(in thousands)
Assets
Total current assets
Property and equipment, net
Other assets
Total assets
Liabilities and members’ equity
Total current liabilities
Total long term liabilities
Members’ equity:
Total members' equity
Total liabilities and members’ equity
December 31,
2013
December 31,
2012
$
$
$
78,437
$
151,098
73,451
1,041
152,929
63,043
258
$
$
1,228,231
6,408
1,385,737
120,408
492,071
89,628
773,258
$
152,929
$
1,385,737
111
(in thousands)
Revenues:
Oil and natural gas
Midstream
Total revenues
Costs and expenses:
Oil and natural gas production
Midstream operating
Impairment of oil and natural gas properties
Asset impairments, net of insurance recoveries
General and administrative
Depletion, depreciation and amortization
Other expenses
Total costs and expenses
Income before income taxes
Income tax expense
Net income
EXCO’s share of equity income before amortization and impairment
Amortization of the difference in the historical basis of our contribution
Impairment of equity investment
EXCO’s share of equity income (loss) after amortization and impairment
$
(in thousands)
Equity method investments
Basis adjustment (1)
Cumulative amortization of basis adjustment (2)
EXCO’s 50% interest in equity method investments
Year Ended December 31,
2013
2012
2011
$
776
$
456
$
524
188,882
189,658
289
52,086
—
7,246
12,638
40,409
12,961
125,629
64,029
361
63,668
31,834
$
$
1,670
(86,784)
(53,280) $
253,586
254,042
234
69,682
1,230
50,771
24,593
40,570
13,049
200,129
53,913
425
53,488
26,744
1,876
—
$
$
242,366
242,890
55
108,116
1,445
9,688
19,597
28,482
13,211
180,594
62,296
636
61,660
30,830
1,876
—
28,620
$
32,706
December 31,
2013
December 31,
2012
$
$
44,162
$
1,618
(966)
44,814
$
347,008
45,755
(6,134)
386,629
$
$
(1) Our equity in TGGT and OPCO, at inception, exceeded the book value of our investments by an aggregate of $45.8
million, comprised of an aggregate $57.2 million difference in the historical basis of our contribution and the fair value of
BG Group’s contribution, offset by $11.4 million of goodwill included in our investment in TGGT. The basis difference
in our investment in TGGT was eliminated as a result of the sale during 2013. The December 31, 2013 basis adjustment
reflects OPCO's difference in historical basis.
The basis difference is being amortized over the estimated life of the associated assets.
(2)
15.
Dividends
On November 21, 2013, our board of directors approved a cash dividend of $0.05 per share for the fourth quarter of
2013. The total cash dividend was $10.9 million, of which $10.8 million was paid on December 16, 2013 to holders of record
on December 2, 2013 and the remainder was accrued to be paid to holders of restricted shares upon vesting. Total dividends
paid to our shareholders in 2013, 2012 and 2011 were $43.2 million, $34.4 million, and $34.2 million, respectively.
Any future declaration of dividends, as well as the establishment of record and payment dates, is subject to limitations
under the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and the approval of our board of
directors.
16.
Share repurchase
On July 19, 2010, we announced a share repurchase program which authorizes us to purchase up to $200.0 million of
our common stock. Any repurchases will be made in the open market, in privately negotiated transactions or in structured share
112
repurchase programs, and may be made from time to time and in one or more large repurchases. The program is conducted in
compliance with the Rule 10b-18 under the Exchange Act and applicable legal requirements and is subject to market conditions
and other factors. EXCO is not obligated to repurchase any common stock, or any particular amount of common stock, and the
repurchase program may be modified or suspended at any time at EXCO's discretion. The repurchase of our common stock was
prohibited until the asset sale requirement of the EXCO Resources Credit Agreement was eliminated in January 2014. As of
December 31, 2013, we have repurchased a total of 539,221 shares for $7.5 million at an average price of $13.87 per share.
There were no share repurchases during 2013, 2012 or 2011.
17.
Rights Offering
On December 19, 2013, the Company granted subscription rights to holders of common stock 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 stock 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 common stock that other rights holders do
not purchase through the purchase of their basic subscription rights at a subscription price equal to $5.00 per share of common
stock. 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.
18.
