Matador Resources Company Annual Report 2011

FY2011 Annual Report · Matador Resources Company

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A TIME OF
TRANSITION.
A YEAR OF
GROWTH.

2011 ANNUAL REPORT

MATADOR STAFF: Surrounding Joe Foran, Matador’s Chairman, President and CEO (front row, center) are

representatives of the Matador team. We had a total of 41 full-time employees at December 31, 2011.

Matador Resources Company is an independent energy company engaged
in the exploration, development, production and acquisition of oil and
natural gas resources in the United States. Our focus is on unconventional
resource plays with a strong emphasis on shale plays.

Our current operations are primarily in the Eagle Ford shale in south
Texas and the Haynesville shale and Cotton Valley in northwest Louisiana
and east Texas. We also have acreage positions in west Texas, New
Mexico, Wyoming, Utah and Idaho.

A TIME OF
TRANSITION.

On February 2, 2012, Matador Resources Company
began trading on the New York Stock Exchange under
the ticker symbol “MTDR.”

On the front cover: Joe and Nancy Foran, along with representatives of the founding

shareholders, Board of Directors and management, ring the closing bell at the New

York Stock Exchange on March 9, 2012, celebrating Matador’s initial public offering.

For more information, please visit our website at www.matadorresources.com.

DEAR SHAREHOLDERS & FRIENDS

As we approach our first shareholders’
meeting as a public company, I wanted to share
with you my thoughts about this annual report
and the year ahead and to invite you to attend
the shareholders’ meeting scheduled for 10:00
a.m. on June 7, 2012 here in Dallas. In February
2012, Matador Resources Company completed
its initial public offering, or “IPO,” and began
trading on the New York Stock Exchange under
the ticker symbol “MTDR.” The front cover
depicts the essential reason for Matador’s long
record of success — a lot of good people have
worked together for many years to contribute
their time, talent and treasure to build a
company worthy of taking public. As a result,
this past year was a time of exciting transition
for Matador, not only from a private to a public
company, but also from a natural gas focus to
an increasing focus on oil and liquids.

The year 2011 was also one of continued
growth for Matador as we achieved record
total oil and natural gas production, realized
revenues and cash flows — up 79%, 89%
and 111%, respectively, from 2010 (see back
cover). In addition to these achievements, we
more than doubled the PV-10 (present value
discounted at 10%) of our oil and natural gas
reserves and increased oil production by
almost five-fold from approximately 33,000
barrels in 2010 to approximately 154,000
barrels in 2011. Details of these achievements
and much more information about Matador
and our 2011 performance are provided in the
attached Form 10-K annual report.

OIL AND LIQUIDS FOCUS FOR 2012

During the first quarter of 2012, oil prices
remained close to or above $100 per barrel,
while natural gas prices declined to their
lowest levels in many years approaching $2.00
per MMBtu. Accordingly, we plan to continue
the transition to exploring and developing the
oil and liquids opportunities in our portfolio,
and in 2012, most of these efforts will be
focused on the Eagle Ford shale play in south
Texas. In 2011, we added significantly to our

oil and liquids prospective position in the
Eagle Ford and now have almost 29,000 net
acres throughout the play in what we believe
to be the “right neighborhoods.” We currently
have two contracted drilling rigs operating
in south Texas — one in the eastern portion
and one in the western portion of the Eagle
Ford shale play, and, with success, we plan to
operate both rigs continuously in south Texas
throughout 2012.

We intend to allocate approximately 84%
of our estimated capital investments of $313
million in 2012 to the exploration, development
and acquisition of additional interests in
the Eagle Ford shale play. Including these
anticipated investments in the Eagle Ford,
we plan to dedicate 94% of our 2012 capital
investments to opportunities prospective
for oil and liquids production. Through
these efforts, we expect our oil production to
increase almost ten-fold in 2012 to between
1.4 and 1.5 million barrels, accounting for
approximately 75% to 80% of our total oil and
natural gas revenues.

We do not plan to drill any operated
Haynesville shale or Cotton Valley wells in
northwest Louisiana in 2012 and have allocated
approximately 5% of our 2012 capital budget
to participating in several non-operated
Haynesville wells this year. Virtually all of
our Haynesville and Cotton Valley acreage is
held by existing production. This gives us a
significant “gas bank” and a readily available
“gas option” for future development when
natural gas prices improve.

The Board, the staff and I are very pleased
with our recent accomplishments and even
more excited about the opportunities that lie
ahead. Following the successful completion
of our IPO, we expect another year of strong
growth fueled by our ongoing drilling activities
in the Eagle Ford shale play. We are optimistic
that these efforts will increase the value of our
assets, our operational flexibility and our share
price as more investors get to know us better.

SHAREHOLDER RELATIONSHIPS

Finally, although the IPO has been
a transformational event for Matador,
there is one thing that I hope will never
change — the special relationships we
enjoy with our shareholders. It is still
very important to the Board, our staff and
to me personally to maintain the close
relationships we have enjoyed with our legacy
shareholders as a private company and to
develop lasting relationships with the new
shareholders who have recently invested in
Matador. We will continue to work hard to
grow our credibility with each of you and to
grow the value of your investment in Matador.

Shareholder meetings have always played
an important role in our communications, and
we usually have more than 100 shareholders
present at these meetings. On June 7, we
hope to set a new attendance record as we
welcome many new shareholders to Dallas
and to Matador. Please accept this letter,
our annual report and the accompanying
proxy materials as your special invitation
to attend and to participate in our first
annual shareholders’ meeting as a public
company. We hope it will be an interesting,
informational and lively meeting, and we look
forward to seeing you there!

Very truly yours,

JOSEPH WM. FORAN
Chairman, President & CEO

OIL PRODUCTION IN BBLS

OIL & GAS REvENUE PERCENTAGE

1,500,000

1,200,000

900,000

600,000

300,000

154,000

33,000

1,450,000

100%

%
6
.
2
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We expect oil production
to increase almost ten-fold
in 2012, accounting for 75%
to 80% of our revenues.

Gas

Oil

2010

2011

2012 est

2010

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)
È ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

or
‘ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

For the fiscal year ended December 31, 2011

EXCHANGE ACT OF 1934

For the transition period from

to
Commission file number 001-34574

Matador Resources Company

(Exact name of registrant as specified in its charter)

Texas
(State or other jurisdiction of
incorporation or organization)

5400 LBJ Freeway, Suite 1500
Dallas, Texas 75240
(Address of principal executive offices)

27-4662601
(I.R.S. Employer
Identification No.)

75240
(Zip Code)

Registrant’s telephone number, including area code: (972) 371-5200

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

Title of each class
Common Stock, par value $0.01 per share

Name of each exchange on which registered

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes ‘ No È
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 È
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes ‘ No È
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 during the
preceding 12 months (or for such shorter period that the registrant was 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 is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. È
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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ‘
Non-accelerated filer È (Do not check if a 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 È

‘
Accelerated filer
Smaller reporting company ‘

As of June 30, 2011, the registrant was a privately held company and not publicly traded. Accordingly, the market

value of its common stock held by non-affiliates on such date cannot be reasonably determined.
As of March 30, 2012, there were 55,272,860 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this annual report on Form 10-K, to the extent not set forth herein, is

incorporated by reference to the registrant’s definitive proxy statement relating to the 2012 Annual Meeting of
Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the
fiscal year to which this annual report on Form 10-K relates.

MATADOR RESOURCES COMPANY

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011

TABLE OF CONTENTS

PART I
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.

PART II
ITEM 5.

ITEM 6.
ITEM 7.

ITEM 7A.
ITEM 8.
ITEM 9.

ITEM 9A.
ITEM 9B.

PART III
ITEM 10.
ITEM 11.
ITEM 12.

ITEM 13.

ITEM 14.

PART IV
ITEM 15.

BUSINESS.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
RISK FACTORS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UNRESOLVED STAFF COMMENTS.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PROPERTIES.
LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MINE SAFETY DISCLOSURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SELECTED FINANCIAL DATA. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
. . . . . . . . . . . . . . .
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CONTROLS AND PROCEDURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
OTHER INFORMATION.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. . . . . . . . . . . . . . . . . . . .
EXECUTIVE COMPENSATION.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PRINCIPAL ACCOUNTING FEES AND SERVICES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

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Cautionary Note Regarding Forward-Looking Statements

Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within

the meaning of applicable U.S. securities legislation. Additionally, forward-looking statements may be
made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on
our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,”
“believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “potential,” “predict,”
“project,” “should” or other similar words.

By their very nature, forward-looking statements require us to make assumptions that may not
materialize or that may not be accurate. Forward-looking statements are subject to known and unknown
risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to
differ materially from those expressed or implied by such statements. Such factors include, among others:
changes in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions,
uncertainties in estimating proved reserves and forecasting production results, operational factors affecting
the commencement or maintenance of producing wells, the condition of the capital markets generally, as
well as our ability to access them, the proximity to and capacity of transportation facilities, uncertainties
regarding environmental regulations or litigation and other legal or regulatory developments affecting our
business, and the other factors discussed below and elsewhere in this report and in other documents that we
file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”), all of which are difficult
to predict. Forward-looking statements may include statements about:

• our business strategy;

• our reserves;

• our technology;

• our cash flows and liquidity;

• our financial strategy, budget, projections and operating results;

• our oil and natural gas realized prices;

• the timing and amount of future production of oil and natural gas;

• the availability of drilling and production equipment;

• the availability of oil field labor;

• the amount, nature and timing of capital expenditures, including future exploration and

development costs;

• the availability and terms of capital;

• our drilling of wells;

• government regulation and taxation of the oil and natural gas industry;

• our marketing of oil and natural gas;

• our exploitation projects or property acquisitions;

• our costs of exploiting and developing our properties and conducting other operations;

• general economic conditions;

• competition in the oil and natural gas industry;

• the effectiveness of our risk management and hedging activities;

• environmental liabilities;

• counterparty credit risk;

• developments in oil-producing and natural gas-producing countries;

• our future operating results;

• estimated future reserves and the present value thereof; and

• our plans, objectives, expectations and intentions contained in this report that are not historical.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable
based on information available to us on the date such forward-looking statements were made, no assurances
can be given as to future results, levels of activity, achievements or financial condition.

You should not place undue reliance on any forward-looking statement and should recognize that the
statements are predictions of future results, which may not occur as anticipated. Actual results could differ
materially from those anticipated in the forward-looking statements and from historical results, due to the
risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor
on a particular forward-looking statement is not determinable with certainty as such factors are
interdependent upon other factors. The foregoing statements are not exclusive and further information
concerning us, including factors that potentially could materially affect our financial results, may emerge
from time to time. We do not intend to update forward-looking statements to reflect actual results or
changes in factors or assumptions affecting such forward-looking statements.

Item 1.

Business.

PART I

In this Annual Report on Form 10-K, references to “we,” “our,” or “the Company” refer to Matador

Resources Company and its subsidiaries before the completion of our corporate reorganization on
August 9, 2011 and Matador Holdco, Inc. and its subsidiaries after the completion of our corporate
reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly owned
subsidiary of Matador Resources Company, now known as MRC Energy Company. Pursuant to the terms of
our corporate reorganization, former Matador Resources Company became a wholly owned subsidiary of
Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco,
Inc. changed its corporate name to Matador Resources Company.

Unless the context otherwise requires, the term “common stock” refers to shares of our common stock

after the conversion of our Class B common stock into Class A common stock upon the consummation of
our initial public offering on February 7, 2012, as the Class A common stock then became the only class of
common stock authorized, and the term “Class A common stock” refers to shares of our Class A common
stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the
consummation of our initial public offering.

For certain oil and natural gas terms used in this report, please see the “Glossary of Oil and Natural

Gas Terms” included in this report.

General

We are an independent energy company engaged in the exploration, development, production and

acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and
natural gas shale plays and other unconventional resource plays. Our current operations are located
primarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisiana
and east Texas. We expect the majority of our near-term capital expenditures will focus primarily on
increasing our production and reserves from the Eagle Ford shale play. We believe our interests in the Eagle
Ford shale play will enable us to create a more balanced commodity portfolio through the drilling of
locations that are prospective for oil and liquids. In addition to these primary operating areas, we have
acreage positions in southeast New Mexico and west Texas and in southwest Wyoming and adjacent areas
in Utah and Idaho where we continue to identify new oil and natural gas prospects.

We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman, President and
CEO, and Scott E. King, Co-Founder and Vice President, Geophysics and New Ventures. Mr. Foran began
his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with
$270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later
contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served
as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003
to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million.

Since our first well in 2004, we have drilled or participated in drilling 236 wells through December 31,

2011, including 106 Haynesville and nine Eagle Ford wells. From December 31, 2008 through
December 31, 2011, we grew our estimated proved reserves from 20.0 Bcfe to 193.2 Bcfe. At December 31,
2011, 34% of our estimated proved reserves were proved developed reserves, 12% of our estimated proved

reserves were oil and 88% of our estimated proved reserves were natural gas. Our average daily production
for the year ended December 31, 2011 was 42.3 MMcfe per day, including 39.8 MMcf of natural gas per
day and 422 Bbl of oil per day as compared to an average daily production of 23.6 MMcfe per day,
including 23.0 MMcf of natural gas per day and 91 Bbl of oil per day for the year ended December 31,
2010. We have achieved this growth while lowering operating costs (consisting of lease operating expenses
and production taxes and marketing expenses) from $1.16 per Mcfe for the year ended December 31, 2009,
to $0.88 per Mcfe for the year ended December 31, 2011, or a decrease of approximately 24%.

The following table presents certain summary data for each of our operating areas as of and for the

year ended December 31, 2011:

Producing
Wells

Total Identified
Drilling Locations(1)

Estimated Net Proved
Reserves

Net Acreage Gross Net

Gross

Net

Bcfe(2)

%
Developed

Avg. Daily
Production
(MMcfe)

South Texas:

Eagle Ford . . . . . . . . . . . . . . . . . . . . . .
Austin Chalk . . . . . . . . . . . . . . . . . . . .

Area Total(3) . . . . . . . . . . . . . . . . .

NW Louisiana/E Texas:

Haynesville . . . . . . . . . . . . . . . . . . . . .
Cotton Valley(4) . . . . . . . . . . . . . . . . . .

Area Total(5) . . . . . . . . . . . . . . . . .
SW Wyoming, NE Utah, SE Idaho . . . . . . .
SE New Mexico, West Texas . . . . . . . . . . .

28,673
14,849

28,673

14,527
23,054

25,339
135,862
6,658

Total . . . . . . . . . . . . . . . . . . . . . . .

196,532

9.0
–

9.0

106.0
108.0

214.0
–
13.0

236.0

7.3
–

7.3

11.6
71.7

83.3
–
5.7

96.3

193.0
16.0

209.0

524.0
60.0

584.0
–
–

793.0

153.1
16.0

169.1

102.9
36.0

138.9
–
–

308.0

27.9
–

27.9

150.4
14.2

164.6
–
0.7

193.2

37.9
–

37.9

26.4
100.0

32.7
–
100.0

33.7

3.3
–

3.3

32.3
6.5

38.8
–
0.2

42.3

(1) These locations have been identified for potential future drilling and are not currently producing. In addition, the total net identified
drilling locations is calculated by multiplying the gross identified drilling locations in an operating area by our working interest
participation in such locations. At December 31, 2011, these identified drilling locations included 8 gross and 8 net locations to which we
have assigned proved undeveloped reserves in the Eagle Ford and 102 gross and 17 net locations to which we have assigned proved
undeveloped reserves in the Haynesville. We have no proved undeveloped reserves assigned to identified drilling locations in the Austin
Chalk or Cotton Valley at December 31, 2011.

(2) These estimates were prepared by our engineering staff and audited by independent reservoir engineers, Netherland, Sewell &

Associates, Inc.

(3) Some of the same leases cover the net acres shown for the Eagle Ford formation and the Austin Chalk formation, a shallower formation

than the Eagle Ford formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for south
Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.

(4)

Includes shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells
producing from the San Miguel formation in Zavala County, Texas.

(5) Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formation

than the Haynesville formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for
northwest Louisiana/east Texas. This total includes acreage that we are producing from or that we believe to be prospective for these
formations.

At December 31, 2011, our properties included approximately 51,000 gross acres and 29,000 net acres in
the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, LaSalle, Gonzales, Webb, Wilson and Zavala
Counties in south Texas. We believe that approximately 85% of our Eagle Ford acreage is prospective
predominantly for oil or liquids production. In addition, portions of the acreage are also prospective for other
targets, such as the Austin Chalk, Olmos and Buda, from which we expect to produce predominantly oil and
liquids. Approximately 80% of our Eagle Ford acreage is either held by production or not burdened by lease
expirations before 2013. We have begun to explore and develop our Eagle Ford position and from November
2010 through December 2011, we completed our first seven operated wells in this area.

At December 31, 2011, we have identified 193 gross locations and 153 net locations for potential
future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property
basis and take into account criteria such as anticipated geologic conditions and reservoir properties,
estimated recoveries from nearby wells based on available public data, drilling densities observed from
other operators, estimated drilling and completion costs, spacing and other rules established by regulatory
authorities and surface considerations, among others. At December 31, 2011, we have identified potential
drilling locations on approximately 75% of our net Eagle Ford acreage. As we explore and develop our
Eagle Ford acreage further, we believe it is possible that we may identify additional locations for drilling.
At December 31, 2011, these identified potential future drilling locations in the Eagle Ford shale play
included 8 gross and 8 net locations to which we have assigned proved undeveloped reserves.

In addition, at December 31, 2011, we had approximately 23,000 gross acres and 15,000 net acres in
the Haynesville shale play in northwest Louisiana and east Texas. Based on our analysis of geologic and
petrophysical information (including total organic carbon content and maturity, resistivity, porosity and
permeability, among other information), well performance data and information available to us related to
drilling activity and results from wells drilled across the Haynesville shale play, approximately 5,500 of our
net acres are located in what we believe is the core area of the play. We believe the core area of the play
includes that area in which the most Haynesville wells have been drilled by operators and from which we
anticipate natural gas recoveries would likely exceed 6 Bcf per well. Over 90% of our Haynesville acreage
is held by production from the Haynesville or other formations, and we believe much of it is also
prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we
believe approximately 1,700 of these net acres are prospective for the Middle Bossier shale play.