Condensed consolidating financial statements
As of December 31, 2013, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit
Agreement and the indenture governing the 2018 Notes. All of our non-guarantor subsidiaries were considered unrestricted
subsidiaries under the indenture governing the 2018 Notes, with the exception of our equity investment in OPCO. As of and for
the year ended December 31, 2013 our equity method investment in OPCO represented $12.9 million of equity method
investments and contributed $4.7 million of equity method losses.
Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-
guarantor subsidiaries. The 2018 Notes, 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 are 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.
113
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2013
(in thousands)
Assets
Current assets:
Cash and cash equivalents
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 equipment, net
Investments in and advances to affiliates, net
Deferred financing costs, net
Derivative financial instruments
Goodwill
Other assets
Total assets
Liabilities and shareholders' equity
Current liabilities
Long-term debt
Deferred income taxes
Other long-term liabilities
Payable to parent
Total shareholders' equity
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
$
81,840
$
(35,892) $
4,535
$
— $
—
22,533
104,373
—
20,570
206,708
191,386
—
—
5,560
10,095
57,562
6,758
415,290
3,259
337,972
3,097,335
(330,086)
(1,840,332)
14,644
3,479
1,834,197
27,771
6,829
13,293
2
1,672,293
24,612
—
—
—
149,862
27
118,903
(13,046)
109,116
22,248
—
(1,834,197)
1,036
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
50,483
20,570
234,801
305,854
57,562
425,307
3,554,210
(2,183,464)
1,796,053
50,339
—
28,807
6,829
163,155
29
$
$
2,004,588
$
2,038,180
$
200,057
$ (1,834,197) $
2,408,628
76,174
$
264,485
$
8,511
$
— $
349,170
1,770,427
—
10,082
—
—
33,831
—
2,230,108
147,905
(490,244)
88,485
—
8,728
35,777
58,556
—
—
—
(2,265,885)
431,688
1,858,912
—
52,641
—
147,905
Total liabilities and shareholders' equity
$
2,004,588
$
2,038,180
$
200,057
$ (1,834,197) $
2,408,628
114
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2012
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
$
65,791
$
(20,147) $
— $
— $
—
63,333
129,124
—
70,085
182,804
232,742
—
—
—
—
347,008
—
—
—
—
—
—
—
—
—
(1,622,731)
—
—
—
—
45,644
70,085
246,137
361,866
347,008
470,043
2,715,767
(1,945,565)
1,240,245
117,191
—
22,584
16,554
218,256
28
—
—
—
—
—
—
—
—
—
—
347,008
$ (1,622,731) $ 2,323,732
— $
— $
237,931
—
—
—
—
—
—
—
(2,172,526)
1,848,972
—
87,436
—
48,179
421,864
513,668
(328,560)
233,287
7,701
1,622,731
22,584
16,554
38,100
1
2,070,082
37,031
1,848,972
—
34,686
—
149,393
$
$
$
$
2,202,099
(1,617,005)
1,006,958
109,490
—
—
—
180,156
27
1,529,373
200,900
—
—
52,750
2,172,526
$
$
(in thousands)
Assets
Current assets:
Cash and cash equivalents
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 equipment, net
Investments in and advances to affiliates, net
Deferred financing costs, net
Derivative financial instruments
Goodwill
Other assets
Total assets
Liabilities and shareholders' equity
Current liabilities
Long-term debt
Deferred income taxes
Other long-term liabilities
Payable to parent
Total shareholders' equity
(896,803)
347,008
549,795
149,393
Total liabilities and shareholders' equity
$
2,070,082
$
1,529,373
$
347,008
$ (1,622,731) $ 2,323,732
115
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the year ended December 31, 2013
Gain on divestitures and other operating items
(25,950)
(151,549)
(in thousands)
Revenues:
Oil and natural gas
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
Total costs and expenses
Operating income (loss)
Other income (expense):
Interest expense, net
Gain (loss) on derivative financial instruments
Other income
Equity loss
Net earnings from consolidated subsidiaries
Total other income (expense)
Income (loss) before income taxes
Income tax expense
Net income (loss)
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
$
9,136
$
582,158
$
43,015
$
— $
634,309
2,440
—
5,917
—
63
23,125
63,716