At December 31, 2011, we have identified 524 gross locations and 103 net locations for potential
future drilling in our Haynesville acreage. These locations have been identified on a property-by-property
basis and take into account criteria such as anticipated geologic conditions and reservoir properties,
estimated recoveries from our producing Haynesville wells and other nearby wells based on available public
data, drilling densities observed from other operators including on some of our non-operated properties,
estimated drilling and completion costs, spacing and other rules established by regulatory authorities and
surface conditions, among others. Of the 524 gross locations identified for future drilling, 449 of these
locations (52 net locations) have been identified within the 5,500 net acres that we believe are located in the
core area of the Haynesville play. As we explore and develop our Haynesville acreage further, we believe it
is possible that we may identify additional locations for future drilling. At December 31, 2011, these
identified potential future drilling locations included 102 gross and 17 net locations in the Haynesville shale
play to which we have assigned proved undeveloped reserves.

We also have a large unevaluated acreage position in southwest Wyoming and adjacent areas in Utah

and Idaho where we began drilling our initial well in February 2011 to test the Meade Peak natural gas
shale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale,
before having operations suspended for several months due to wildlife restrictions. We resumed operations
on this initial test well in September 2011 and completed drilling and coring operations on this well in
November 2011. At December 31, 2011, this well had not been completed, as we were still evaluating the
well logs and awaiting results from various core analysis tests. In addition, we have leasehold interests in
the Delaware and Midland Basins in southeast New Mexico and west Texas where we are developing new
oil and natural gas prospects.

We are active both as an operator and as a co-working interest owner with larger industry participants

including affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc and
others. Of the 236 gross wells we have drilled or participated in drilling, we drilled approximately 40% of

these wells as the operator, although our working interest is small in many of the non-operated wells,
particularly in the Haynesville shale. At December 31, 2011, we were the operator for approximately 85%
of our Eagle Ford and 70% of our Haynesville acreage, including approximately 22% of our acreage in
what we believe is the core area of the Haynesville play. A large portion of our acreage in that core area is
operated by a subsidiary of Chesapeake Energy Corporation. We also operate all of our acreage in
southwest Wyoming and the adjacent areas of Utah and Idaho, as well as the vast majority of our acreage in
southeast New Mexico and west Texas.

We are a non-operating working interest participant with affiliates of Chesapeake Energy Corporation,
Royal Dutch Shell plc and several other companies in the Haynesville shale and with EOG Resources, Inc.
in the Eagle Ford shale. We have entered into a joint operating agreement with an affiliate of Chesapeake
Energy Corporation governing the Haynesville operations underlying our Elm Grove/Caspiana properties in
southern Caddo Parish, Louisiana and a joint operating agreement with EOG Resources, Inc. governing all
operations on our joint acreage in Atascosa County, Texas. We have not entered into a joint operating
agreement with Royal Dutch Shell plc or certain other operators of wells in the Haynesville area in which
we have a minority working interest. Particularly when our working interest is small, we do not always
enter into formal operating agreements with the operators, and in such cases, we rely on applicable legal and
statutory authority to govern our arrangement in accordance with industry standard practices.

Where we do have joint operating agreements with affiliates of Chesapeake Energy Corporation and
EOG Resources, Inc., these agreements call for significant penalties should we elect not to participate in the
drilling and completion of a well proposed by the operator, or a non-consent well. These non-consent
penalties typically allow the operator to recover up to 400% of its costs to drill, complete and equip the
non-consent well from the well’s future net revenue prior to us being allowed to participate in the
non-consent well for our original working interest. Ultimately, the amount of these penalties may result in
us having no participation at all in the non-consent well. We also have the right to propose wells under these
joint operating agreements, and the same non-consent penalties apply to the operator should it elect not to
consent to a well that we propose.

While we do not have direct access to our operating partners’ drilling plans with respect to future well
locations, we do attempt to maintain ongoing communications with the technical staff of these operators in
an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of
any related proved undeveloped well locations. We review these locations with Netherland, Sewell &
Associates, Inc., our independent reservoir engineers, on a periodic basis to ensure their concurrence with
our estimates of these drilling plans and our approach to booking these reserves.

The following table presents our 2012 anticipated capital expenditure budget of approximately
$313.0 million segregated by target formation and by whether the wells are expected to be exploration or
development wells.

2012 Anticipated Drilling

2012 Anticipated Capital
Expenditure Budget

Gross Wells(1)

Net Wells(1)

(in millions)(2)

Exploration Development Total Exploration Development Total Exploration Development Total

South Texas
Eagle Ford . . . . . . . . . . . . . . .
Austin Chalk . . . . . . . . . . . . .

Area Total . . . . . . . . . . . . .

NW Louisiana / E Texas
Haynesville . . . . . . . . . . . . . .
Cotton Valley . . . . . . . . . . . .

Area Total . . . . . . . . . . . . .

SW Wyoming, NE Utah,

SE Idaho . . . . . . . . . . . . .

SE New Mexico, West

Texas . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . .

Total

. . . . . . . . . . . . . . . . .

13.0
2.0

15.0

6.0
–

6.0

1.0

–
N/A

22.0

15.0
–

15.0

19.0
–

19.0

–

–
N/A

34.0

28.0
2.0

30.0

25.0
–

25.0

1.0

–
N/A

56.0

11.8
2.0

13.8

0.2
–

0.2

0.4

–
N/A

14.4

13.8
–

13.8

1.3
–

1.3

–

–
N/A

15.1

25.6
2.0

27.6

1.5
–

1.5

0.4

–
N/A

29.5

$122.3
11.3

133.6

$134.9
–

134.9

$257.2
11.3

268.5

1.9
–

1.9

2.5

–
25.0

11.6
–

11.6

–

–
3.5

13.5
–

13.5

2.5(3)

–
28.5(4)

$163.0

$150.0

$313.0

(1)

Includes wells we currently expect to drill and complete as operator, plus those wells in which we currently plan to participate as a
non-operator in 2012.

(2) Our capital expenditure budget is based on our net working interests in the properties.

(3) We have a carried interest for $5.0 million of the cost of this well presuming the election of our joint venture partner to participate in the

drilling of this well.

(4)

Includes $20.0 million to acquire additional leasehold interests primarily prospective for oil and liquids production in southeast New
Mexico and west Texas.

Although we intend to allocate a portion of our 2012 capital expenditure budget to financing

exploration, development and acquisition of additional interests in the Haynesville shale play, we currently
intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration,
development and acquisition of additional interests in the Eagle Ford shale play. Including these anticipated
capital expenditures in the Eagle Ford shale play, we plan to dedicate about 94% of our 2012 anticipated
capital expenditure budget to opportunities prospective for oil and liquids production. While we have
budgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate materially
based on market conditions and our drilling results. Since at December 31, 2011, over 90% of our
Haynesville acreage was held by production and approximately 80% of our Eagle Ford acreage was either
held by production or not burdened by lease expirations before 2013, we possess the financial flexibility to
allocate our capital when we believe it is economical and justified.

Recent Developments

On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock

at $12.00 per share. We sold 12,209,167 shares of common stock in this offering and certain selling
shareholders sold 2,674,167 shares of common stock, including shares sold by us and the selling
shareholders pursuant to the partial exercise of the underwriters’ over-allotment option on March 7, 2012.

Between November 2011 and February 2012, we entered into various costless collars to mitigate our
exposure to oil price volatility and enhance predictability of our cash flows. As of March 30, 2012, we had
hedged a total of 1,180,000 Bbls of oil for 2012, 1,260,000 Bbls of oil for 2013 and 120,000 Bbls of oil for
2014. For 2012, these collars have a weighted average price floor of $90.51 per Bbl and a weighted average
price ceiling of $109.84 per Bbl. For 2013, these collars have a weighted average price floor of $87.14 per
Bbl and a weighted average price ceiling of $110.26 per Bbl. For 2014, these collars have a weighted
average price floor of $90.00 per Bbl and a weighted average price ceiling of $114.90 per Bbl.

In December 2011, we amended and restated our senior secured revolving credit agreement. This
amendment increased the maximum facility amount from $150.0 million to $400.0 million. Borrowings are
limited to the lesser of $400.0 million or the borrowing base, which was $125.0 million as of March 30,
2012.

In November and December 2011, we completed three operated Eagle Ford horizontal wells, the
Martin Ranch #2H, #3H and #5H in northeastern LaSalle County, Texas. During initial flow tests on these
wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf of natural gas per day,
the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural gas per day, and the
Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6 MMcf of natural gas per day. All three
wells were turned to sales in late December 2011. We are the operator and have a 100% working interest in
these three wells.

Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800

net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from Orca
ICI Development, JV. We believe that all of this acreage is in an oil and liquids prone area of the Eagle
Ford play. We believe that the acreage in Wilson and Gonzales Counties and a portion of DeWitt County
will be prospective for oil and liquids from the Austin Chalk formation in addition to the Eagle Ford. We
paid approximately $31.5 million to acquire this acreage. We currently own a 50% working interest in the
acreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. We
currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) in
Karnes, Wilson and Gonzales Counties and are the operator.

Principal Areas of Interest

Our focus since inception has been the exploration for oil and natural gas in unconventional resource
plays with a particular focus over the last few years in the Haynesville shale play and more recently in the
Eagle Ford shale play. Our exploration efforts have concentrated primarily on known hydrocarbon-
producing basins with well-established production histories offering the potential for multiple-zone
completions. We have also sought to balance the risk profile of our prospects, as well as to explore for more
conventional targets in addition to the unconventional resource plays.

At December 2011, our principal areas of interest consisted of (1) the Eagle Ford shale play in south

Texas, (2) the Haynesville shale play, including the Middle Bossier shale play, as well as the traditional
Cotton Valley and Hosston (Travis Peak) formations in northwest Louisiana and east Texas, (3) the Meade
Peak shale play in southwest Wyoming and the adjacent areas of Utah and Idaho and (4) southeast New
Mexico and west Texas, including the Delaware and Midland Basins.

South Texas

Eagle Ford Shale and Other Formations

About 8% of our daily production, or 3.3 MMcfe per day, including 331 Bbls of oil per day and 1.3
MMcf of natural gas per day, was produced from the Eagle Ford shale in south Texas for the year ended
December 31, 2011. The Eagle Ford contributed approximately 78% of our daily oil production and about
3% of our daily natural gas production for 2011. For the month of December 2011, about 13% of our daily
production, or 5.6 MMcfe per day, including 706 Bbls of oil per day and 1.3 MMcf per day, was produced
from the Eagle Ford. During December 2011, the Eagle Ford contributed 91% of our daily oil production
and about 4% of our daily natural gas production. At December 31, 2011, approximately 14% of our proved
reserves, or 27.9 Bcfe, was attributable to the Eagle Ford, including approximately 3.6 million Bbls of oil
and 6.1 Bcf of natural gas. Our Eagle Ford proved reserves at December 31, 2011 comprised approximately
96% of our proved oil reserves and approximately 4% of our proved natural gas reserves. The present value
discounted at 10% for our proved reserves in the Eagle Ford at December 31, 2011 was $130.2 million, or
about 52% of the PV-10 for our total proved reserves of $248.7 million. We anticipate that the percentage
of our daily production and reserves attributable to the Eagle Ford shale will grow in 2012 as we intend to
allocate approximately 84% of our 2012 capital expenditure budget to the exploration, development and
acquisition of additional interests in the Eagle Ford play in an effort to grow the oil and liquids component
of our production and reserves.

The Eagle Ford shale extends across portions of south Texas from the Mexican border into east Texas

forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich
calcareous shale, in places transitioning to an organic, argillaceous lime-mudstone. It lies between the
deeper Buda limestone and the shallower Austin Chalk formation. Most, if not all, of the oil found in the
Austin Chalk and Buda formations is generally believed to be sourced from the Eagle Ford shale. In the
prospective areas for the Eagle Ford shale, the interval averages 200 feet thick, is found at depths ranging
from as shallow as 4,000 feet to as deep as 13,000 feet, and in much of the deeper portions of the play is
overpressured. The Eagle Ford shale has a total organic carbon content of 1% to 7% that is comparable to
the Haynesville shale, and is generally porous, with core-measured porosities ranging between 4% and 14%.

Along the entire length of the Eagle Ford trend the structural dip of the formation is consistently down

to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial
increases consistently southwards along with the thermal maturity of the formation. Where the formation is
shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more
thermally mature, the Eagle Ford shale is more natural gas prone. The transition between being more oil
prone and more natural gas prone includes an interval that typically produces wet gas with condensate. We
believe that approximately 85% of our Eagle Ford acreage lies within those portions of the Eagle Ford shale
that are prone to produce oil or wet gas with condensate.

Most of the current Eagle Ford shale activity is concentrated in Atascosa, Bee, DeWitt, Dimmit, Frio,
Gonzales, Karnes, LaSalle, Lavaca, Live Oak, Maverick, McMullen, Webb, Wilson and Zavala Counties in
south Texas. The first horizontal wells drilled specifically for the Eagle Ford shale were drilled in 2008,
leading to a discovery in LaSalle County. Since then, the play has expanded significantly across a large
portion of south Texas.

Publicly available information indicates that operators are typically drilling 3,500 to 7,000 feet

horizontal laterals and applying hydraulic fracture stimulation in multiple stages along the full length of the
horizontal laterals to complete the wells and establish production. Although production rates vary across the

different areas of the play, initial production rates in the oil areas have been reported as high as 1,000 to
1,500 Bbls of oil per day with varying amounts of associated natural gas. In the natural gas areas of the
Eagle Ford play, initial production rates as high as 5.0 to 15.0 MMcfe per day have been reported with
varying amounts of associated oil and liquids.

At December 31, 2011, our aggregate leasehold interests consisted of approximately 51,000 gross acres

and 29,000 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, LaSalle, Gonzales,
Webb, Wilson and Zavala Counties in south Texas. We believe portions of this acreage are also prospective
for the Austin Chalk, Buda, Olmos and other formations, from which we expect to produce predominantly oil
and liquids. In particular, the Austin Chalk formation, which is a naturally fractured carbonate ranging in
thickness from 200 to 400 feet, has produced from several fields on or nearby portions of our acreage. Our
Zavala County acreage, for example, is located within the historic Pearsall (Austin Chalk) field.

We believe that approximately 85% of our Eagle Ford acreage is prospective predominantly for oil and
liquids. At December 31, 2011, we owned a 100% working interest in approximately 26,000 gross acres and
23,000 net acres in Dimmit, Gonzales, Karnes, LaSalle, Webb, Wilson and Zavala Counties and a 50%
working interest in approximately 2,800 gross and 1,400 net acres in DeWitt County and are the operator of
this acreage. We also owned an approximate 21% working interest in approximately 22,000 gross acres in
Atascosa County operated by EOG Resources, Inc. At December 31, 2011, approximately 80% of our Eagle
Ford acreage was either held by production or not burdened by lease expirations before 2013.

At December 31, 2011, we had drilled and completed seven Eagle Ford wells on our operated

properties. All of these wells were producing to sales, although four of these wells were initially placed on
production in late December. At December 31, 2011, we had also participated in two Eagle Ford wells with
EOG Resources, Inc. as operator, on the Atascosa County acreage. Our first operated Eagle Ford horizontal
well, the JCM Jr. Minerals #1H in southern LaSalle County along the Edwards Reef, was completed in
November 2010. First sales of oil and natural gas began from this well in late January 2011, and during
December 2011, the well produced at an average daily rate of approximately 0.5 MMcf of natural gas and 9
Bbls of condensate per day, and through December 31, 2011, had produced a total of approximately 430
MMcf of natural gas and 11,200 Bbls of condensate. Our second operated Eagle Ford horizontal well, the
Martin Ranch #1H in northeastern LaSalle County, was completed in January 2011 and tested
approximately 1,200 Bbls of oil per day during an initial flow test. First sales of oil and natural gas from
this well began in late March at approximately 700 Bbls of oil and 350 Mcf of natural gas per day. During
December 2011, the well produced at an average daily rate of approximately 330 Bbls of oil and 0.6 MMcf
of natural gas per day, and through December 31, 2011, had produced a total of 117,000 Bbls of oil and 144
MMcf of natural gas.

Our third operated Eagle Ford horizontal well, the Affleck #1H, was completed in February 2011 in
eastern Dimmit County, Texas, and tested at approximately 415 Bbls of oil and 5.4 MMcf of natural gas per
day during an initial flow test. During December 2011, the well produced at an average daily rate of 0.8
MMcf of natural gas and 38 Bbls of oil per day. In August 2011, we completed our fourth operated Eagle
Ford horizontal well, the Lewton #1H in DeWitt County, Texas. This well tested at approximately 2.7
MMcf of natural gas and 1,040 Bbls of condensate per day during an initial flow test. The Lewton well
began producing to sales in late December 2011.

In November and December 2011, we completed three additional operated Eagle Ford horizontal

wells, the Martin Ranch #2H, #3H and #5H, in northeastern LaSalle County, Texas. During initial flow
tests on these wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf of

natural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural
gas per day, and the Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6 MMcf of natural gas
per day. All three wells were turned to sales in late December 2011.

Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800

net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from Orca
ICI Development, JV. We paid approximately $31.5 million to acquire this acreage. We currently own a
50% working interest in the acreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and
are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and
3,400 net acres) in Karnes, Wilson and Gonzales Counties and are the operator. At December 31, 2011, we
had drilled and completed only one well on this acreage, the Lewton #1H in DeWitt County.

We will pay 100% of the costs to drill and complete the first six wells drilled on the acreage in DeWitt

County. We will have an 85% working interest in these six wells until we have recovered all of our
acquisition, drilling and completion costs from each well, at which time Orca’s working interest will
increase to 50%. When the cumulative production from each of the first six wells reaches 500,000 BOE, on
a well-by-well basis, then Orca’s working interest in that well increases to 55%. If the cumulative
production from each of the first six wells reaches 750,000 BOE, on a well-by-well basis, then Orca’s
working interest in that well will increase to 70%. Both we and Orca will own a 50% working interest in all
subsequent wells drilled after the first six wells on the acreage in DeWitt County.

We will have a 100% working interest in the first five wells drilled on the acreage in Karnes, Wilson
and Gonzales Counties. When we have recovered all of our acquisition, drilling and completion costs from
each of these five wells, Orca may elect, on a well-by-well basis, to back-in for a 25% working interest in
these wells. In addition, Orca retains a one-time election for a short period of time after we complete these
first five wells to participate for a 25% working interest in all subsequent wells drilled on this acreage by
paying a purchase price equal to 25% of our costs to acquire the acreage in Karnes, Wilson and Gonzales
Counties.

At March 30, 2012, we had drilled an aggregate of 15 Eagle Ford horizontal wells in south Texas as
operator, including 10 wells in LaSalle County, one well in Dimmit County, three wells in Karnes County
and one well in DeWitt County. Thirteen of these wells have been completed and are producing and two of
these wells are awaiting completion. At March 30, 2012 we had two contracted drilling rigs operating in the
Eagle Ford play in south Texas: one in LaSalle County and one in Karnes County. We are not currently
experiencing difficulties in securing completion, and particularly hydraulic fracturing services, for our
newly drilled wells, although we experienced these problems at various times during 2011 in south Texas
and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling
and completion services and reducing drilling and completion costs will be essential to the successful
development and profitability of the Eagle Ford shale play. See “Risk Factors – The Unavailability or High
Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic
Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute
Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material
Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.”

We experienced temporary pipeline interruptions from time to time during 2011 associated with
natural gas production from our Eagle Ford wells and have been required to either shut in wells for brief
periods or to flare some of the natural gas we produce. At March 30, 2012, we were experiencing pipeline
capacity limitations at our Martin Ranch lease in LaSalle County and are currently flaring a portion of the
natural gas we are producing there as a result. We believe that these pipeline interruptions and capacity

constraints are temporary and that additional oil and natural gas pipeline infrastructure currently being built
throughout south Texas will help to alleviate these problems within 60 to 90 days. If we were required to
shut in our production for long periods of time due to these pipeline interruptions, it could have a material
adverse effect on our business, financial condition, results of operations and cash flows. See “Risk Factors –
The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering and Transportation
Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas
Transportation Agreements Would Have a Material Adverse Effect on Our Revenue.”

In addition to the Eagle Ford potential on our acreage, we believe that approximately 24,000 gross
acres and 15,000 net acres in south Texas are prospective primarily for the Austin Chalk formation, which
has historically been targeted by operators in south Texas. We have not yet drilled an Austin Chalk well,
and although we believe that other prospective well locations exist on this acreage, we have only included
16 gross and net well locations in our total identified drilling locations at December 31, 2011.

Northwest Louisiana and East Texas

At December 31, 2011, most of our production and proved reserves was attributable to our acreage in

northwest Louisiana and east Texas. For the year ended December 31, 2011, about 76% of our daily
production, or 32.3 MMcfe per day, was produced from the Haynesville shale, with another 15%, or
6.5 MMcfe per day, produced from the Cotton Valley and other shallower formations in this area. At
December 31, 2011, approximately 78% of our proved reserves, or 150.4 Bcfe, were attributable to the
Haynesville shale underlying this acreage with another 7% of our proved reserves, or 14.2 Bcfe, associated
with the Cotton Valley and shallower formations. In addition, we are evaluating the Bossier shale play
which is generally encountered above the Haynesville shale and below the Cotton Valley formation.

We operate all of our Cotton Valley and shallower production under this acreage, as well as all of our

Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville
play. Of the approximately 5,500 net acres that we consider to be in the core area of the Haynesville play,
we operate about 22% of that acreage.

In recent months, natural gas prices have declined to their lowest levels in many years, and at March

30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $2.13
per MMBtu. We would not expect to drill any operated natural gas wells in either our Haynesville or Cotton
Valley properties until natural gas prices improved substantially from these levels or unless the costs to drill
and complete these wells were also to decline substantially from their recent levels. See “Risk Factors – Our
Identified Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to
Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.”

Haynesville and Middle Bossier Shales

The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton
Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500
feet across a broad region throughout northwest Louisiana and east Texas, including principally Bossier,
Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in
Texas. The Haynesville shale has a typical thickness ranging from 100 to 300 feet. Total organic carbon
ranges from 0.5% to 5.0%, with core-measured porosities from 3% to 15%. The Haynesville shale produces
primarily dry natural gas with almost no associated liquids.

The oil and natural gas industry has focused significant attention on the Haynesville shale play over the

last several years. Operators are typically drilling 4,500 to 5,000 feet horizontal laterals and applying
hydraulic fracture stimulation in multiple stages along the entire length of the horizontal laterals to complete
the wells and establish production. Although initial production rates vary widely across the play, initial
production rates as high as 20.0 to 25.0 MMcf per day of natural gas have been reported by operators from
horizontal wells drilled and completed in the Haynesville shale.

The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle
Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine
Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar
productive characteristics to the deeper Haynesville shale. Typically, the Middle Bossier shale is found at
depths ranging from 500 to 800 feet shallower than the Haynesville shale, has a typical thickness ranging
from 150 to 300 feet, has core-measured porosities ranging between 5% and 14%, and total organic carbon
values between 0.5% and 4%. Although there is some overlap between the Bossier and Haynesville shale
plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each
formation.

At December 31, 2011, we had leasehold and mineral interests in approximately 23,000 gross and 15,000
net acres prospective for the Haynesville shale. Portions of our acreage are located in Caddo, DeSoto, Bossier
and Red River Parishes, Louisiana and in Harrison County, Texas. This acreage includes approximately 5,500
net acres in what we believe is the core area of the play. Over 90% of our Haynesville acreage is held by
production and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston
(Travis Peak) and other shallower formations. In addition, we believe that approximately 1,700 net acres are
prospective for the Middle Bossier play as well. We have not yet drilled a Middle Bossier shale well, and,
although we believe that prospective well locations exist on this acreage, we have not yet included any Middle
Bossier locations in our identified drilling locations at December 31, 2011.

Within the 5,500 net acres that we believe to be in the core area of the Haynesville shale play, we are

the operator in two sections where we have working interests of 95% and 100% in all wells to be drilled. In
October 2010, as operator, we drilled and completed our L.A. Wildlife H #1 horizontal Haynesville well in
the section in which we have a 95% working interest and on December 31, 2010 first sales of natural gas
began from this well. During December 2011, the well produced at an average daily rate of approximately
8.7 MMcf of natural gas per day, and through December 31, 2011, had produced a total of approximately
3.4 Bcf of natural gas. In March 2011, we completed our operated Williams 17 H #1 horizontal Haynesville
well on the second section where we have a 100% working interest. During December 2011, this well
produced at an average daily rate of 3.9 MMcf of natural gas per day and, through December 31, 2011, had
produced approximately 1.8 Bcf of natural gas. We began producing both of these wells at a constrained
rate of about 10.0 MMcf of natural gas per day. We have identified 12 gross and approximately 12 net
potential additional Haynesville locations that we may drill and operate in the future in these two sections.

The remainder of our acreage in the core area of the Haynesville shale play, about 4,300 net acres, is

operated by other companies. Just over half of our non-operated Haynesville acreage in this area of the play
results from a transaction with a subsidiary of Chesapeake in July 2008. The remainder of our non-operated
Haynesville acreage is attributable to leasehold interests that we hold in approximately 87 sections in
Caddo, DeSoto, Bossier and Red River Parishes. Our working interests in the Haynesville wells in these
sections range from less than 1% to more than 30%. At December 31, 2011, our production from these
non-operated Haynesville wells averaged approximately 22 MMcfe per day.

We do not plan to drill any operated Haynesville wells in 2012, but we have budgeted capital

expenditures of approximately $13 million for our anticipated participation in approximately 25 gross (1.5
net) non-operated wells that may be drilled in order to hold expiring acreage or that may be proposed in
multi-well development programs to evaluate optimal well spacing.

Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations

Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our
production and reserves in northwest Louisiana and east Texas were attributable to wells producing from
the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley
formation to the surface under our acreage in northwest Louisiana and east Texas.

All of the shallow rights underlying our acreage in our Elm Grove/Caspiana properties in northwest

Louisiana, approximately 10,000 gross and net acres at December 31, 2011, is held by existing production
from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary
producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley
formation is a low permeability gas sand that ranges in thickness from 200 to 300 feet and has porosities
ranging from 6% to 10%.

In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H #1-Alt. in

our Elm Grove/Caspiana properties, in DeSoto Parish and commenced sales of natural gas from this well.
Prior to this time, we had only drilled and completed vertical Cotton Valley and Hosston wells on these
properties. During December 2011, this well produced at an average daily rate of approximately 1.6 MMcf
of natural gas per day and through December 31, 2011, had produced a total of approximately 950 MMcf of
natural gas. We are the operator and have a 100% working interest in this well. We have identified 60 gross
and 36 net additional drilling locations for future Cotton Valley horizontal wells in our Elm Grove/Caspiana
properties. We do not plan to drill any of these locations in 2012. As all of this acreage is held by existing
production, we expect to allocate the majority of our near-term capital expenditures primarily to exploration
and development of our Eagle Ford shale acreage in south Texas.

We also continue to hold the shallow rights by existing production or by leases that are still in their

primary terms in our central and southwest Pine Island, Longwood, Woodlawn and other prospect areas in
northwest Louisiana and east Texas. At December 31, 2011, we held an estimated 11,500 net leasehold and
mineral acres by existing production in these areas.

Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale

The Meade Peak shale is an organic-rich source rock that has sourced much of the oil and natural gas

in conventional reservoirs in the western Wyoming and eastern Utah area. The Meade Peak shale has an
observed shale thickness of 70 to 350 feet, total organic carbon of 3% to 7% and vitrinite reflectance values
ranging from 1.8% to 2.7%. The Meade Peak shale is encountered at drill depths of 3,000 to 14,000 feet,
with the majority of our acreage in the depth range of 3,000 to 10,000 feet. The shale has been penetrated by
over 100 wells in the area, most of which have natural gas shows. Seismic and subsurface data show
distinct, stacked thrust plates with areas of sediment prospective for natural gas.

At December 31, 2011, we had assembled approximately 144,000 gross, or approximately 136,000 net,
acres in southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploratory
prospect targeting the Meade Peak shale. The majority of this acreage, with lease terms of five to ten years,
has been acquired by us within the past four to five years, and we are the operator of this prospect.

We believe there have been no previous attempts to drill horizontally or to hydraulically fracture the

Meade Peak shale in this area. Our focus to date has been to confirm the structure of the Meade Peak shale,
understand its characteristics and evaluate its potential. We have gathered well log data in the area and studied
the petrophysical characteristics. In addition, we have purchased 2-D seismic data and have worked with a
structural geologist that has experience in the immediate area to better understand the area’s tectonic history.

We have entered into a participation and joint operating agreement with other parties covering the
initial exploration efforts and, if successful, the future development of this acreage. We began drilling the
initial test well on this prospect, the Crawford Federal #1 well in Lincoln County, Wyoming, in February
2011. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale,
before having operations suspended for several months due to wildlife restrictions. We resumed operations
on this initial test well in September 2011 and completed drilling and coring operations on this well in
November 2011. At December 31, 2011, this well had not been completed, as we were still evaluating the
well logs and awaiting results from various core analysis tests.

Approximately 102,000 gross, or approximately 93,000 net, acres in this prospect are scheduled to

expire at various times during 2012. Although we plan to seek extensions on some of this acreage, certain
leases, particularly those taken on state lands, do not offer the opportunity for automatic extension, and we
will be required to obtain new leases on these lands should we desire and be able to do so. We expect that a
significant portion of the 93,000 net acres will be allowed to expire during 2012, while we and our partners
continue to evaluate the results from our initial test well and plan for its completion and further testing. We
have no production and no proved reserves attributable to this acreage at December 31, 2011.

Southeast New Mexico and West Texas — Delaware and Midland Basins

The Delaware and Midland Basins are mature exploration and production provinces with extensive

developments in a wide variety of petroleum systems resulting in stacked target horizons in many
areas. Historically, the majority of development in these basins has focused on relatively conventional
reservoir targets, but we believe the combination of advanced formation evaluation, 3-D seismic technology,
horizontal drilling and hydraulic fracturing technology is enhancing the development potential of these basins.

One example of such an opportunity appears to be the so-called “Wolf-Bone” play of the Delaware
Basin. Together, the Lower Permian age Bone Spring (also called Leonardian) and Wolfcamp formations
span several thousand feet of stacked shales, sandstones, limestones and dolomites representing complex
and dynamic submarine depositional systems that include several organic rich source rocks. Throughout
these intervals, oil and natural gas have been produced primarily from conventional sandstone and
carbonate reservoirs even though hydrocarbons are trapped in the tight sands, limestones and dolomites
interbedded within organic rich shale. Recently, these hydrocarbon-bearing zones have been recognized by
a number of operators as targets for horizontal drilling and multi-stage hydraulic fracturing techniques. As a
result, several large industry players are expanding positions and conducting drilling programs throughout
Lea and Eddy Counties in southeast New Mexico and Loving, Reeves and Ward Counties in west Texas.

Although the Delaware and Midland Basins have not been a primary focus of our recent operations or
exploration efforts, we were developing new oil and natural gas prospects in these basins at December 31, 2011.
Most notably, we have identified potential drilling opportunities on our acreage, particularly in southeast New
Mexico, near old vertical wells, some of which have produced up to 1,000,000 BOE from the Wolfcamp
formation and up to 500,000 BOE from the Bone Spring formation. These wells suggest a hydrocarbon-rich
environment in the area of our acreage, and after completing our internal geologic studies, we may determine to
drill a Wolfcamp or Bone Spring vertical well or to drill a horizontal well to test these formations on our acreage.

At December 31, 2011, we had not included any potential drilling locations on our acreage in our total identified
drilling locations, and we had not budgeted any capital expenditures to drill wells in southeast New Mexico or
west Texas during 2012. We have budgeted $20.0 million of our anticipated 2012 capital expenditures to acquire
additional leasehold interests primarily prospective for oil and liquids production in areas of southeast New
Mexico and west Texas where we are developing new prospects. Although we do have existing leasehold
interests in this area of approximately 11,000 gross and approximately 7,000 net acres at December 31, 2011, we
believe approximately 8,000 gross and 4,000 net acres are no longer prospective, and we plan to let them expire
without drilling.

Operating Summary

The following table sets forth certain unaudited production data for the years ended December 31,

2011, 2010 and 2009:

Unaudited Production Data
Net Production Volumes:

Year Ended December 31,

2011

2010

2009

Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (Bcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total natural gas equivalents (Bcfe)(1)
Average daily production (MMcfe/d)(1)

154
14.5
15.4
42.3

33
8.4
8.6
23.6

30
4.8
5.0
13.7

Average Sales Prices:

Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas, with realized derivatives (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas, without realized derivatives (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$93.80
$ 4.11
$ 3.62

$76.39
$ 4.38
$ 3.75

$57.72
$ 5.17
$ 3.59

Operating Expenses (per Mcfe):

Production taxes and marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 0.41
$ 0.47
$ 2.06
$ 0.87

$ 0.23
$ 0.61
$ 1.81
$ 1.13

$ 0.22
$ 0.94
$ 2.15
$ 1.42

(1) Estimated using a conversion ratio of one Bbl per six Mcf.

The following table sets forth information regarding our average net daily production and total

production for the year ended December 31, 2010 from our primary operating areas:

Average Net Daily Production

Gas
(Mcf/d)

Oil
(Bbls/d)

Gas Equivalent
(Mcfe/d)

Total Net
Production
(MMcfe)

Percentage of
Total Net
Production

South Texas:

Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Austin Chalk(1)

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4
–

NW Louisiana/E Texas:

Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cotton Valley(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

17,127
5,840

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

22,967

SW Wyoming, NE Utah, SE Idaho(1) . . . . . . . . . . . . . . . . . . . . . . . . . .
SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

–
43

Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

23,014

19
–

1
40

–
31

119
–

119

17,132
6,074

23,206

–
228

23,553

43
–

6,253
2,218

8,471

–
83

8,597

0.5%
–

0.5

72.7
25.8

98.5

–
1.0

100.0%

(1) We currently have no production from our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant

production from the Austin Chalk formation in south Texas.

(2)

Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange
County, Texas and two wells producing from the San Miguel formation in Zavala County, Texas.

The following table sets forth information regarding our average net daily production and total

production for the year ended December 31, 2011 from our primary operating areas:

Average Net Daily Production

Gas
(Mcf/d)

Oil
(Bbls/d)

Gas Equivalent
(Mcfe/d)

Total Net
Production
(MMcfe)

Percentage of
Total Net
Production

South Texas:

Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Austin Chalk(1)

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1,298
–

1,298

NW Louisiana/E Texas:

Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cotton Valley(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

32,319
6,084

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

38,403

SW Wyoming, NE Utah, SE Idaho(1) . . . . . . . . . . . . . . . . . . . . . . . . . .
SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

–
59

331
–

331

–
64

–
27

3,286
–

3,286

32,319
6,465

38,784

–
221

1,200
–

1,200

11,797
2,360

14,157

–
81

7.8%
–

7.8

76.4
15.3

91.7

–
0.5

Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

39,760

422

42,291

15,438

100.0%

(1) We currently have no production from our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant

production from the Austin Chalk formation in south Texas.

(2)

Our total production of 15.4 Bcfe for the year ended December 31, 2011 was an increase of 79% over

our total production of 8.6 Bcfe for the year ended December 31, 2010. This increased production was
primarily due to drilling operations in the Haynesville shale, but a portion of the increase also reflects
production due to our initial drilling operations in the Eagle Ford shale. Our total production of 8.6 Bcfe for
the year ended December 31, 2010 was an increase of 72% over our total production of 5.0 Bcfe for the
year ended December 31, 2009. Most of this increase was attributable to our drilling operations in the
Haynesville shale play. In addition, as a result of production from new wells that were completed in 2011,
our daily production for the year ended December 31, 2011 averaged approximately 42.3 MMcfe per day,
as compared to 23.6 MMcfe per day for the year ended December 31, 2010. Our daily oil production for the
year ended December 31, 2011 averaged 422 Bbls per day, an approximate five-fold increase from 91 Bbls
per day for the year ended December 31, 2010.

Producing Wells

The following table sets forth information relating to producing wells at December 31, 2011. Wells are

classified as oil or natural gas according to their predominant production stream. We do not have any
currently active dual completions. We have an approximate average working interest of 92% in all wells
that we operate. For wells where we are not the operator, our working interests range from less than 1% to
as much as 44%, and average approximately 9%. In the table below, gross wells are the total number of
producing wells in which we own a working interest, and net wells represent the total of our fractional
working interests owned in the gross wells.