97,166
225,499
108,546
1,881
66,558
5,595
3,541
411,817
170,341
(99,815)
1,439
(1,068)
—
118,107
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)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(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)
—
(57,625)
(52,286)
—
(118,107)
(157,017)
(118,107)
22,204
—
—
$
22,204
$
170,393
$
(52,286) $
(118,107) $
22,204
116
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the year ended December 31, 2012
(in thousands)
Revenues:
Oil and natural gas
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 (expense):
Interest expense, net
Gain on derivative financial instruments
Other income
Equity income
Net loss from consolidated subsidiaries
Total other income (expense)
Income (loss) before income taxes
Income tax expense
Net income (loss)
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
$
78,649
$
467,960
$
— $
— $
546,609
19,820
—
7,767
—
526
14,394
(194)
42,313
36,336
84,790
102,875
295,389
1,346,749
3,361
69,424
17,223
1,919,811
(1,451,851)
(73,489)
62,812
238
—
(1,419,182)
(1,429,621)
(3)
3,321
731
—
—
4,049
(1,393,285)
(1,447,802)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
28,620
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,419,182
1,419,182
28,620
28,620
—
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
1,419,182
(1,393,285)
—
—
$ (1,393,285) $ (1,447,802) $
28,620
$ 1,419,182
$ (1,393,285)
117
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the year ended December 31, 2011
(in thousands)
Revenues:
Oil and natural gas
Costs and expenses:
Oil and natural gas production
Gathering and transportation
Depreciation, depletion 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:
Interest expense, net
Gain on derivative financial instruments
Other income
Equity income
Net loss from consolidated subsidiaries
Total other income
Income (loss) before income taxes
Income tax expense
Net income (loss)
Resources
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
$
93,663
$
660,538
$
— $
— $
754,201
19,166
—
39,954
—
442
27,559
19,122
106,243
(12,580)
(59,764)
190,043
316
—
(95,419)
35,176
22,596
—
89,475
86,881
322,853
233,239
3,210
77,059
4,973
817,690
(157,152)
(1,259)
29,687
472
—
—
28,900
(128,252)
—
—
—
149
—
—
—
(276)
(127)
127
—
—
—
32,706
—
32,706
32,833
—
—
—
—
—
—
—
—
—
—
—
—
—
—
95,419
95,419
95,419
—
108,641
86,881
362,956
233,239
3,652
104,618
23,819
923,806
(169,605)
(61,023)
219,730
788
32,706
—
192,201
22,596
—
$
22,596
$
(128,252) $
32,833
$
95,419
$
22,596
118
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
(15,767)
(1,242,667)
(38,818)
— (1,297,252)
Restricted cash
Equity method investments
Proceeds from disposition of property and equipment
Distributions received from EXCO/HGI Partnership
Net changes in advances to joint ventures
Advances/investments with affiliates
Other
—
—
244,500
3,825
—
(59,575)
(1,303)
49,515
236,289
505,128
—
10,645
59,575
—
—
—
—
—
—
—
—
—
—
—
(3,825)
—
—
—
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
Repayments under credit agreements
Proceeds from issuance of common stock
Payment of common stock dividends
EXCO/HGI Partnership cash distribution
Deferred financing costs and other
Net cash provided by (used in) financing activities
Net increase (decrease) in cash
Cash at beginning of period
Cash at end of period
967,766
(1,015,900)
1,712
(43,214)
—
(33,317)
(122,953)
16,049
65,791
—
—
—
—
—
—
—
(15,745)
(20,147)
36,757
(6,885)
—
—
(3,825)
(236)
25,811
4,535
—
—
1,004,523
— (1,022,785)
—
—
3,825
—
3,825
—
—
1,712
(43,214)
—
(33,553)
(93,317)
4,839
45,644
50,483
$
81,840
$
(35,892) $
4,535
$
— $
119
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 and property acquisitions
(77,006)
(459,917)
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 credit agreements
Repayments under credit agreements
Proceeds from issuance of common stock
Payment of common stock dividends
Deferred financing costs and other
Net cash used in financing activities
Net increase (decrease) in cash
Cash at beginning of period
Cash at end of period
—
—
15,161
—
(59,126)
85,840
(14,907)
22,884
851
59,126
(120,971)
(306,123)
53,000
(93,000)
1,968
(34,358)
(1,655)
(74,045)
(12,873)
78,664
—
—
—
—
—
—
26,520
(46,667)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(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
$
65,791
$
(20,147) $
— $
— $
120
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended December 31, 2011
(in thousands)
Operating Activities:
Resources
Guarantor
Subsidiaries
Non-
guarantor
subsidiaries
Eliminations
Consolidated
Net cash provided by operating activities
$
71,636
$
355,736
$
1,171
$
— $
428,543
Net cash used in investing activities
(338,491)
(369,869)
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
Deposit on acquisitions
Net changes in advances to joint ventures
Advances/investments with affiliates
Other
Financing Activities:
Borrowings under the credit agreements
Repayments under the credit agreements
Proceeds from issuance of common stock
Payment of common stock dividends
Deferred financing costs and other
Net cash provided by financing activities
Net increase (decrease) in cash
Cash at beginning of period
Cash at end of period
(63,089)
(1,670,029)
(4,253)
—
—
3,129
—
—
(278,531)
—
5,792
111,171
446,554
464,151
(1,707)
275,449
(1,250)
706,000
(407,500)
12,063
(34,238)
(7,569)
268,756
1,901
76,763
—
—
—
—
—
—
(14,133)
(32,534)
—
—
—
—
—
3,082
—
(1,171)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1,737,371)
5,792
111,171
449,683
464,151
(1,707)
—
(1,250)
(709,531)
706,000
(407,500)
12,063
(34,238)
(7,569)
268,756
(12,232)
44,229
31,997
$
78,664
$
(46,667) $
— $
— $
121
19.
Quarterly financial data (unaudited)
The following are summarized quarterly financial data for the years ended December 31, 2013 and 2012:
(in thousands, except per share amounts)
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
2012
Oil and natural gas revenues
Operating loss (4)
Net loss
Basic loss per share:
Net loss
Weighted average shares
Diluted loss per share:
Net loss
Weighted average shares
1st
2nd
3rd
4th
Quarter
$
$
$
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
$
134,848
(311,087)
(281,649) $
$
117,978
(476,036)
(496,433) $
$
141,621
(321,021)
(346,174) $
(1.32) $
(2.32) $
(1.62) $
214,145
214,164
214,301
(1.32) $
(2.32) $
(1.62) $
214,145
214,164
214,301
180,440
(79,331)
(122,863)
(0.57)
215,410
(0.57)
215,410
152,162
(307,371)
(269,029)
(1.25)
214,672
(1.25)
214,672
$
$
$
$
$
$
$
$
(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 14. Equity investments" 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 the EXCO/HGI Partnership. See "Note 3. Acquisitions, divestitures and other significant events" for
further discussion.
(4) Operating loss for the first quarter, second quarter, third quarter and fourth quarter of 2012 includes $275.9 million,
$428.8 million, $318.0 million and $324.0 million, respectively, of impairments of oil and natural gas properties. See
"Note 2. Summary of significant accounting policies" for further discussion.
20.
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, 2013, 2012 and 2011 is presented in accordance with ASC 932, Extractive Activities, Oil and Gas.
122
Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities:
(in thousands, except per unit amounts)
Amount
2013:
Proved property acquisition costs
Unproved property acquisition costs
Total property acquisition costs (1)
Development
Exploration costs (2)
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 (3)
Lease acquisitions and other (4)
Capitalized asset retirement costs
Depletion per Boe
Depletion per Mcfe
2011:
Proved property acquisition costs
Unproved property acquisition costs
Total property acquisition costs (5)
Development
Exploration costs (6)
Lease acquisitions and other (7)
Capitalized asset retirement costs
Depletion per Boe
Depletion per Mcfe
$
$
$
$
$
$
$
$
$
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
136,295
260,076
396,371
593,331
262,120
31,466
3,765
11.24
1.87
(1) Acquisition costs in 2013 include the Eagle Ford acquisition, Haynesville acquisition and our proportionate share of the
(2)
(3)
EXCO/HGI Partnership acquisition of shallow Cotton Valley assets.