Natural Gas Wells

Oil Wells

Total Wells

Gross

Net

Gross Net Gross Net

South Texas:

Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Austin Chalk(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Area Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

NW Louisiana/E Texas:

Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cotton Valley(2)

Area Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SW Wyoming, NE Utah, SE Idaho(1)
SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2.0
–

2.0

106.0
106.0

212.0
–
1.0

215.0

2.0
–

2.0

11.6
69.7

81.3
–
0.6

83.9

7.0
–

7.0

–
2.0

2.0
–
12.0

21.0

5.3
–

5.3

–
2.0

2.0
–
5.1

9.0
–

9.0

106.0
108.0

214.0
–
13.0

12.4

236.0

7.3
–

7.3

11.6
71.7

83.3
–
5.7

96.3

(1) We currently have no producing wells on our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant

production from the Austin Chalk formation in south Texas.

(2)

Includes shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells
producing from the San Miguel formation in Zavala County, Texas.

Estimated Proved Reserves

The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2011,

2010 and 2009. The reserves estimates were based on evaluations prepared by our engineering staff and
have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir
engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural
gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any
unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they
include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond
those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the
estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions. Our total estimated proved reserves are estimated using a
conversion ratio of one Bbl per six Mcf.

Estimated Proved Reserves Data:(2)
Estimated proved reserves:

Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas (Bcf)

Total (Bcfe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Estimated proved developed reserves:

Total (Bcfe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

At December 31,(1)

2011

2010

2009

3,794
170.4

193.2

1,419
56.5

65.1

152
127.4

128.3

152
43.1

44.1

103
63.9

64.5

103
25.4

26.0

Percent developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

33.7%

34.3% 40.3%

Estimated proved undeveloped reserves:

Total (Bcfe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2,375
113.9

128.1

–
84.3

84.3

–
38.6

38.6

PV-10(3) (in millions) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Standardized Measure(4) (in millions) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$248.7
$215.5

$119.9
$111.1

$70.4
$65.1

(1) Numbers in table may not total due to rounding.

(2) Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without

giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages
of the first-day-of-the-month prices for the 12 months ended December 31, 2009 were $57.65 per Bbl for oil and $3.866 per MMBtu for
natural gas, for the 12 months ended December 31, 2010 were $75.96 per Bbl for oil and $4.376 per MMBtu for natural gas, and for the
12 months ended December 31, 2011 were $92.71 per Bbl for oil and $4.118 per MMBtu for natural gas. These prices were adjusted by
lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the
price received at the wellhead.

(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP

financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair
market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved
reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific
tax characteristics of such entities. Our PV-10 at December 31, 2009, 2010 and 2011 may be reconciled to our Standardized Measure of
discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such
reserves. The discounted future income taxes at December 31, 2009, 2010 and 2011 were, in millions, $5.3, $8.8 and $33.2, respectively.

(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future

development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing
of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.

Our total proved oil and natural gas reserves increased from 128.3 Bcfe at December 31, 2010 to
193.2 Bcfe at December 31, 2011. Most of this increase is attributable to proved reserves added due to our
drilling operations in both the Eagle Ford and Haynesville shale plays. The increase in proved oil reserves
specifically from 152 MBbls at December 31, 2010 to 3,794 MBbls at December 31, 2011 is attributable to
proved oil reserves added due to our drilling operations in the Eagle Ford shale play. Our proved reserves at
December 31, 2011 were made up of approximately 88% natural gas and 12% oil. Our proved developed
reserves increased from 44.1 Bcfe at December 31, 2010 to 65.1 Bcfe at December 31, 2011 due primarily
to proved developed reserves added as a result of drilling operations in both the Eagle Ford and Haynesville
shale plays. The increase in proved developed oil reserves specifically from 152 MBbls at December 31,
2010 to 1,419 MBbls at December 31, 2011 is attributable to proved developed oil reserves added due to
our drilling operations in the Eagle Ford shale play. Our proved undeveloped reserves increased from 84.3
Bcfe at December 31, 2010 to 128.1 Bcfe at December 31, 2011 due primarily to our drilling operations in
the Eagle Ford and Haynesville shale plays. The increase in our proved undeveloped oil reserves
specifically from zero to 2,375 MBbls at December 31, 2011 is attributable to our drilling operations in the
Eagle Ford shale play. The net increase of 43.8 Bcfe in our proved undeveloped reserves from
December 31, 2010 to December 31, 2011 is composed of (1) additions of 49.0 Bcfe to proved undeveloped
reserves identified through drilling operations, less (2) the conversion of 3.4 Bcfe of proved undeveloped
reserves to proved developed reserves, less (3) the downward revisions of proved undeveloped reserves by
1.8 Bcfe in the period. During this period, we recorded no changes to proved undeveloped reserves as a
result of the acquisition or divestment of reserves. At December 31, 2011, we had no proved reserves in our
estimates that remained undeveloped for five years or more following their initial booking.

The following table sets forth additional summary information by operating area with respect to our

estimated proved reserves at December 31, 2011:

Net Proved Reserves(1)

Oil

Gas

Gas
Equivalent

PV-10(2)

Standardized
Measure(3)

(MBbls)

(Bcf)

(Bcfe)

(in millions)

South Texas:

Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Austin Chalk(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Area Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

NW Louisiana/E Texas:

Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cotton Valley(5)

Area Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SW Wyoming, NE Utah, SE Idaho(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3,636
–

3,636

–
61

61
–
97

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3,794

6.1
–

6.1

150.4
13.8

164.2
–
0.1

170.4

27.9
–

27.9

150.4
14.2

164.6
–
0.7

193.2

$130.2
–

130.2

96.6
19.5

116.1
–
2.4

$112.8
–

112.8

83.7
16.9

100.6
–
2.1

$248.7

$215.5

(1) Numbers in table may not total due to rounding.

(2) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP

financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair
market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved
reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific
tax characteristics of such entities. Our PV-10 at December 31, 2011 may be reconciled to our Standardized Measure of discounted
future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The
discounted future income taxes at December 31, 2011 were approximately $33.2 million.

(3) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future

(4) At December 31, 2011, we had no proved reserves attributable to the Austin Chalk formation in south Texas or to our acreage in

southwest Wyoming and adjacent areas of Utah and Idaho.

(5)

Includes Cotton Valley and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and
two wells producing from the San Miguel formation in Zavala County, Texas.

Technology Used to Establish Reserves

Under current SEC rules, proved 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. The term “reasonable certainty” implies a high degree of
confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate.
Reasonable certainty can be established using techniques that have been proven effective by actual
production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable
technology that establishes reasonable certainty. Reliable technology is a grouping of one or more
technologies (including computational methods) that have been field tested and have been demonstrated to
provide reasonably certain results with consistency and repeatability in the formation being evaluated or in
an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we used

technologies that have been demonstrated to yield results with consistency and repeatability. The
technologies and technical data used in the estimation of our proved reserves include, but are not limited to,
electric logs, radioactivity logs, core analyses, geologic maps and available downhole and production data,
seismic data and well test data. Reserves for proved developed producing wells were estimated using
production performance and material balance methods. Certain new producing properties with little
production history were forecast using a combination of production performance and analogy to offset
production. Non-producing reserves estimates for both developed and undeveloped properties were forecast
using either volumetric and/or analogy methods.

Internal Control Over Reserves Estimation Process

We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the

integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Reserves
Manager is primarily responsible for overseeing the preparation of our reserves estimates and has over
15 years of industry experience. Our Reserves Manager received his Ph.D. degree in Petroleum Engineering
from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and received a
certificate of completion in a prescribed course of study in Reserves and Evaluation from Texas A&M
University in May 2009. Our Vice President – Reservoir Engineering is responsible for reviewing and
approving our reserves estimates and has over 30 years of industry experience. Following the preparation of
our reserves estimates, we had our reserves estimates audited for their reasonableness by Netherland,
Sewell & Associates, Inc., our independent petroleum engineers. The Engineering Committee of our board
of directors reviews the reserves report and our reserves estimation process, and the results of the reserves
report and the independent audit of our reserves are reviewed by members of our board of directors,
including members of our Audit Committee.

Acreage Summary

The following table sets forth the approximate acreage in which we held a leasehold, mineral or other

interest at December 31, 2011. At that date, only about 12% of our total acreage had been developed,
although these percentages are much higher in northwest Louisiana and east Texas.

Developed Acres Undeveloped Acres

Total Acres

Gross

Net

Gross

Net

Gross

Net

South Texas:

Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Austin Chalk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Area Total(1)

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

NW Louisiana/E Texas:

Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cotton Valley(2)

Area Total(3)

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SW Wyoming, NE Utah, SE Idaho . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2,514
–

2,514

18,713
20,942

23,033
–
1,160

2,130
–

2,130

10,599
17,846

19,691
–
1,038

48,225
24,473

26,543
14,849

50,739
24,473

28,673
14,849

48,225

26,543

50,739

28,673

4,158
5,327

3,928
5,208

5,866
144,368
9,554

5,648
135,862
5,620

22,871
26,269

28,899
144,368
10,714

14,527
23,054

25,339
135,862
6,658

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

26,707

22,859

208,013

173,673

234,720

196,532

(1) Some of the same leases cover the net acres shown for the Eagle Ford shale and the Austin Chalk formation, a shallower formation than

the Eagle Ford shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

(2)

Includes shallower zones and also includes acreage surrounding one well producing from the Frio formation in Orange County, Texas.

(3) Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formation

than the Haynesville shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

Undeveloped Acreage Expiration

The following table sets forth the approximate number of gross and net undeveloped acres at
December 31, 2011 that will expire prior to December 31, 2013 by operating area unless production is
established within the spacing units covering the acreage prior to the expiration dates or unless the existing
leases are renewed prior to expiration:

Acres
Expiring 2012

Acres
Expiring 2013

Gross

Net

Gross

Net

South Texas:

Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Austin Chalk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

15,044
5,731

4,349
1,133

12,165
3,851

Area Total(1)

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

15,044

4,349

12,165

NW Louisiana/E Texas

Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cotton Valley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

644
750

395
401

Area Total(2)

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SW Wyoming, NE Utah, SE Idaho . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

750
101,905
1,712

401
93,356
79

40
40

40
8,461
8,454

7,149
2,646

7,149

5
5

5
8,301
2,715

Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

119,411

98,185

29,120

18,170

(1) Some of the same leases cover the net acres shown for the Eagle Ford shale and the Austin Chalk formation, a shallower formation than

the Eagle Ford shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

(2) Some of the same leases cover the net acres shown for the Haynesville shale and the Cotton Valley formation, a shallower formation than

the Haynesville shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

Many of the leases comprising the acreage set forth in the table above will expire at the end of their

respective primary terms unless production from the acreage has been established prior to such date, in
which event the lease will remain in effect until the cessation of production in commercial quantities. We
also have options to extend some of our leases through payment of additional lease bonus payments prior to
the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the
expiration of certain of our acreage; however, there may be third party leases that become effective
immediately if our leases expire at the end of their respective terms and production has not been established
prior to such date. Our leases are mainly fee leases with three to five years of primary term. We believe that
our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and
royalty interests.

Drilling Results

The following table summarizes our drilling activity for the three years ended December 31, 2011,

2010 and 2009:

Year Ended December 31,

2011

2010

2009

Gross Net Gross Net Gross Net

Development Wells

Productive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Exploration Wells

Total Wells

30
–

60
–

0.6
–

10.2
–

10.8
–

5
–

36
–

41
–

1.7
–

3.4
–

5.1
–

3
–

15
2

18
2

1.3
–

6.0
2.0

7.3
2.0

Marketing

Our crude oil is generally sold under short-term, extendable and cancellable agreements with

unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a
consequence, the prices we receive for crude oil and liquids move up and down in direct correlation with the
oil market as it reacts to supply and demand factors. Transportation costs related to moving crude oil are
also deducted from the price received for crude oil.

Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural

gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated
independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices
that are based on various pipeline indices less any associated fees. When there is an opportunity to do so,
the mid-stream companies may, at our request, process our natural gas at a processing facility and extract
liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on a negotiated
percentage of the proceeds that are generated from the mid-stream companies’ sale of the liquids, or based
on other negotiated pricing arrangements.

The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price
fluctuations include the level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf
Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of
OPEC, price and availability of alternative fuels, political conditions in oil and natural gas producing
regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall

economic conditions. Decreases in these commodity prices do adversely affect the carrying value of our
proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural
gas production do occur from time to time due to downstream pipeline system failure, capacity issues and
scheduled maintenance, as well as maintenance and repairs involving our own well operations. These
situations do curtail our production capabilities and ability to maintain a steady source of revenue for our
company. In addition, demand for natural gas has historically been seasonal in nature, with peak demand
and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent
on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These
Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure
Requirements and Financial Obligations.”

For the year ended December 31, 2009, we had three significant purchasers that each accounted for
more than 10% of our total oil and natural gas revenues: Chesapeake Operating Inc. (32%), Regency Gas
Services LP (25%), and J-W Operating Company (17%). For the year ended December 31, 2010, we had
three significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues:
Chesapeake Operating Inc. (42%), Regency Gas Services LP (17%) and Petrohawk Energy Corporation
(11%). For the year ended December 31, 2011, we had three significant purchasers that each accounted for
more than 10% of our total oil and natural gas revenues: Sequent Energy Management (24%), Chesapeake
Operating Inc. (21%) and Eastex Crude Company (15%). Due to the nature of the markets for oil and
natural gas, we do not believe that the loss of any one of these purchasers would have a material adverse
impact on our financial condition, results of operations or cash flows for any significant period of time.

While we do not have any commitments to sell a fixed and determinable quantity of oil or natural gas
to a particular buyer, we were party to two natural gas transportation agreements at December 31, 2011 that
require us to deliver a specified volume of natural gas through pipelines for a fixed period of time. If we fail
to meet the volume requirements, we are required to pay an amount to the owners of the pipelines to offset a
portion of the expenses they incurred in building the pipelines to our well locations. Neither of these
contracts constitutes a material commitment.

Title to Properties

We endeavor to assure that title to our properties is in accordance with standards generally accepted in

the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term
assignments and other contractual arrangements with third parties, the terms of which often will require the
drilling of wells or the undertaking of other exploratory or development activities in order to retain our
interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory
fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident
to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially
interfere with the use and operation of or affect the value of these properties. We intend to maintain our
leasehold interests by making lease rental payments or by producing wells in paying quantities prior to
expiration of various time periods to avoid lease termination. Certain of the leases that we have obtained to
date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk
Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We
Invest.”

Competition

The oil and natural gas industry is highly competitive. We compete and will continue to compete with

major and independent oil and natural gas companies for exploration opportunities, acreage and property
acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill,

operate and develop our properties. Most of our competitors have substantially greater financial resources,
staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any
changes in federal, state and local laws and regulations more easily than we can, which would adversely
affect our competitive position. These competitors may be able to pay more for drilling rigs or exploratory
prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and
purchase a greater number of properties and prospects than we can. Our competitors may also be able to
afford to purchase and operate their own drilling rigs.

Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our
ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in
this highly competitive environment. We have been conducting field operations since 2004 while our
competitors have a longer history of operations, and most of them have also demonstrated the ability to
operate through industry cycles.

The oil and natural gas industry also competes with other energy-related industries in supplying the

energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors –
Competition in the Oil and Natural Gas Industry Is Intense Making It More Difficult for Us to Acquire
Properties, Market Natural Gas and Secure Trained Personnel.”

Regulation

Oil and Natural Gas Regulation

Our oil and natural gas exploration, development, production and related operations are subject to

extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and
regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry
increases our cost of doing business and affects our profitability. Because these rules and regulations are
frequently amended or reinterpreted and new rules and regulations are promulgated, we are unable to
predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will
become, subject. Our competitors in the oil and natural gas industry are generally subject to the same
regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future
government regulation on our properties or operations.

Texas, New Mexico, Louisiana, Wyoming, Idaho and Utah and many other states require permits for

drilling operations, drilling bonds and reports concerning operations and impose other requirements relating
to the exploration, development and production of oil and natural gas. Many states also have statutes or
regulations addressing conservation of oil and natural gas matters, including provisions for the unitization or
pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the
regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the
sourcing and disposal of water used in the drilling and completion process and the plugging and
abandonment of these wells. Many states restrict production to the market demand for oil and natural gas.
Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries.
Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on
production by restricting the rate of flow of oil and natural gas wells below natural production capacity in
order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or
severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its
jurisdiction.

Some of our oil and natural gas leases are issued by agencies of the federal government, as well as

agencies of the states in which we operate. These leases contain various restrictions on access and
development and other requirements that may impede our ability to conduct operations on the acreage
represented by these leases.

Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the
availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate
transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or
FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas
Policy Act of 1978, or the NGPA. 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. The natural gas industry has
historically, however, been heavily regulated and we can give no assurance that the current less stringent
regulatory approach of FERC will continue.

In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act.

The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any
entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical
natural gas in interstate commerce, and to significantly increase the penalties for violations of the NGA, the
NGPA, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement
the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in
addition to FERC-imposed penalties, we may also be subject to third party damage claims.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for
intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given
to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will
apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the
regulation in any states in which we operate will not affect our operations in any way that is materially
different from our competitors that are similarly situated.

The price we receive from the sale of oil and natural gas liquids will be affected by the availability,

terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil
pipelines can change rates based on an inflation index, though other rate mechanisms may be used in
specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state
regulatory commissions, which varies from state to state. We are not able to predict with certainty the
effects, if any, of these regulations on our operations.

In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA,

among other things, prohibits market manipulation by any person in connection with the purchase or sale of
crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that
the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the
regulations and establishes penalties for violations thereunder. We cannot predict any future regulations or
their impact.

U.S. Federal and State Taxation

The federal, state and local governments in the areas in which we operate impose taxes on the oil and

natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our
drilling and operating costs. In the past, there has been a significant amount of discussion by legislators and

presidential administrations concerning a variety of energy tax proposals. President Obama has recently
proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration
and production companies such as us. President Obama has proposed to eliminate allowing small U.S. oil
and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Many
states have raised state taxes on energy sources, and additional increases may occur. Changes to tax laws
could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to
Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced
Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas
Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our
Business, Financial Condition, Results of Operations and Cash Flows.”