Exploration costs in 2013 include approximately $29.2 million in the Eagle Ford shale and approximately $9.4 million in
the Marcellus shale.
Exploration costs in 2012 include approximately $40.1 million in the Haynesville shale, and approximately $17.2 million
in the Marcellus shale.
Lease acquisition costs in 2012 are net of acreage reimbursements from BG Group totaling $2.1 million.
(4)
(5) Acquisition costs in 2011, net of BG Group reimbursements of $359.1 million, include the Chief Transaction, Appalachia
Transaction and the Haynesville Shale Acquisition.
Exploration costs in 2011 include approximately $33.9 million incurred in the Marcellus shale play in Appalachia and
approximately $228.2 million in the Shelby area.
Lease acquisition costs in 2011 are net of acreage reimbursements from BG Group totaling $31.9 million.
(6)
(7)
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
123
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
our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and
natural gas prices, interest rates, changes in development and production costs and risks associated with future production.
Because of these and other considerations, any estimate of fair value is subjective and imprecise.
Oil
(Mbbls)
Natural
Gas
(Mmcf)
Natural Gas
Liquids (Mbbls)
(13)
Mmcfe
1,499,101
62,489
201,139
(14,565)
(230,097)
(5,767)
(182,712)
1,329,588
—
—
—
—
—
—
—
—
—
424
102,111
—
6,724
—
(509)
6,639
2,201
513
686
(741)
(6,472)
(243)
2,583
(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
December 31, 2010 (1)
Purchase of reserves in place
Discoveries and extensions (2)
Revisions of previous estimates:
Changes in price
Other factors (3)
Sales of reserves in place
Production
December 31, 2011 (4)
Purchase of reserves in place
Discoveries and extensions (5)
Revisions of previous estimates:
Changes in price
Other factors (6)
Sales of reserves in place
Production
December 31, 2012 (7)
Purchase of reserves in place (8)
Discoveries and extensions (9)
Revisions of previous estimates:
Changes in price
Other factors (10)
Sales of reserves in place (11)
Production
December 31, 2013 (12)
7,358
1,454,953
—
929
62,489
195,565
100
(1,264)
(28)
(741)
6,354
—
492
(110)
(463)
—
(703)
5,570
16,022
5,960
457
(3,219)
(8,224)
(1,188)
15,378
(15,165)
(222,513)
(5,599)
(178,266)
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
124
Estimated Quantities of Proved Developed and Proved Undeveloped Reserves
Proved developed:
December 31, 2013
December 31, 2012
December 31, 2011
Proved undeveloped:
December 31, 2013
December 31, 2012
December 31, 2011
Oil
(Mbbls)
Natural
Gas
(Mmcf)
Natural Gas Liquids
(Mbbls) (13)
Mmcfe
11,274
4,371
4,565
4,104
1,199
1,789
657,116
917,326
955,522
359,363
18,806
335,942
2,088
4,784
—
495
1,855
—
737,291
972,256
982,912
386,954
37,130
346,676
(1)
The above reserves do not include our equity interest in OPCO, which represents 0.04% (575 Mmcfe) of our consolidated
Proved Reserves at December 31, 2010 and a Standardized Measure of $0.4 million, or 0.03%, of our consolidated
Standardized Measure.
(2) New discoveries and extensions in 2011 include 158,649 Mmcfe in East Texas/North Louisiana, primarily in the
(3)
(4)
Haynesville shale, 30,206 Mmcfe in Appalachia, all in the Marcellus shale and 12,284 Mmcfe in the Permian Basin.
Total revisions due to Other factors in 2011 include approximately 168,264 Mmcfe of Proved Undeveloped Reserves that
were reclassified to unproved reserves as a result of a slower development schedule due to continued low natural gas
prices, which extended their scheduling beyond a five-year development horizon. The reclassified Proved Developed
Reserves represent all non-shale Proved Undeveloped Reserves in Appalachia and East Texas/North Louisiana.
The above reserves do not include our equity interest in OPCO, which represents 0.04% (576 Mmcfe) of our consolidated
Proved Reserves at December 31, 2011 and a Standardized Measure of $0.6 million, or 0.04%, of our consolidated
Standardized Measure.