Hydraulic Fracturing Policies and Procedures

We use hydraulic fracturing as a means to maximize the productivity of our oil and natural gas wells in

almost every well that we drill and complete. Our engineers responsible for these operations attend
specialized hydraulic fracturing training programs taught by industry professionals. Although average
drilling and completion costs for each area will vary, as will the cost of each well within a given area, on
average approximately 50% of the drilling and completion costs for our horizontal wells are associated with
hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and
completion of our wells are treated and are built into and funded through our normal capital expenditures
budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact
these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State
Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and
Additional Operating Restrictions or Delays.”

The protection of groundwater quality is important to us. We believe that we follow all state and federal

regulations and apply industry standard practices for groundwater protection in our operations. These
measures are subject to close supervision by state and federal regulators (including the BLM with respect to
federal acreage). Our policy and practice is to follow all applicable guidelines and regulations in the areas
where we conduct hydraulic fracturing. A surface casing string is typically set deeper than the deepest usable
quality fresh water zones and cemented back to the surface in accordance with the appropriate regulations,
lease requirements and legal requirements. This surface string of casing is then pressure tested to ensure
mechanical integrity of the casing string prior to continuing drilling operations. We follow strict quality
control procedures for conducting hydraulic fracturing operations that include a multi-point safety checklist,
managing inventories of all materials and chemicals on the well site and ensuring that Material Safety Data
Sheets are on location for every well that is hydraulically fractured. We contract with third parties to conduct
hydraulic fracturing operations, and we send at least one of our own engineers or an experienced consultant to
the well site to personally supervise each hydraulic fracture treatment. On a real-time basis, we closely monitor
pump rates and pressures on existing casing strings to ensure that wellbore integrity is maintained during
hydraulic fracturing operations. Our policy regarding monitoring well pressures would require stopping the
hydraulic fracturing operations upon any indication that wellbore integrity may have been compromised.

We follow additional regulatory requirements and recommended practices to ensure wellbore integrity

and full isolation of any underground aquifers and protection of surface waters. These include the
following:

• Prior to perforating the production casing and hydraulic fracturing operations, a cement bond log is
run to verify cement integrity between the formation to be fractured and shallow formations. Then,
the casing is pressure tested to ensure no leaks exist within the casing;

• Before the fracturing operation commences, all surface equipment is pressure tested, which
includes the wellhead and all high pressure lines and connections leading from the pumping
equipment to the wellhead. During the pumping phases of the hydraulic fracturing treatment, the
service companies we engage must provide specialized equipment to monitor and record surface
pressures, pumping rates, volumes and chemical concentrations to ensure the treatment is
proceeding as designed and the wellbore integrity is sound. Our engineers at the job site have
laptop computers with special software to monitor and collect, for permanent archiving,
information from the hydraulic fracturing operations. As part of this process, when fracturing
operations are being performed down casing, we also monitor the casing annular pressure to ensure
that there is no communication of hydraulic pressure and fracture fluids outside the casing that
could communicate with shallow formations. Should any problem be detected at any time during
the hydraulic fracturing treatment, the operation would be shut down until the problem is evaluated,
reported and remediated; and

• As a means to further protect against the negative impacts of any potential surface release of fluids
associated with the hydraulic fracturing operation, special precautions are taken both during and
after the operation. During the fracturing operation, all chemicals are mixed into the fracturing fluid
as it is being pumped into the well as opposed to being pre-mixed in the “frac pits” or work tanks.
While chemical additives are stored on location in independent containment vessels, only fresh
water is stored in the frac pits or work tanks. All pumping equipment used during the operation is
pressure tested and monitored. When the well is flowed back, after the fracturing operation, all
fluids are produced into closed-top storage tanks. All flowback equipment and piping are pressure
tested to ensure no leaks are present and the fluids are properly contained.

Once the final string of casing is set in place, cement is pumped into the casing/wellbore annulus
where it hardens and creates a permanent, isolating barrier between the steel casing pipe and surrounding
geological formations. This aspect of the well design establishes a pressure seal essentially eliminating any
pathway for the fracturing fluid to contact fresh water aquifers during the hydraulic fracturing operation.
Furthermore, in the areas in which we conduct hydraulic fracturing, the hydrocarbon bearing formations are
separated from any usable quality underground fresh water aquifers by thousands of feet of impermeable
rock layers. This natural geological separation serves as a protective barrier, preventing migration of
fracturing fluids or hydrocarbons upwards into any fresh water zones.

Although rare, if and when the cement and steel casing used in well construction need to be

remediated, we deal with these problems by evaluating the issue, running diagnostic tools including cement
bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs. We repair
wellhead leaks by replacing wellhead components, re-installing components to proper specifications and
re-testing. In wellbores that utilize downhole packers, pressure integrity issues are rectified by repairing or
replacing packers. Casing integrity lost due to corrosion on a producing well is remedied by identifying the
specific location of the leak by cased hole logging tools, mechanical isolation and pressure testing or other
diagnostic methods, followed by high pressure squeeze cementing and subsequent pressure testing to ensure
the leak has been repaired. Throughout the process we believe we abide by applicable regulations.

The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of

man-made propping agents. We use major hydraulic fracturing service companies who track and report
chemical additives that are used in the fracturing operation as required by the appropriate governmental
agencies. These service companies fracture stimulate thousands of wells each year for the industry and
invest millions of dollars to protect the environment through rigorous safety procedures, and also work to

develop more environmentally friendly fracturing fluids. As previously mentioned, we also follow strict
safety procedures and monitor all aspects of the fracturing operation to ensure environmental protection.
We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures.

While current fracture stimulation procedures utilize a significant amount of water, we typically
recover less than 10% of this fracture stimulation water before produced salt water becomes a significant
portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in a
way that does not impact surface waters. All produced water is disposed of in permitted and regulated
disposal facilities.

Environmental Regulation

The exploration, development and production of oil and natural gas, including the operation of salt
water 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. Our activities are subject to a variety of environmental laws and
regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act,
or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA,
the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking
Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable
state statutes and regulations. We are also subject to regulations governing the handling, transportation,
storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or
NORM, that may result from our oil and natural gas operations. Civil and criminal fines and penalties may
be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and
regulations require the acquisition of permits or other governmental authorizations before undertaking some
activities, limit or prohibit other activities because of protected wetlands, areas or species and require
investigation and cleanup of pollution. We expect to remain in compliance in all material respects with
currently applicable environmental laws and regulations and expect that these laws and regulations will not
have a material adverse impact on us.

The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention
of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining
shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90
may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict,
joint and several financial liability for removal costs and other damages, including natural resource
damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on
responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the
OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct
operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that
compliance with applicable requirements under the OPA 90 will not have a material and adverse effect on
us.

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of
produced waters, fill materials and other materials into navigable waters. These controls have become more
stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits
are required to discharge pollutants into certain state and federal waters and to conduct construction
activities in those waters and wetlands. Certain state regulations and the general permits issued under the
federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water,

produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry
into certain coastal and offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has
adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for
storm water discharges. Costs may be associated with the treatment of wastewater or developing and
implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil,
criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose
liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance
of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require
certain oil-storing facilities to prepare plans and meet construction and operating standards.

CERCLA, also known as the “Superfund” law, and comparable state statutes impose liability, without

regard to fault or the legality of the original conduct, on various classes of persons that are considered to
have contributed to the release of a “hazardous substance” into the environment. These persons include the
owner or operator of the disposal site where the release occurred and companies that disposed of, or
arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for
releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs
of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not
uncommon for neighboring landowners and other third parties to file claims for personal injury and property
damage allegedly caused by hazardous substances released into the environment. Although CERCLA
generally exempts petroleum from the definition of hazardous substances, our operations may, and in all
likelihood will, involve the use or handling of materials that may be classified as hazardous substances
under CERCLA. Certain state statutes may not contain a similar exemption for petroleum. Furthermore, we
may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed
to, prior releases of hazardous wastes.

RCRA and comparable state and local statutes govern the management, including treatment, storage and

disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid
waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows
many wastes associated with crude oil and natural gas exploration and production to be classified as
nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the
wastes we generate fall within these exemptions. At various times in the past, proposals have been made to
amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production
wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through
changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage
and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous
wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes.

The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many
sources, including oil and natural gas production. These laws and any implementing regulations impose
stringent air permit requirements and require us to obtain pre-approval for the construction or modification
of certain projects or facilities expected to produce air emissions, or to use specific equipment or
technologies to control emissions. On July 28, 2011, the EPA proposed new regulations targeting air
emissions from the oil and natural gas industry. The proposed rules, if adopted, would impose new
requirements on production and processing and transmission and storage facilities and on hydraulic
fracturing activities. While we may be required to incur certain capital expenditures in the next few years
for air pollution control equipment in connection with maintaining or obtaining operating permits
addressing other air emission-related issues, we do not believe that such requirements will affect our
operations in any way that is materially different from our competitors.

Changes in environmental laws and regulations occur frequently, and any changes that result in more

stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could
materially adversely affect our operations and financial position, as well as those of the oil and natural gas
industry in general. For instance, recent scientific studies have suggested that emissions of certain gases,
commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing
to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive
greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or
implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood
would, require us to incur increased operating costs adversely affecting our profits and could adversely affect
demand for the oil and natural gas we produce depressing the prices we receive for oil and natural gas.

The EPA has published its findings that emissions of greenhouse gases presented an endangerment to

human health and the environment. These findings by the EPA allow the agency to proceed with the
adoption and implementation of regulations that would restrict emissions of greenhouse gases under
existing provisions of the CAA. Subsequently, the EPA proposed and adopted two sets of regulations, one
of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which
regulated emissions of greenhouse gases from certain large stationary sources. In addition, on October 30,
2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources
in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a
rule that expands its final rule on greenhouse gas emissions reporting to include owners and operators of
onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage,
natural gas transmission and natural gas distribution facilities. Reporting of greenhouse gas emissions from
such onshore production will be required on an annual basis beginning in 2012 for emissions occurring in
2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting
emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require
us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting
our profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices
we receive for oil and natural gas.

Some states have begun taking actions to control and/or reduce emissions of greenhouse gases,
primarily through the planned development of greenhouse gas emission inventories and/or state or regional
greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on
significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less
significant sources of emissions could become subject to greenhouse gas emission limitations or emissions
allowance purchase requirements in the future. Any one of these climate change regulatory and legislative
initiatives could have a material adverse effect on our business, financial condition, results of operations and
cash flows.

Underground injection is the subsurface placement of fluid through a well, such as the reinjection of
brine produced and separated from oil and natural gas production. In our industry, underground injection
not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can
increase the oil production from such zone. The SDWA establishes a regulatory framework for underground
injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and
to prevent migration of fluids from the injection zone into underground sources of drinking water. The
disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of
produced water. We currently own and operate five underground injection wells and expect to own other
similar wells. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could
subject us to civil and/or criminal enforcement actions and penalties.

Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing
operations, see “Business — Regulation — Hydraulic Fracturing Policies and Procedures.” Recently, there
has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation
as underground injection on the federal level pursuant to the SDWA. However, the U.S. Senate and House
of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would
amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities.
If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial
assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and
recordkeeping obligations, and meet plugging and abandonment requirements. These legislative proposals
have also contained language to require the reporting and public disclosure of chemicals used in the
fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other
legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing
contained in any such legislation could have a significant impact on our financial condition, results of
operations and cash flows.

In addition, at the federal level and in some states, there has been a push to place additional regulatory

burdens upon hydraulic fracturing activities and in some areas to severely restrict or prohibit those
activities. Certain bills have been introduced in the Senate and the House of Representatives that, 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, and in all likelihood would,
result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations
and increasing our costs of compliance. At the state level, Wyoming and Texas, for example, have enacted
requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. On June 17,
2011, Texas signed into law a mandate for public disclosure of the chemicals that operators use during
hydraulic fracturing in Texas. The law went into effect in 2011 and implementing regulations have been
adopted. In addition, at least a few local governments in Texas have imposed temporary moratoria on
drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to
address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting
requirements or permitting requirements for the hydraulic fracturing activity, will result in additional
expense and delay in our operations.

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. The EPA is currently conducting a
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. In addition, in December 2011, the EPA published an
unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas
field in Wyoming. This study remains subject to review and public comment but such studies could result in
additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our
costs of compliance and doing business.

Oil and natural gas exploration and production, operations and other activities have been conducted at
some of our properties by previous owners and operators. Materials from these operations remain on some
of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to
indemnify sellers of producing properties from whom we acquire reserves against some of the liability for
environmental claims associated with these properties. While we do not believe that costs we incur for
compliance with environmental regulations and remediating previously or currently owned or operated
properties will be material, we cannot provide any assurances that these costs will not result in material
expenditures that adversely affect our profitability.

Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks,
including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and
environmental compliance. It is also possible that our oil and natural gas operations may require us to
manage NORM. NORM is present in varying concentrations in sub-surface formations, including
hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in
contact with crude oil and natural gas production and processing streams. Some states, including Texas,
have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we
will be able to control directly the operations of only those wells for which we act as the operator. Despite
our lack of control over wells owned by us but operated by others, the failure of the operator to comply with
the applicable environmental regulations may, in certain circumstances, be attributable to us.

We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard
Communication Standard, the “community right-to-know” regulations under Title III of the federal
Superfund Amendments and Reauthorization Act and similar state statutes require us to organize
information about hazardous materials used, released or produced in our operations. Certain of this
information must be provided to employees, state and local governmental authorities and local citizens. We
are also subject to the requirements and reporting set forth in OSHA workplace standards.

We have not in the past been, and do not anticipate in the near future to be, required to expend amounts

that are material in relation to our total capital expenditures as a result of environmental laws and
regulations, but since these laws and regulations are periodically amended, we are unable to predict the
ultimate cost of compliance. We cannot assure you that more stringent laws and regulations protecting the
environment will not be adopted or that we will not otherwise incur material expenses in connection with
environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government
Regulation and Liability, including Complex Environmental Laws, Which Could Require Significant
Expenditures.”

The clear trend in environmental regulation is to place more restrictions and limitations on activities

that may affect the environment, and thus, any changes in environmental laws and regulations or
re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage,
transport, disposal or remediation requirements could have a material adverse effect on our operations and
financial position. We may be unable to pass on such increased compliance costs to our customers.
Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you
that we will not incur significant costs and liabilities as a result of such releases or spills, including any third
party claims for damage to property, natural resources or persons.

We maintain insurance against some, but not all, potential risks and losses associated with our industry

and operations. We do not currently carry business interruption insurance. For some risks, we may not
obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In
addition, pollution and environmental risks generally are not fully insurable. If a significant accident or
other event occurs and is not fully covered by insurance, it could materially adversely affect our financial
condition, results of operations and cash flows.

Office Lease

Our corporate headquarters are located in 28,743 square feet of office space in One Lincoln Centre,

5400 LBJ Freeway, Suite 1500, Dallas, Texas. In April 2011, we entered into a third amended and restated
office lease agreement pursuant to which our office space was increased from 20,849 to 28,743 square feet
and the term of our lease was extended from July 1, 2011 to June 30, 2022. Beginning July 1, 2011, through

June 30, 2012, we are not required to pay a monthly base rent. From July 1, 2012 through June 30, 2015,
our monthly base rent is $47,905. From July 1, 2015 through June 30, 2017, our monthly base rent is
$50,300. From July 1, 2017 through June 30, 2019, our monthly base rent is $52,696. From July 1, 2019
through June 30, 2020, our monthly base rent is $55,091. From July 1, 2020 through the expiration date of
the lease, our monthly base rent is $57,726. In addition, the lease contains a renewal option in our favor for
an additional 60-month period at the then existing market rate as determined in accordance with the lease.

Employees

At December 31, 2011, we had 41 full-time employees. We believe that our relationships with our
employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to
time, we use the services of independent consultants and contractors to perform various professional
services, particularly in the areas of geology and geophysics, construction, design, well site surveillance and
supervision, permitting and environmental assessment and legal and income tax preparation and accounting
services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site
production operation services for us, including pumping, maintenance, dispatching, inspection and testing.
If significant opportunities for company growth arise and require additional management and professional
expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to
develop those opportunities.

Available Information

Our Internet website address is www.matadorresources.com. We expect to make available, free of
charge, through our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing
such reports to the SEC. Also, the charters of our Audit Committee and Nominating, Compensation and
Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees,
are available through our website and in print to any shareholder who provides a written request to the
Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The
contents of our website are not intended to be incorporated by reference into this report or any other report
or document we file and any reference to our website is intended to be an inactive textual reference only.

Item 1A. Risk Factors.

Risks Related to the Oil and Natural Gas Industry and Our Business

Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the
Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to
Meet Our Capital Expenditure Requirements and Financial Obligations.

The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow

available for capital expenditures, access to capital and future rate of growth. Oil and natural gas are
commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor
changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These
markets will likely continue to be volatile in the future. The prices we receive for our production, and the
levels of our production, depend on numerous factors. These factors include the following:

• the domestic and foreign supply of oil and natural gas;

• the domestic and foreign demand for oil and natural gas;

• the prices and availability of competitors’ supplies of oil and natural gas;

• the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled

oil companies relating to oil price and production controls;

• the price and quantity of foreign imports;

• the impact of U.S. dollar exchange rates on oil and natural gas prices;

• domestic and foreign governmental regulations and taxes;

• speculative trading of oil and natural gas futures contracts;

• the availability, proximity and capacity of gathering and transportation systems for natural gas;

• the availability of refining capacity;

• the prices and availability of alternative fuel sources;

• weather conditions and natural disasters;

• political conditions in or affecting oil and natural gas producing regions, including the Middle East

and South America;

• the continued threat of terrorism and the impact of military action and civil unrest;

• public pressure on, and legislative and regulatory interest within, federal, state and local

governments to stop, significantly limit or regulate hydraulic fracturing activities;

• the level of global oil and natural gas inventories and exploration and production activity;

• the impact of energy conservation efforts;

• technological advances affecting energy consumption; and

• overall worldwide economic conditions.

Approximately 98% of our production during the year ended December 31, 2010, 94% of our
production during the year ended December 31, 2011 and 88% of our proved reserves at December 31,

2011 are attributable to natural gas. In addition, three of our largest prospects, our Haynesville shale, Cotton
Valley properties and our Meade Peak shale prospect, currently produce or are expected to produce
predominantly natural gas. As a result, they are sensitive to fluctuations in natural gas prices.

One of our current business strategies is to focus on increasing our oil and liquids production.
Specifically, our near-term drilling opportunities in the Eagle Ford shale play focus on oil and liquids. We
currently intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration of
the Eagle Ford shale. We believe that approximately 85% of our Eagle Ford acreage is prospective
predominantly for oil and liquids production, and we have identified 193 gross locations for potential future
drilling in our Eagle Ford acreage. Therefore, our Eagle Ford shale play is highly susceptible to changes in
oil prices.

Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of

oil and natural gas that we can produce economically. Should natural gas or oil prices decrease to
economically unattractive levels and remain there for an extended period of time, we may elect in the future
to delay some of our exploration and development plans for our prospects, or to cease exploration or
development activities on certain prospects due to the anticipated unfavorable economics from such
activities, each of which would have a material adverse effect on our business, financial condition, results of
operations and reserves.

In recent months, natural gas prices have declined to their lowest levels in many years, and at

Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk,
with Many Uncertainties That Could Adversely Affect Our Business.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial

risk, which precludes us from definitively predicting the costs involved and time required to reach certain
objectives. Our drilling locations are in various stages of evaluation, ranging from a location that is ready to
drill to a location that will require substantial additional interpretation before it can be drilled. The budgeted
costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase
significantly due to various complications that may arise during the drilling and operating processes. Before a
well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether
a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a
much greater risk of loss than development wells. The analogies we draw from available data from other
wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our
actual drilling and development costs are significantly more than our estimated costs, we may not be able to
continue our operations as proposed and could be forced to modify our drilling plans accordingly.

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas

reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We
may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after
drilling, operating and other costs. There is no way to predict in advance of drilling and testing whether any
particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling or
completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may

damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties
while drilling or completing the well, resulting in a reduction in production and reserves from the well or
abandonment of the well. Whether a well is ultimately productive and profitable depends on a number of
additional factors, including the following:

• general economic and industry conditions, including the prices received for oil and natural gas;

• shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and

qualified personnel;

• potential drainage by operators on adjacent properties;

• loss of or damage to oilfield development and service tools;

• problems with title to the underlying properties;

• increases in severance taxes;

• adverse weather conditions that delay drilling activities or cause producing wells to be shut down;

• domestic and foreign governmental regulations; and

• proximity to and capacity of transportation facilities.

If we do not drill productive and profitable wells in the future, our business, financial condition, results

of operations, cash flows and reserves could be materially and adversely affected.

We May Have Accidents, Equipment Failures or Mechanical Problems While Drilling or Completing Wells
or in Production Activities, Which Could Adversely Affect Our Business.

While we are drilling and completing wells or involved in production activities, we may have accidents

or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and
complete the well or to continue to produce the well according to our plans. We may also damage a
potentially hydrocarbon-bearing formation during drilling and completion operations. Such incidents may
result in a reduction of our production and reserves from the well or in abandonment of the well.

Because Our Reserves and Production Are Concentrated in a Small Number of Properties, Problems in
Production and Markets Relating to Any Property Could Have a Material Impact on Our Business.

Almost all of our current oil and natural gas production and our proved reserves are attributable to
properties in northwest Louisiana and east Texas, and we expect that most of our operations in the near
future will be primarily in south Texas. As a result, we may be disproportionately exposed to the impact of
delays or interruptions of production from these wells caused by transportation capacity constraints or
interruptions, curtailment of production, availability of equipment, facilities, personnel or services,
significant governmental regulation, natural disasters, adverse weather conditions or plant closures for
scheduled maintenance. In particular, our operations in south Texas may be adversely impacted by a lack of
pipeline infrastructure and natural gas processing facilities in light of the oil and natural gas industry’s
increased focus on the exploration and development of the Eagle Ford shale. Our operations in south Texas
may also be adversely affected by hurricanes and tropical storms resulting in delays in exploration and
drilling, damage to facilities and equipment and the inability to receive equipment or to access personnel
and products at affected job sites in a timely manner. Due to the concentrated nature of our portfolio of
properties, a number of our properties could experience any of the same conditions at the same time,
resulting in a relatively greater impact on our results of operations than they might have on other companies
that have a more diversified portfolio of properties. Such delays or interruptions could have a material
adverse effect on our financial condition, results of operations and cash flows.

Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which
Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our
future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent
on our success in: (i) efficiently developing and exploiting our current reserves on properties owned by us or by
other persons or entities and (ii) economically finding or acquiring additional oil and natural gas producing
properties. We are currently focusing primarily on increasing our production and reserves from the Eagle Ford
shale play, an area in which industry activity has increased rapidly. As a result of this increased activity, we may
have difficulty expanding our current production or acquiring new properties in this area and may experience
such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, it will become
more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current
and future production, our reserves will decrease, and our business, financial condition, results of operations and
cash flows would be adversely affected.

Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and
Natural Gas We Will Receive, and Significant Inaccuracies in These Reserves Estimates or Underlying
Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.

The process of estimating accumulations of oil and natural gas is complex and is not exact, due to numerous
inherent uncertainties. The process relies on interpretations of available geological, geophysical, engineering and
production data. The extent, quality and reliability of this technical data can vary. The process also requires
certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function
of:

• the quality and quantity of available data;

• the interpretation of that data;

• the judgment of the persons preparing the estimate; and

• the accuracy of the assumptions.

The accuracy of any estimates of proved reserves generally increases with the length of the production
history. Due to the limited production history of many of our properties, the estimates of future production
associated with these properties may be subject to greater variance to actual production than would be the
case with properties having a longer production history. As our wells produce over time and more data is
available, the estimated proved reserves will be redetermined on at least an annual basis and may be
adjusted to reflect new information based upon our actual production history, results of exploration and
development, prevailing oil and natural gas prices and other factors.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures,

operating expenses and quantities of recoverable oil and natural gas most likely will vary from our
estimates. It is possible that future production declines in our wells may be greater than we have estimated.
Any significant variance to our estimates could materially affect the quantities and present value of our
reserves.

The Calculated Present Value of Future Net Revenues from Our Proven Reserves Will Not Necessarily Be
the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves.

It should not be assumed that the present value of future net cash flows included in this report is the

current market value of our estimated proved oil and natural gas reserves. We generally base the estimated
discounted future net cash flows from proved reserves on current costs held constant over time without
escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index

prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual
future prices and costs may be materially higher or lower than the prices and costs used for these estimates and
will be affected by factors such as:

• actual prices we receive for oil and natural gas;

• actual cost and timing of development and production expenditures;

• the amount and timing of actual production; and

• changes in governmental regulations or taxation.

In addition, the 10% discount factor that is required to be used to calculate discounted future net

revenues for reporting purposes under Generally Accepted Accounting Principles, or GAAP, is not
necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and
risks associated with our business and the oil and natural gas industry in general.

Approximately 67% of Our Total Proved Reserves at December 31, 2011 Consisted of Undeveloped and
Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced.

At December 31, 2011, approximately 66% of our total proved reserves were undeveloped and

approximately 1% were developed non-producing. Our undeveloped and/or developed non-producing reserves
may never be developed or produced or such reserves may not be developed or produced within the time periods
we have projected or at the costs we have budgeted. Delays in the development of our reserves or increases in
costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped
reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical.
In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate
proved reserves in the future could cause us to have to reclassify our proved reserves as unproved reserves, which
would materially affect our business, financial condition, results of operations and ability to raise capital.

Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That
May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to
Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.

Our exploration and development activities are capital intensive. We make and expect to continue to

make substantial capital expenditures in our business for the development, exploitation, production and
acquisition of oil and natural gas reserves. Our cash and cash equivalents, operating cash flows and future
potential borrowings under our credit agreement or otherwise may not be adequate to fund our future
acquisitions or future capital expenditure requirements. The rate of our future growth may be dependent, at
least in part, on our ability to access capital at rates and on terms we determine to be acceptable.

We may sell additional securities to raise capital. If we succeed in selling additional securities to raise

funds, at such time the ownership of our existing shareholders would likely be diluted, and new investors
may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional
capital through the issuance of new debt securities or additional indebtedness, we may become subject to
additional covenants that restrict our business activities.

Our cash flows from operations and access to capital are subject to a number of variables, including:

• our estimated proved oil and natural gas reserves;

• the amount of oil and natural gas we produce from existing wells;

• the prices at which we sell our production;

• the costs of developing and producing our oil and natural gas reserves;

• our ability to acquire, locate and produce new reserves;

• the ability and willingness of banks to lend to us; and

• our ability to access the equity and debt capital markets.

In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financial

market disruptions, general economic recessions, oil and natural gas industry recessions, large company
bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and
disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and
the public to more closely review the financial statements, capital structures and earnings of public
companies, including energy companies. Such events have constrained the capital available to the energy
industry in the past, and such events or similar events could adversely affect our access to funding for our
operations in the future.

If our revenues decrease as a result of lower oil and gas prices, operating difficulties, declines in
reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our
operations at current levels, further develop and exploit our current properties or invest in additional
exploration opportunities. Alternatively, a significant improvement in oil and gas prices could result in an
increase in our capital expenditures and we may be required to alter or increase our capitalization
substantially through the issuance of debt or equity securities, the sale of production payments, the sale of
non-strategic assets, the borrowing of funds or otherwise to meet any increase in capital needs. If we are
unable to raise additional capital from available sources at acceptable terms, our business, financial
condition and future results of operations could be adversely affected.

Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not
Be Adequately Insured.

There are numerous operational hazards inherent in oil and natural gas exploration, development,

production and gathering, including:

• unusual or unexpected geologic formations;

• natural disasters;

• adverse weather conditions;

• unanticipated pressures;

• loss of drilling fluid circulation;

• blowouts where oil or natural gas flows uncontrolled at a wellhead;

• cratering or collapse of the formation;

• pipe or cement leaks, failures or casing collapses;

• fires or explosions;

• releases of hazardous substances or other waste materials that cause environmental damage;

• pressures or irregularities in formations; and

• equipment failures or accidents.

In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the

performance of our operations, some of which may be material, due to our handling of petroleum

hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our
wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices.
Any of these or other similar occurrences could result in the disruption or impairment of our operations,
substantial repair costs, personal injury or loss of human life, significant damage to property, environmental
pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other
facilities near populated areas, including residential areas, commercial business centers and industrial sites,
could significantly increase the level of damages resulting from these risks.

Insurance against all operational risks is not available to us. We are not fully insured against all risks,

including development and completion risks that are generally not recoverable from third parties or
insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we
may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to
the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in
amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at
commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due
to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a
result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior
to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all
potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities
from uninsured and underinsured events and delays in the payment of insurance proceeds could have a
material adverse effect on our business, financial condition, results of operations and cash flows.

The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration
Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely
Affect Our Future Cash Flows and Results of Operations.

We intend to employ visualization and 2-D and 3-D seismic images to assist us in exploration and

development activities where applicable. These techniques only assist geoscientists in identifying
subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if
hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells
based on these technologies. Poor results from our exploration activities could limit our ability to replace
and grow reserves and materially and adversely affect our future cash flows and results of operations.

We Currently Own Only a Limited Amount of Seismic and Other Geological Data and May Have Difficulty
Obtaining Additional Data at a Reasonable Cost, Which Could Adversely Affect Our Future Cash Flows
and Results of Operations.

We currently own only a limited amount of seismic and other geological data to assist us in exploration

and development activities. We intend to obtain access to additional data in our areas of interest through
licensing arrangements with companies that own or have access to that data or by paying to obtain that data
directly. Seismic and geological data can be expensive to license or obtain. We may not be able to license or
obtain such data at an acceptable cost.

The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and
Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability
to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which
Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.

Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnel

could delay or adversely affect our operations. When drilling activity in the United States increases,

associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies
and personnel and the services and products of other vendors to the industry. These costs may increase, and
necessary equipment and services may become unavailable to us at economical prices. Should this increase
in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves,
or we may incur these higher costs, which may negatively affect our financial condition, results of
operations and cash flows.

In addition, the demand for hydraulic fracturing services currently exceeds the availability of fracturing

equipment and crews across the industry and in our operating areas in particular. The accelerated wear and
tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields
characterized by longer lateral lengths and larger numbers of fracturing stages has further amplified this
equipment and crew shortage. If demand for fracturing services continues to increase or the supply of
fracturing equipment and crews decreases, then higher costs could result and could adversely affect our
business and results of operations.

Our Identified Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to
Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.

Our management team has identified and scheduled drilling locations in our operating areas over a
multi-year period. Our ability to drill and develop these locations depends on a number of factors, including
the availability of equipment and capital, approval by regulators, seasonal conditions, oil and natural gas
prices, assessment of risks, costs and drilling results. The final determination on whether to drill any of
these locations will be dependent upon the factors described elsewhere in this report as well as, to some
degree, the results of our drilling activities with respect to our established drilling locations. Because of
these uncertainties, we do not know if the drilling locations we have identified will be drilled within our
expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any
other potential drilling locations. Our actual drilling activities may be materially different from our current
expectations, which could adversely affect our financial condition, results of operations and cash flows.

We Have Limited Control Over Activities on Properties We Do Not Operate.

We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our
sale of certain assets to a subsidiary of Chesapeake Energy Corporation in 2008, we do not operate one of our
most significant natural gas assets in the Haynesville shale. We have also acquired other non-operated acreage
positions in northwest Louisiana. Because we are not the operator for these properties, our ability to exercise
influence over the operations of these properties or their associated costs is limited. Our dependence on the
operators and other working interest owners of these projects and our limited ability to influence operations
and associated costs or control the risks could materially and adversely affect the realization of our targeted
returns on capital in drilling or acquisition activities. The success and timing of our drilling and development
activities on properties operated by others therefore depends upon a number of factors, including:

• timing and amount of capital expenditures;

• the operator’s expertise and financial resources;

• the rate of production of reserves, if any;

• approval of other participants in drilling wells; and

• selection of technology.

In areas where we do not have the right to propose the drilling of wells, we may have limited influence on

when, how and at what pace our properties in those areas are developed. Further, the operators of those properties
may experience financial problems in the future or may sell their rights to another operator not of our choosing,
both of which could limit our ability to develop and monetize the underlying natural gas reserves. In addition, the
operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these
properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no
production and associated revenues from these properties until the operator elects to return them to production.

A Component of Our Growth May Come Through Acquisitions, and Our Failure to Identify or Complete
Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we
consider economically acceptable. There is intense competition for acquisition opportunities in our industry.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.
The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to
obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through
acquisitions will require us to continue to invest in operations, financial and management information
systems and to attract, retain, motivate and effectively manage our employees. The inability to manage the
integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current
operations, and could negatively impact our results of operations and growth potential. Our financial
position, results of operations and cash flows may fluctuate significantly from period to period as a result of
the completion of significant acquisitions during particular periods. If we are not successful in identifying or
acquiring any material property interests, our earnings could be reduced and our growth could be restricted.

We may engage in bidding and negotiating to complete successful acquisitions. We may be required to

alter or increase substantially our capitalization to finance these acquisitions through the use of cash on
hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic
assets, the borrowing of funds or otherwise. Our credit agreement includes covenants limiting our ability to
incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our
common stock, our shareholders would suffer dilution of their interests. Furthermore, our decision to
acquire properties that are substantially different in operating or geologic characteristics or geographic
locations from areas with which our staff is familiar may impact our productivity in such areas.

We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About
or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could
Adversely Affect Our Results of Operations.

Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas

prices, operating costs, potential environmental liabilities and other factors relating to the properties.
However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain.
As a result, we may not discover all existing or potential problems associated with the properties we buy.
We may not become sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. We do not generally perform inspections on every well or property, and we may not be able to
observe mechanical and environmental problems even when we conduct an inspection. The seller may not
be willing or financially able to give us contractual protection against any identified problems, and we may
decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire
properties with risks or liabilities we did not know about or that we did not assess correctly, our financial
condition, results of operations and cash flows could be adversely affected as we settle claims and incur
cleanup costs related to these liabilities.

Strategic Relationships Upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability
to Conduct Our Operations.

Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil and
natural gas interests and acreage depends on our developing and maintaining close working relationships with
industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly
competitive environment. These realities are subject to change and may impair our ability to grow.

To develop our business, we will endeavor to use the business relationships of our management, board

and special board advisors to enter into strategic relationships, which may take the form of contractual
arrangements with other oil and natural gas companies, including those that supply equipment and other
resources that we expect to use in our business. We may not be able to establish these strategic
relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our
relationships with strategic partners may require us to incur expenses or undertake activities we would not
otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our
relationships. If our strategic relationships are not established or maintained, our business prospects may be
limited, which could diminish our ability to conduct our operations.

The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering and
Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil
and Natural Gas Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.

The unavailability of satisfactory oil and natural gas transportation arrangements may hinder our
access to oil and natural gas markets or delay production from our wells. The availability of a ready market
for our oil and natural gas production depends on a number of factors, including the demand for, and supply
of, oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market
our production depends in substantial part on the availability and capacity of gathering systems, pipelines
and processing facilities owned and operated by third parties. Our failure to obtain these services on
acceptable terms could materially harm our business. We may be required to shut in wells for lack of a
market or because of inadequacy or unavailability of pipeline or gathering system capacity. If that were to
occur, we would be unable to realize revenue from those wells until production arrangements were made to
deliver our production to market. Furthermore, if we were required to shut in wells we might also be
obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.

The disruption of third party facilities due to maintenance and/or weather could negatively impact our

ability to market and deliver our products. The third parties control when or if such facilities are restored
and what prices will be charged. We generally do not purchase firm transportation on third party facilities,
and, therefore, our production transportation can be interrupted by those having firm arrangements. Federal
and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in
supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic
conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial
Losses.

To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using

primarily “costless collars,” with respect to a portion of our future production. A costless collar provides us
with downside price protection through the purchase of a put option which is financed through the sale of a
call option. Because the call option proceeds are used to offset the cost of the put option, this arrangement is

initially “costless” to us. The goal of these and other hedges is to lock in a range of prices so as to mitigate
price volatility and increase the predictability of cash flows. These transactions limit our potential gains if
oil or natural gas prices rise above the maximum price established by the call option and may offer
protection if prices fall below the minimum price established by the put option only to the extent of the
volumes then hedged.