(5) New discoveries and extensions in 2012 include 25,626 Mmcfe in East Texas/North Louisiana, primarily in the
(6)
(7)
(8)
Haynesville shale, 59,455 Mmcfe in Appalachia, all 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 continued depressed natural
gas prices, 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.
The above reserves do not include our equity interest in OPCO, which represents 0.07% (752 Mmcfe) of our consolidated
Proved Reserves at December 31, 2012 and a Standardized Measure of $0.5 million, or 0.07% of our consolidated
Standardized Measure.
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 the EXCO/HGI Partnership's acquisition of shallow Cotton Valley
assets in East Texas/North Louisiana.
(9) New discoveries and extensions in 2013 included 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 the EXCO/HGI
Partnership in the Permian Basin, and 1,486 Mmcfe for shale properties in the Permian Basin.
(10) Total revisions due to Other factors were approximately 130,455 Mmcfe of 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.
(11) Sales of reserves in place included 327,608 Mmcfe as a result of our contribution of properties to the EXCO/HGI
Partnership and 30,582 Mmcfe from the sale of undeveloped properties in the Eagle Ford in connection with the KKR
Participation Agreement.
(12) The above reserves do not include our equity interest in OPCO, which represents 0.08% (910 Mmcfe) of our consolidated
Proved Reserves at December 31, 2013 and a Standardized Measure of $0.8 million, or 0.06% of our consolidated
Standardized Measure.
(13) Beginning in 2012, we began reporting our NGLs separately. In 2011, the NGLs were reported as a component of natural
gas.
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
125
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.
(in thousands)
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
Year ended December 31, 2011:
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
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
5,950,080
2,231,693
915,399
390,786
2,412,202
985,740
1,426,462
$
$
$
$
$
$
During recent years, prices paid for oil and natural gas have fluctuated significantly. The reference prices at
December 31, 2013, 2012 and 2011 used in the above table, were $96.78, $94.71 and $96.19 per Bbl of oil, respectively, and
$3.67, $2.76 and $4.12 per Mmbtu of natural gas, respectively. Beginning in 2012, we began reporting our NGLs separately. In
2011, the NGLs were reported as a component of natural gas. The reference price at December 31, 2013 and 2012 used in the
above table was $39.92 and $46.57 per Bbl for NGLs, respectively. In each case, the prices were adjusted for historical
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.
126
The following are the principal sources of change in the Standardized Measure:
(in thousands)
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 (includes revisions-transfer of Proved Undeveloped Reserves to
probable reserves)
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, 2011:
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 (includes revisions-transfer of Proved Undeveloped Reserves to
probable reserves)
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
127
$
Amount
(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)
(558,794)
(182,750)
293,377
405,125
265,864
(334,181)
(6,067)
156,731
137,519
140,304
(114,105)
203,023
$
$
$
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
2013
2012
2011
2010 and
prior
$
376,825
$
135,125
$
4,982
$
93,373
$
143,345
12,360
36,122
12,360
13,618
—
13,824
—
8,317
—
363
$
425,307
$
161,103
$
18,806
$
101,690
$
143,708
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, 2013 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,
2013, using criteria established in Internal Control-Integrated Framework (1992) 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, 2013 that have materially affected, or are reasonably
likely to materially affect, EXCO's internal control over financial reporting.
Item 9B. Other Information
None.
128
PART III
Item 10.
Directors, Executive Officers and Corporate Governance
The information required in response to this Item 10 is incorporated herein by reference to our Definitive Proxy
Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
fiscal year covered by this Annual Report on Form 10-K.
Item 11.
Executive Compensation
The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy
Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
fiscal year covered by this Annual Report on Form 10-K.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy
Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
fiscal year covered by this Annual Report on Form 10-K.
Item 13.
Certain Relationships and Related Transactions and Director Independence
The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy
Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
fiscal year covered by this Annual Report on Form 10-K.
Item 14.
Principal Accountant Fees and Services
The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy
Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
fiscal year covered by this Annual Report on Form 10-K.
PART IV
Item 15.
Exhibits and Financial Statement Schedules
(a)(1) See Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.
(a)(2) None.
(a)(3) See "Index to Exhibits" for a description of our exhibits.
(b)
(c)
See "Index to Exhibits" for a description of our exhibits.
None.