In addition, hedging transactions may expose us to the risk of financial loss in certain other

circumstances, including instances in which our production is less than expected or the counterparties to our
put and call option contracts fail to perform under the contracts.

Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which

could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes
in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately
predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.

Furthermore, there may be times when we have not hedged our production when, in retrospect, it

would have been advisable to do so. Decisions as to whether and what production volumes to hedge are
difficult and depend on market conditions and our forecast of future production and oil and gas prices, and
we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future
that differ from those that we have used in the past, and neither the continued application of our current
strategies nor our use of different hedging strategies may be successful.

An Increase in the Differential Between the NYMEX or Other Benchmark Prices of Oil and Natural Gas
and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial
Condition, Results of Operations and Cash Flows.

The prices that we receive for our oil and natural gas production sometimes reflect a discount to the

relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference
between the benchmark price and the prices we receive is called a differential. Increases in the differential
between the benchmark prices for oil and natural gas and the wellhead price we receive could adversely
affect our business, financial condition, results of operations and cash flows. We do not have, and may not
have in the future, any derivative contracts covering the amount of the basis differentials we experience in
respect of our production. As such, we will be exposed to any increase in such differentials.

We Are Subject to Government Regulation and Liability, including Complex Environmental Laws, Which
Could Require Significant Expenditures.

The exploration, development, production and sale of oil and natural gas in the United States are
subject to many federal, state and local laws, rules and regulations, including complex environmental laws
and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning
operations, the spacing of wells, unitization and pooling of properties, taxation or environmental matters
and health and safety criteria addressing worker protection. Under these laws and regulations, we may be
required to make large expenditures that could materially adversely affect our financial condition, results of
operations and cash flows. These expenditures could include payments for:

• personal injuries;

• property damage;

• containment and clean up of oil and other spills;

• the management and disposal of hazardous materials;

• remediation and clean-up costs; and

• other environmental damages.

We do not believe that full insurance coverage for all potential damages is available at a reasonable

cost. Failure to comply with these laws and regulations also may result in the suspension or termination of
our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the
imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the
environment have changed frequently and the changes often include increasingly stringent requirements.
These laws, rules and regulations may impose liability on us for environmental damage and disposal of
hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the
conduct of others or for acts that complied with applicable laws, rules or regulations at the time we
performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal
and state agencies. In addition, private parties, including the owners of properties upon which our wells are
drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue
legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations.

We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have
Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil
and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could
Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The federal, state and local governments in the areas in which we operate impose taxes on the oil and
natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling
and operating costs. In the past, there has been a significant amount of discussion by legislators and presidential
administrations concerning a variety of energy tax proposals. Many states have raised state taxes on energy
sources, and additional increases may occur. Changes to tax laws that are applicable to us could adversely affect
our business and our financial results.

Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences
currently available to oil and natural gas exploration and production companies. Such changes include, but
are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties,
(ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination
of the deduction for certain United States production activities and (iv) the increase in the amortization
period for geological and geophysical costs paid or incurred in connection with the exploration for, or
development of, oil or natural gas within the United States. These changes were included in the White
House budget proposals, released on February 26, 2009, February 1, 2010, February 14, 2011 and
February 13, 2012, and may be raised again in the future. The passage of any legislation as a result of the
budget proposals or any other similar change in U.S. federal income tax law could affect certain tax
deductions that are currently available with respect to oil and natural gas exploration and production
activities and could negatively impact our financial condition, results of operations and cash flows.

We May Be Required to Write Down the Carrying Value of Our Proved Properties Under Accounting Rules
and these Write-Downs Could Adversely Affect Our Financial Condition.

There is a risk that we will be required to write down the carrying value of our oil and natural gas
properties when oil or natural gas prices are low. In addition, non-cash write-downs may occur if we have:

• downward adjustments to our estimated proved reserves;

• increases in our estimates of development costs; or

• deterioration in our exploration results.

We periodically review the carrying value of our oil and natural gas properties under full-cost
accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related
deferred income taxes may not exceed a cost center ceiling that is based on the present value, based on
constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash
flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas
properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of
this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if
prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities,
but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity and
could lower the value of our common stock.

We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.

If an examination of the title history of a property that we have purchased reveals an oil and natural gas

lease has been purchased in error from a person who is not the owner of the mineral interest desired, our
interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well
as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be
lost.

It is our practice, in acquiring oil and natural gas leases, or undivided interests in oil and natural gas

leases, not to undergo the expense of retaining lawyers to examine the title to the mineral interest to be
placed under lease or already placed under lease. Rather, we will rely upon the judgment of oil and natural
gas lease brokers and/or landmen who perform the field work in examining records in the appropriate
governmental office before attempting to acquire a lease on a specific mineral interest.

Prior to the drilling of an oil and natural gas well, however, it is the normal practice in the oil and
natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title
review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there
are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative
work must be done to correct deficiencies in the marketability of the title, and such curative work entails
expense. Our failure to cure any title defects may adversely impact our ability in the future to increase
production and reserves. In the future, we may suffer a monetary loss from title defects or title failure.
Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If
there are any title defects or defects in assignment of leasehold rights in properties in which we hold an
interest, we will suffer a financial loss which could adversely affect our financial condition, results of
operations and cash flows.

The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge
Risks Associated with Our Business.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer
Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S.
financial system. The Dodd-Frank Act, among other things, sets forth the new framework for regulating
certain derivative products including the commodity hedges of the type used by us, but many aspects of this
law are subject to further rulemaking and will take effect over several years. As a result, it is difficult to

anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into
and maintaining such commodity hedges and the terms thereof. Based upon the limited assessments we are
able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could
have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In
particular, the Dodd-Frank Act could result in the implementation of position limits and additional
regulatory requirements on our derivative arrangements, which could include new margin, reporting and
clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and
may increase the cost of our derivative arrangements in the future.

If these types of commodity hedges become unavailable or uneconomic, our commodity price risk
could increase, which would increase the volatility of revenues and may decrease the amount of credit
available to us. Any limitations or changes in our use of derivative arrangements could also materially affect
our future ability to conduct acquisitions.

Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in
Increased Costs and Additional Operating Restrictions or Delays.

In past sessions, Congress has considered, but did not pass, legislation to amend the SDWA to remove

the exemption from restrictions on underground injection of fluids near drinking water sources granted to
most hydraulic fracturing operations and to require reporting and disclosure of chemicals used by oil and
natural gas companies in the hydraulic fracturing process. Hydraulic fracturing involves the injection of
water, sand or other propping agents and chemicals under pressure into rock formations to stimulate oil and
natural gas production. We routinely use hydraulic fracturing to produce commercial quantities of oil,
liquids and natural gas from shale formations such as the Eagle Ford and the Haynesville shales, where we
focus our operations. Sponsors of bills before the Senate and House of Representatives have asserted that
chemicals used in the fracturing process could adversely affect drinking water supplies. Such 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, and in all
likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic
fracturing operations and increasing our costs of compliance. Moreover, the EPA is conducting a
comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on
drinking water and groundwater. In addition, in December 2011, the EPA published an unrelated draft
report concluding that hydraulic fracturing caused groundwater pollution of a natural gas field in Wyoming,
although this study remains subject to review and public comments. Consequently, even if federal
legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could
spur further action at a later date towards federal legislation and regulation of hydraulic fracturing or similar
production operations.

In addition, a number of states are considering or have implemented more stringent regulatory

requirements applicable to fracturing, which could include a moratorium on drilling and effectively prohibit
further production of natural gas through the use of hydraulic fracturing or similar operations. For example,
Texas has adopted legislation that requires the disclosure of information regarding the substances used in
the hydraulic fracturing process to the Railroad Commission of Texas and the public. This legislation and
any implementing regulation could increase our costs of compliance and doing business.

The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the

hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale
formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal

legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional
permitting requirements, and also to attendant permitting delays and potential increases in cost, which could
adversely affect our business and results of operations.

Legislation or Regulations Restricting Emissions of “Greenhouse Gases” Could Result in Increased
Operating Costs and Reduced Demand for the Natural Gas, Natural Gas Liquids and Oil We Produce
While the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur
Significant Costs in Preparing for or Responding to those Effects.

The EPA has published its final findings that emissions of carbon dioxide, methane and other “greenhouse
gases” present an endangerment to public health and welfare because emissions of such gases are, according to
the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings allow
the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing
provisions of the CAA. Accordingly, the EPA has adopted regulations that would require a reduction in
emissions of greenhouse gases from motor vehicles and permitting and presumably requiring a reduction in
greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a
final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission
sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA
released a final rule that expands its rule on reporting of greenhouse gas emissions to include owners and
operators of petroleum and natural gas systems. Monitoring of those newly covered emissions commenced on
January 1, 2011, with the first annual reports due to the EPA in 2012. The adoption and implementation of any
regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment
and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our
operations. There were attempts at comprehensive federal legislation establishing a cap and trade program, but
that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or
reduce emissions of greenhouse gases from a wide range of sources. Any such legislation could adversely affect
demand for the natural gas, oil and liquids that we produce.

A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by
It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and
Operating Expenses to Increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural

gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the
traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a
natural gas company. However, the distinction between FERC-regulated transmission services and federally
unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our
gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.
A change in the jurisdictional characterization by FERC or Congress or a change in policy by either of them
may result in increased regulation of our assets, which may cause our revenues to decline and operating
expenses to increase.

Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and
Orders, We Could Be Subject to Substantial Penalties and Fines.

Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for

current violations of up to $1.0 million per day for each violation and disgorgement of profits associated
with any violation. Our systems have not yet been regulated by FERC, as a natural gas company subject to
the provisions of the NGA. FERC has adopted regulations that may subject certain of our otherwise

non-FERC/NGA jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity
posting requirements. Additional laws, rules and regulations pertaining to those and other matters may be
considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and
regulations in the future could subject us to civil penalty liability.

Competition in the Oil and Natural Gas Industry Is Intense Making It More Difficult for Us to Acquire
Properties, Market Natural Gas and Secure Trained Personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on
our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive
environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also,
there is substantial competition for capital available for investment in the oil and natural gas industry. Many
of our competitors possess and employ financial, technical and personnel resources substantially greater
than ours. Those companies may be able to pay more for productive oil and natural gas properties and
exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects
than our financial or personnel resources permit. In addition, other companies may be able to offer better
compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract
and retain qualified personnel has increased in recent years due to competition and may increase
substantially in the future. We may not be able to compete successfully in the future in acquiring
prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality
personnel and raising additional capital, which could have a material adverse effect on our business.

Our Competitors May Use Superior Technology and Data Resources that We May Be Unable to Afford or
that Would Require a Costly Investment by Us in Order to Compete with Them More Effectively.

Our industry is subject to rapid and significant advancements in technology, including the introduction
of new products and services using new technologies and databases. As our competitors use or develop new
technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to
implement new technologies at a substantial cost. In addition, many of our competitors will have greater
financial, technical and personnel resources that allow them to enjoy technological advantages and may in
the future allow them to implement new technologies before we can. We cannot be certain that we will be
able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the
technologies that we will use or that we may implement in the future may become obsolete, and we may be
adversely affected.

Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases that Will Expire Over the Next
Several Years Unless Production Is Established on Units Containing the Acreage.

At December 31, 2011, we had leasehold interests in approximately 116,000 net acres across all of our
areas of interest that are not currently held by production and are subject to leases with primary or renewed
terms that expire prior to December 31, 2013. Unless we establish production in paying quantities on units
containing these leases during their terms or we renew such leases, these leases will expire. If our leases
expire, we will lose our right to develop the related properties. The cost to renew such leases may increase
significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In
addition, on certain portions of our acreage, third party leases may have been taken and could become
immediately effective if our leases expire. As such, our actual drilling activities may materially differ from
our current expectations, which could adversely affect our business, financial condition, results of
operations and cash flows.

We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect
on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute
Our Business Plan in a Timely Fashion.

Because of our small size, growth in accordance with our business plans, if achieved, will place a
significant strain on our financial, technical, operational and management resources. As we expand our
activities, including our planned increase in oil exploration, development and production, and increase the
number of projects we are evaluating or in which we participate, there will be additional demands on our
financial, technical and management resources. The failure to continue to upgrade our technical,
administrative, operating and financial control systems or the occurrence of unexpected expansion
difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum
engineers and landmen could have a material adverse effect on our business, financial condition, results of
operations and cash flows and our ability to execute our business plan in a timely fashion.

Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third Party Operators or
Other Third Parties Could Decrease Our Cash Flow from Operations and Adversely Affect the Exploration
and Development of Our Prospects and Assets.

We derive essentially all of our revenues from the sale of our oil and natural gas to unaffiliated third
party purchasers, independent marketing companies and mid-stream companies. Any delays in payments
from our purchasers caused by financial problems encountered by them will have an immediate negative
effect on our results of operations and cash flows.

Liquidity and cash flow problems encountered by our working interest co-owners or the third party
operators of our non-operated properties may prevent or delay the drilling of a well or the development of a
project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of
projects as they become due. In the case of a farmout party, we would have to find a new farmout party or
obtain alternative funding in order to complete the exploration and development of the prospects subject to a
farmout agreement. In the case of a working interest owner, we could be required to pay the working
interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital
necessary to fund either of these contingencies or that we would be able to find a new farmout party.

We May Incur Indebtedness Which Could Reduce Our Financial Flexibility, Increase Interest Expense and
Adversely Impact Our Operations and Our Unit Costs.

At March 30, 2012, we had available borrowings of approximately $108.7 million under our credit
agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually
by our lenders based primarily on the estimated value of our existing and future acquired oil and gas reserves.
Our credit agreement is secured by substantially all of our interests in our oil and gas properties and other assets
and contains covenants restricting our ability to incur additional indebtedness, which may limit our ability to
obtain additional financing. In addition, the borrowing base under our credit agreement is subject to periodic
redeterminations, and we could be forced to repay a portion of our borrowings due to redeterminations of our
borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments.

Borrowings under our credit agreement at March 30, 2012 bear interest at a variable rate of 1.75% plus
a Eurodollar-based rate per annum, which equated to approximately 2.0% per annum. In the future, we may
incur significant amounts of additional indebtedness, including under our credit agreement, in order to make
acquisitions or to develop our properties. Interest rates on such future indebtedness may be higher than
current levels, causing our financing costs to increase accordingly.

Our level of indebtedness could affect our operations in several ways, including the following:

• a significant portion of our cash flows could be used to service our indebtedness;

• a high level of debt would increase our vulnerability to general adverse economic and industry

conditions;

• any covenants contained in the agreements governing our outstanding indebtedness could limit our
ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

• a high level of debt may place us at a competitive disadvantage compared to our competitors that

are less leveraged and, therefore, may be able to take advantage of opportunities that our
indebtedness may prevent us from pursuing;

• our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the

economy and in our industry; and

• a high level of debt may impair our ability to obtain additional financing in the future for working

capital, capital expenditures, acquisitions and general corporate or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to
meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General
economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and
our future performance. We may not be able to generate sufficient cash flows to pay the principal or interest on
our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance
such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing
of our debt include financial market conditions, the value of our assets and our performance at the time we need
capital. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or
arrange new financing, we may have to sell significant assets or have a portion of our assets foreclosed upon
which could have a material adverse effect on our business and financial results.

Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our
Chairman of the Board, Chief Executive Officer and President, the Members of Our Board of Directors and
Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor
Could Disrupt Our Business Operations.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our

management and the success of our technical team in identifying, evaluating and developing prospects and
reserves. Our performance and success are dependent to a large extent on the efforts and continued
employment of our management and technical personnel, including our Chairman, President and Chief
Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel
of equal experience and capabilities, and their successors may not be as effective. We have entered into
employment agreements with Mr. Foran and other key personnel. However, these employment agreements
do not ensure that these individuals will remain in our employment. If Mr. Foran or any of these other key
personnel resign or become unable to continue in their present roles and if they are not adequately replaced,
our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain,
nor do we plan to obtain, any insurance against the loss of any of these individuals.

We have an active board of directors that meets several times throughout the year and is intimately

involved in our business and the determination of our operational strategies. Members of our board of
directors work closely with management to identify potential prospects, acquisitions and areas for further
development. Many of our directors have been involved with us since our inception and have a deep

understanding of our operations and culture. If any of our directors resign or become unable to continue in
their present role, it may be difficult to find replacements with the same knowledge and experience and as a
result, our operations may be adversely affected.

In addition, our board consults regularly with our special advisors regarding our business and the

evaluation, exploration, engineering and development of our prospects. Due to the knowledge and
experience of our special advisors, they play a key role in our multi-disciplined approach to making
decisions regarding prospects, acquisitions and development. If any of our special advisors resign or
become unable to continue in their present role, our operations may be adversely affected.

Our Management Team Owns Approximately 13% of Our Common Stock Which Could Give Them
Influence in Corporate Transactions and Other Matters, and the Interests of Our Management Could Differ
from Other Shareholders.

Our directors and officers beneficially own approximately 13% of our outstanding shares of common

stock. These shareholders are positioned to influence or control to some degree the outcome of matters
requiring a shareholder vote, including the election of directors, the adoption of any amendment to our
certificate of formation or bylaws and the approval of mergers and other significant corporate transactions.
Their influence or control of the company may have the effect of delaying or preventing a change of control
of the company and may adversely affect the voting and other rights of other shareholders. In addition, due
to their ownership interest in our common stock, they may be able to remain entrenched in their positions.

Risks Relating to Our Common Stock

Our Common Stock Has Only Been Publicly Traded Since February 2, 2012, and the Price of our Common
Stock Has Fluctuated Substantially Since Then and May Fluctuate Substantially in the Future.

Our common stock has been publicly traded only since February 2, 2012. The market price of our
common stock could vary significantly as a result of a number of factors. In addition, the trading volume of
our common stock may fluctuate and cause significant price variations to occur. In the event of a drop in the
market price of our common stock, you could lose a substantial part or all of your investment in our
common stock. In addition, the stock markets in general have experienced extreme volatility that has often
been unrelated to the operating performance of particular companies. These broad market fluctuations may
adversely affect the trading price of our common stock.