129
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
130
Date: February 26, 2014
EXCO RESOURCES, INC.
(Registrant)
/s/ Harold L. Hickey
Harold L. Hickey
President and Chief Operating Officer
/s/ Mark F. Mulhern
Mark F. Mulhern
Executive Vice President, Chief Financial Officer and
Interim Chief Accounting Officer
/s/ Jeffrey D. Benjamin
Jeffrey D. Benjamin
Non-Executive Chairman
/s/ Earl E. Ellis
Earl E. Ellis
Director
/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
131
Exhibit
Number
Description of Exhibits
INDEX TO EXHIBITS
2.1
2.2
2.3
2.4
2.5
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
Unit Purchase and Contribution Agreement, dated November 5, 2012, by and among EXCO Resources, Inc.,
EXCO Operating Company, LP, EXCO/HGI JV Assets, LLC and HGI Energy Holdings, LLC, filed as an
Exhibit to EXCO's Current Report on Form 8-K, dated November 5, 2012 and filed on November 9, 2012 and
incorporated by reference herein.
First Amendment to Unit Purchase and Contribution Agreement and Closing Agreement, dated as of February
14, 2013, by and among EXCO Resources, Inc., EXCO Operating Company, LP, EXCO/HGI JV Assets, LLC
and HGI Energy Holdings, LLC, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter
Ended March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.
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.
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, dated March 4, 2009 and filed on March 6, 2009 and incorporated by reference herein.
Statement of Designation of Series A-l 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO
Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated
March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
Statement of Designation of Series A-2 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO
Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated
March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
Statement of Designation of Series B 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO
Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated
March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
Statement of Designation of Series C 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO
Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated
March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
Statement of Designation of Series A-l Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to
EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007
and incorporated by reference herein.
132
3.9
3.10
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
10.1
10.2
Statement of Designation of Series A-2 Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to
EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007
and incorporated by reference herein.
Statement of Designation of Series A Junior Participating Preferred Stock of EXCO Resources, Inc., filed as an
Exhibit to EXCO’s Current Report on Form 8-K, dated January 12, 2011 and filed on January 13, 2011 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.
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.
First Amended and Restated Registration Rights Agreement dates as of December 30, 2005, by and among
EXCO Holdings Inc. and the Initial Holders (as defined therein), filed as an Exhibit to EXCO’s Amendment
No. 1 to its Registration Statement on Form S-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.*
133
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
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.*
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 February 24, 2010 and incorporated by
reference herein.*
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.
Letter Agreement, dated March 28, 2007, with Ares Corporate Opportunities Fund, 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 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.
Joint Development Agreement, dated as of June 1, 2010, by and among EXCO Production Company (PA),
LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production
Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on
Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.17
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
134
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
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.
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.
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.
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.
Amended and Restated Agreement of Limited Partnership of EXCO/HGI Production Partners, LP, filed as an
Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 2013
and incorporated by reference herein.
Form of Amended and Restated Limited Liability Company Agreement of EXCO/HGI GP, LLC, filed as an
Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 2013
and incorporated by reference herein.
Letter Agreement, dated November 5, 2012, by and among EXCO Resources, Inc., EXCO Operating Company,
LP, Harbinger Group Inc. and HGI Energy Holdings, LLC, filed as an Exhibit to EXCO's Current Report on
Form 8-K, dated November 5, 2012 and filed on November 9, 2012 and incorporated by reference herein.
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.*
Letter Agreement, dated March 1, 2013, by and between EXCO Resources, Inc. and Mark Mulhern, filed as an
Exhibit to EXCO's Current Report on Form 8-K, dated February 28, 2013 and filed on March 6, 2013 and
incorporated by reference herein.*
EXCO Resources, Inc. 2013 Management Incentive Plan, filed as an Exhibit to EXCO's Current Report on
Form 8-K, dated February 28, 2013 and filed on March 6, 2013 and incorporated by reference herein.*
135
10.31
10.32
10.33
10.34
10.35
10.36
10.37
10.38
10.39
10.40
10.41
Credit Agreement, dated as of February 14, 2013, among EXCO/HGI JV Assets, LLC, as Borrower, certain
subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as
Administrative Agent, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended
March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.
First Amendment to Credit Agreement, dated as of March 5, 2013, by and among EXCO/HGI JV Assets, LLC,
as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank,
N.A., as Administrative Agent, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter
Ended March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.
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.
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.
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.
10.42
EXCO Resources, Inc. Retention Bonus Plan, dated August 4, 2011, 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.*
136
10.43
10.44
10.45
10.46
14.1
14.2
14.3
21.1
23.1
23.2
23.3
23.4
23.5
23.6
31.1
31.2
32.1
99.1
99.2
99.3
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.*
Bonus and Retention Agreement, dated January 17, 2014, by and between Mark F. Mulhern and EXCO
Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed
on January 24, 2014 and incorporated by reference herein.*
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.
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 KPMG LLP as it relates to TGGT Holdings, LLC, 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.
Consent of Haas Petroleum Engineering Services, Inc., 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.
2013 Report of Lee Keeling and Associates, Inc., filed herewith.
2013 Report of Netherland, Sewell & Associates, Inc., filed herewith.
2013 Report of Ryder Scott Company, L.P., filed herewith.
137
99.4
99.5
EXCO/HGI JV Assets, LLC 2013 Report of Lee Keeling and Associates, Inc., filed herewith.
Consolidated Financial Statements of TGGT Holdings, LLC, for the period from January 1, 2013 to November
14, 2013 and for the Years Ended December 31, 2012 and 2011, 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.
138
DIRECTORS
SHAREHOLDER INFORMATION
Shareholder Relations
Christopher C. Peracchi
Treasurer and Director of Finance
and Investor Relations
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 2014 Annual Meeting
of Shareholders will be held
on Thursday, May 22, 2014 at
10:00 a.m. local time, at the:
Westin Galleria Dallas
13340 Dallas Parkway
Dallas, Texas 75240
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, New York 10004
212.509.4000
Number of Common Shareholders
30,344
(As of March 15, 2014)
JEFFREY D. BENJAMIN 1, 2, 3
Non-Executive Chairman of the Board –
EXCO Resources, Inc.
Senior Advisor –
Cyrus Capital Partners, LP
EARL E. ELLIS 4
Chairman and Chief Executive Officer –
Whole Harvest Products
B. JAMES FORD 2, 3
Managing Director –
Oaktree Capital Management, L.P.
SAMUEL A. MITCHELL 1, 2, 3
Managing Director –
Hamblin Watsa Investment Counsel
T. BOONE PICKENS
Chairman and Chief Executive Officer –
BP Capital L.P.
WILBUR L. ROSS, JR. 2, 3
Chairman and
Chief Executive Officer –
WL Ross & Co. LLC
JEFFREY S. SEROTA 1, 2, 3
Senior Advisor –
Ares Management LLC
ROBERT L. STILLWELL 1, 2, 3
Retired General Counsel –
BP Capital L.P.
1 Audit Committee Member
2 Compensation Committee Member
3 Nominating and Corporate Governance Committee Member
4 Mr. Ellis has decided not to stand for re-election at the 2014 annual shareholder meeting
OFFICERS
HAROLD L. HICKEY
President and
Chief Operating Officer
MARK F. MULHERN
Executive Vice President
and Chief Financial Officer
WILLIAM L. BOEING
Vice President, General Counsel
and Secretary
RICHARD A. BURNETT
Vice President and
Chief Accounting Officer
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
STEVEN L. ESTES
Vice President
of Marketing
JOE D. FORD
Vice President of
Human Resources
RUSSELL D. GRIFFIN
Vice President of Environmental,
Heath and Safety
SCOTT M. HERSTEIN
Vice President of
Business Development
DANIEL W. HIGDON
Vice President of Land
HAROLD H. JAMESON
Vice President of
Asset Management
CHRISTOPHER C. PERACCHI
Treasurer and Director
of Finance and Investor Relations
STEPHEN E. PUCKETT
Vice President of
Reservoir Engineering
MARCIA R. SIMPSON
Vice President
of Engineering
ROBERT L. THOMAS
Chief Information Officer
EXCO Resources, Inc.
12377 Merit Drive
Suite 1700
Dallas, Texas 75251
PHONE 214.368.2084
FAX 214.368.2087
www.excoresources.com
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