Factors that could affect our stock price or result in fluctuations in the market price or trading volume

of our common stock include:

• our actual or anticipated operating and financial performance and drilling locations, including

reserves estimates;

• quarterly variations in the rate of growth of our financial indicators, such as net income per share,

net income and cash flows, or those of companies that are perceived to be similar to us;

• changes in revenue, cash flows or earnings estimates or publication of reports by equity research

analysts;

• speculation in the press or investment community;

• public reaction to our press releases, announcements and filings with the Securities and Exchange

Commission, or SEC;

• sales of our common stock by us or shareholders, or the perception that such sales may occur;

• general financial market conditions and oil and gas industry market conditions, including

fluctuations in commodity prices;

• the realization of any of the risk factors presented in this report;

• the recruitment or departure of key personnel;

• commencement of or involvement in litigation;

• the prices of oil and natural gas;

• the success of our exploration and development operations, and the marketing of any oil and

natural gas we produce;

• changes in market valuations of companies similar to ours; and

• domestic and international economic, legal and regulatory factors unrelated to our performance.

The Requirements of Being a Public Company, Including Compliance with the Reporting Requirements of
the Securities Exchange Act of 1934, as Amended, and the Requirements of the Sarbanes-Oxley Act of
2002, May Strain Our Resources, Increase Our Costs and Distract Management; and It May Be Difficult to
Comply with These Requirements in a Timely or Cost-Effective Manner.

As a new public company with listed equity securities, we are required to comply with laws,

regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002,
related regulations of the SEC and the requirements of the New York Stock Exchange, or the NYSE, with
which we were not required to comply as a private company. Complying with these statutes, regulations and
requirements will occupy a significant amount of time of our board of directors and management and will
significantly increase our costs and expenses. We will need to:

• institute a more comprehensive compliance function;

• establish and maintain a system of internal controls over financial reporting in compliance with the
requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the
SEC;

• comply with rules promulgated by the NYSE;

• prepare and distribute periodic public reports in compliance with our obligations under the federal

securities laws;

• establish new internal policies, such as those relating to disclosure controls and procedures and

insider trading; and

• involve and retain to a greater degree outside counsel and accountants in the above activities.

In addition, as a result of being subject to these rules and regulations, we may have to accept less

director and officer liability insurance coverage than we desire or to incur substantial costs to obtain
acceptable coverage. These factors could also make it more difficult for us to attract and retain qualified
members of our board of directors, particularly to serve on our Audit Committee, and qualified executive
officers.

If Any of the Material Weaknesses Previously Identified by Our Independent Registered Public Accountants
Persist or if We Fail to Establish and Maintain Effective Internal Control over Financial Reporting in the
Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected.

Until February 1, 2012, we were a private company and maintained internal controls and procedures in
accordance with being a private company. We have maintained limited accounting personnel to perform our

accounting processes and limited supervisory resources with which to address our internal control over financial
reporting. In connection with our audits for the years ended December 31, 2011 and 2010, our independent
registered public accountants identified and communicated material weaknesses. In 2010, the material
weaknesses related to controls over accounting and reporting for deferred income taxes, impairment of oil and
natural gas properties, assessment of unproved and unevaluated properties and the administration of our stock
and incentive plan. In 2011, the material weakness related only to accounting and reporting for stock
compensation expense.

A material weakness is a control deficiency, or a combination of control deficiencies, in internal
control over financial reporting, such that there is a reasonable possibility that a material misstatement of
our annual and interim financial statements will not be prevented or detected and corrected on a timely
basis. We have begun the process of evaluating our internal control over financial reporting and expect to
put into place new accounting processes and control procedures to address the weaknesses described above,
including the hiring of outside consultants to review significant or complex accounting issues and
calculations, the implementation of a more formalized closing process, the formation of a disclosure
committee and the hiring of additional personnel.

As a public company, we are required to comply with the SEC’s rules implementing

Sections 302 and 404 of the Sarbanes-Oxley Act, which require our management to certify financial and
other information in our quarterly and annual reports and to provide an annual management report on the
effectiveness of our internal control over financial reporting. We will be required to make our first
assessment of our internal control over financial reporting for the year ended December 31, 2012. To
comply with the requirements of being a public company, we are upgrading our systems, including
information technology, implementing additional financial and management controls, reporting systems and
procedures and have hired additional accounting and financial reporting staff.

Further, our independent registered public accountants are not yet required to formally attest to the

effectiveness of our internal control over financial reporting. Once they are required to do so, our
independent registered public accountants may issue a report that is adverse in the event they are not
satisfied with the level at which our controls are documented, designed, operated or reviewed. Our
remediation efforts may not enable us to remedy or avoid material weaknesses in the future.

Our efforts to develop and maintain our internal controls may not be successful, and we may be unable

to maintain effective controls over our financial processes and reporting in the future and comply with the
certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, our
remediation efforts may not enable us to remedy or avoid material weaknesses in the future. Any failure to
remediate deficiencies and to develop or maintain effective controls, or any difficulties encountered in our
implementation or improvement of our internal control over financial reporting, could result in material
misstatements that are not prevented or detected and corrected on a timely basis, which could potentially
subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective
internal controls could also cause investors to lose confidence in our reported financial information and
adversely affect our business and our stock price.

We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common
Stock.

We do not presently intend to pay any cash dividends on our common stock. Any payment of future

dividends will be at the discretion of the board of directors and will depend on, among other things, our
earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual
restrictions applying to the payment of dividends and other considerations that our board of directors deems

relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we
experience substantial losses, such funds may not be available. In addition, certain covenants in our credit
agreement may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly,
you may have to sell some or all of your common stock in order to generate cash flow from your investment
and there is no guarantee that the price of our common stock that will prevail in the market will exceed the
price paid by you.

The Trading Volume in Our Common Stock Has Been Low, and the Sale of a Substantial Number of Shares
in the Public Market Could Depress the Price of Our Common Stock.

Our common stock is listed on the NYSE, but since the completion of our initial public offering, it has
had a relatively low average daily trading volume relative to many other stocks. Thinly traded stock can be
more volatile than stock trading in an active public market, which can lead to significant price swings even
when a relatively small number of shares are being traded and can limit an investor’s ability to quickly sell
blocks of stock. Shareholders holding more than 75% of our outstanding shares of common stock are
subject to lockup agreements that prohibit the disposition of those shares until at least July 30, 2012, subject
to certain exceptions. We cannot predict what effect, if any, the expiration of these lockups will have on
future sales of our common stock in the market, including the availability of our common stock for sale in
the market and the market price of our common stock.

Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our
Common Stock by Us Could Depress the Price of Our Common Stock.

The market price of our common stock could decline as a result of sales of a large number of shares of

our common stock in the market, and the perception that these sales could occur may also depress the
market price of our common stock. If our existing shareholders sell, or indicate an intent to sell, substantial
amounts of our common stock in the public market after any contractual lockup and other legal restrictions
on resale lapse, the trading price of our common stock could decline significantly. Sales of our common
stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we
deem appropriate. These sales also could cause our stock price to fall and make it more difficult for you to
sell shares of our common stock.

We may also sell additional shares of common stock or securities convertible into common stock in
subsequent offerings. We cannot predict the size of future issuances of our common stock or convertible
securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible
securities will have on the market price of our common stock.

Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects that
Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders.

Our certificate of formation and bylaws contain certain provisions that may discourage, delay or
prevent a merger or acquisition that our shareholders may consider favorable. These provisions include:

• authorization for our board of directors to issue preferred stock without shareholder approval;

• a classified board of directors so that not all members of our board of directors are elected at one

time;

• the prohibition of cumulative voting in the election of directors; and

• a limitation on the ability of shareholders to call special meetings to those owning at least 25% of

our outstanding shares of common stock.

Provisions of Texas law also may discourage, delay or prevent someone from acquiring or merging
with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder
who beneficially owns more than 20% of our voting stock, or any “affiliated shareholder,” cannot acquire
us for a period of three years from the date this person became an affiliated shareholder, unless various
conditions are met, such as approval of the transaction by our board of directors before this person became
an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares
not beneficially owned by the affiliated shareholder.

Our Board of Directors Can Authorize the Issuance of Preferred Stock, which Could Diminish the Rights of
Holders of Our Common Stock, and Make a Change of Control of the Company More Difficult Even if It
Might Benefit Our Shareholders.

Our board of directors is authorized to issue shares of preferred stock in one or more series and to fix

the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may
issue shares of preferred stock with a preference over our common stock with respect to dividends or
distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights
of the holders of common stock. Issuances of preferred stock, depending upon the rights, preferences and
designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of
control of the company, even if that change of control might benefit our shareholders.

Item 1B. Unresolved Staff Comments.

Not applicable.

Item 2.

Properties.

See “Business” for descriptions of our properties. We also have various operating leases for rental of

office space, office and field equipment, and vehicles. See Note 12, Commitments and Contingencies, to the
consolidated financial statements for the future minimum rental payments. Such information is incorporated
herein by reference.

Item 3.

Legal Proceedings.

Although we may, from time to time, be involved in litigation and claims arising out of our operations
in the normal course of business, we are not currently a party to any material legal proceeding. In addition,
we are not aware of any material legal or governmental proceedings against us, or contemplated to be
brought against us.

Item 4.

Mine Safety Disclosures

Not applicable.

PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities.

General Market Information

On February 2, 2012, our common stock began trading on the NYSE under the symbol “MTDR.” On

February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock at $12.00
per share. We sold 12,209,167 shares of common stock in this offering, and certain selling shareholders sold
2,674,167 shares of common stock, including shares sold by us and the selling shareholders pursuant to the
partial exercise of the underwriters’ over-allotment on March 7, 2012. Prior to trading on the NYSE, there
was no established public trading market for our common stock.

On March 30, 2012, we had 55,272,860 shares of common stock outstanding held by approximately

516 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name.

The following table sets forth the high and low sales prices of our common stock as reported by the

NYSE for the period indicated:

Period from February 2, 2012 to March 30, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$12.33

$10.85

High

Low

On March 30, 2012, the last reported sales price of our common stock on the NYSE was $10.95 per

share.

Dividend Policy

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the
foreseeable future. We currently intend to retain future earnings to finance the expansion of our business.
Our future dividend policy is within the discretion of our board of directors and will depend upon various
factors, including our results of operations, financial condition, capital requirements and investment
opportunities. In addition, certain covenants in our credit agreement may limit our ability to pay dividends
on our common stock.

Prior to consummation of our initial public offering, the holders of our Class B common stock were

entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally
available for the payment of dividends. These dividends accrued and were payable quarterly at the rate of
$0.06-2/3 per share of Class B common stock outstanding. For the years ended December 31, 2011, 2010
and 2009, we declared dividends on our outstanding shares of Class B common stock totaling $274,853 in
each year. Upon the automatic conversion of the outstanding shares of Class B common stock at the closing
of our initial public offering, the right of the holders of Class B common stock to dividends was terminated
and such holders were paid approximately $28,000 during the first quarter of 2012 for all accrued but
unpaid dividends existing at the time of such conversion.

Equity Compensation Plan Information

The following table presents the securities authorized for issuance under our equity compensation

plans as of December 31, 2011.

Equity Compensation Plan Information

Plan Category

Number of
Shares to be
Issued Upon
Exercise of
Outstanding
Options,
Warrants
and
Rights

Weighted-
Average
Exercise
Price of
Outstanding
Options,
Warrants
and Rights
($)

Equity compensation plans approved by security holders(1)
Equity compensation plans not approved by security holders(2)

. . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . .

1,024,500
–

Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1,024,500

$9.75
–

$9.75

Number of
Shares
Remaining
Available for
Future
Issuance
Under Equity
Compensation
Plans

–
4,000,000

4,000,000

(1) Our board of directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock

and Incentive Plan.

(2) Our 2012 Long-Term Incentive Plan was approved by our board of directors in December 2011 and took effect on January 1, 2012. For a
description of our 2012 Long-Term Incentive Plan, see Note 17 to our consolidated financial statements included elsewhere in this Form
10-K.

Recent Sales of Unregistered Securities

From October 2010 through January 2011, we sold 1,922,199 shares of our common stock to
accredited investors for the aggregate consideration of $21,144,189. These shares were issued in a
transaction exempt from the registration requirements of the Securities Act under Section 4(2) of the
Securities Act and Rule 506.

During 2011, we issued an aggregate of 93,001 shares of common stock pursuant to the exercise of

stock options held by certain directors and employees and received an aggregate of $837,009 for such
exercises. The issuance of these shares was exempt from the registration requirements of the Securities Act
pursuant to Rule 701.

During 2011, we issued an aggregate of 17,500 shares of our common stock to our outside directors

and advisors in connection with their service to the board. These shares were issued in transactions exempt
from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

In October 2011, we issued an aggregate of 2,575 shares of our common stock to General Mills, Inc.

Benefits Finance Committee on behalf of General Mills Group Trust and Voluntary Employees Beneficiary
Assoc. Trust General Mills & Bakery, Confectionary, Tobacco & Grain Millers in connection with prior
service on the board by officers of General Mills, Inc. Benefits Finance Committee. These shares were
issued in transactions exempt from the registration requirements of the Securities Act under Section 4(2) of
the Securities Act.

Use of Proceeds

Our initial public offering of common stock was effected through a Registration Statement on Form S-1
(File No. 333-176263), which was declared effective by the SEC on February 1, 2012. RBC Capital Markets,
LLC; Citigroup Global Markets Inc.; Jefferies & Company, Inc.; Howard Weil Incorporated; Stifel,
Nicolaus & Company, Incorporated; Stephens Inc.; and Comerica Securities, Inc. acted as underwriters for the
offering. RBC Capital Markets, LLC and Citigroup Global Markets Inc. acted as the co-managers for the
offering. Under the Form S-1, we registered the offer and sale of an aggregate of 15,333,334 shares of our
common stock, 12,209,167 shares of which were issued and sold by us and 2,674,167 shares of which were
sold by the selling shareholders named in the Form S-1, including shares sold by us and certain of the selling
shareholders pursuant to the partial exercise of the underwriters’ option to purchase additional shares. The
initial public offering closed on February 7, 2012 and the over-allotment option closed on March 7, 2012. We
issued and sold all but 450,000 of the shares that were registered.

The shares were sold at a price to the public of $12.00 per share and we received cash proceeds of
approximately $133.6 million from this transaction, net of underwriting discounts and commissions. We did
not receive any proceeds from the sale of shares by the selling shareholders. The underwriters received
underwriting discounts and commissions totaling approximately $9.9 million, and we incurred additional costs
of approximately $3.0 million in connection with the offering, which amounted to total fees and costs of
approximately $12.9 million. No offering costs were paid directly or indirectly to any of our directors or
officers (or their associates) or persons owning 10% or more of any class of our equity securities or to any
other affiliates, other than advancement of legal fees for one counsel to represent the selling shareholders.

We used $123.0 million to repay the then outstanding borrowings under our credit agreement. We used

the remaining proceeds to fund a portion of our 2012 capital expenditure requirements.

Item 6.

Selected Financial Data.

You should read the following selected financial data in conjunction with “Management’s Discussion and

Analysis of Financial Condition and Results of Operations” and our historical consolidated financial
statements and related notes thereto included elsewhere in this report. The financial information included in
this report may not be indicative of our future results of operations, financial position or cash flows.

The following selected financial information is summarized from our results of operations for the five-
year period ended December 31, 2011 and selected consolidated balance sheet data at December 31, 2011,
2010, 2009, 2008 and 2007 and should be read in conjunction with the consolidated financial statements at
the years ended December 31, 2011, 2010 and 2009 included herewith.

Year Ended December 31,

2011

2010

2009

2008

2007

(In thousands)
Statement of operations data:
Revenues:

Oil and natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 67,000
7,106
5,138

$34,042
5,299
3,139

$ 19,039
7,625
(2,375)

$ 30,645
(1,326)
3,592

$13,988
213
(211)

Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

79,244

42,480

24,289

32,911

13,990

Expenses:

Production taxes and marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Full-cost ceiling impairment
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

6,278
7,244
31,754
209
35,673
13,394

94,552

1,982
5,284
15,596
155
–
9,702

32,719

1,077
4,725
10,743
137
25,244
7,115

49,041

1,639
4,667
12,127
92
22,195
8,252

48,972

779
3,099
7,889
70
–
5,189

17,026

Operating (loss) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(15,308)

9,761

(24,752)

(16,061)

(3,036)

Other (expense) income:

Net (loss) gain on asset sales and inventory impairment . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(154)
(683)
315

(224)
(3)
364

(379)
–
781

136,977
–
2,984

–
–
2,736

Total other (expense) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net (loss) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(522)

137
$(10,309) $ 6,377

402

139,962
$(14,425) $103,878

2,736
$ (300)

Earnings (loss) per common share

Basic

Class A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Diluted

Class A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Class B dividend declared, per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(0.25) $

0.15

0.02

0.42

(0.25) $

0.15

0.02

0.27

0.42

0.27

(0.37) $

2.50

$ (0.05)

(0.10) $

2.77

0.22

(0.37) $

2.46

$ (0.05)

(0.10) $

2.73

0.27

0.22

0.27

(In thousands)
Balance sheet data:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Certificates of deposit
Short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net property and equipment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

At December 31,

2011

2010

2009

2008

2007

$ 10,284
1,335
–
399,865
439,469
74,576
93,377
$ 271,515

$ 21,060
2,349
–
303,880
346,382
30,097
34,408
$ 281,877

$104,230
15,675
–
142,078
277,400
8,868
4,210
$264,321

$ 150,768
20,782
–
125,261
314,539
35,475
2,059
$ 277,005

9,017
–
57,925
105,814
179,152
5,541
1,568
$ 172,043

Year Ended December 31,

2011

2010

2009

2008

2007

Other financial data:
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash (used in) provided by investing activities . . . . . . . . . . . . . . . . . . . . .
Oil and natural gas properties capital expenditures . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . .
Expenditures for other property and equipment
Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjusted EBITDA(1)

$ 61,868
(160,088)
(156,431)
(4,671)
87,444
$ 49,911

$ 27,273
(147,334)
(159,050)
(1,610)
36,891
$ 23,635

1,791
(49,415)
(54,244)
(307)
1,086
$ 15,184

$ 25,851
115,481
(104,119)
(3,012)
419
$ 18,411

7,881
(108,296)
(50,310)
(1,300)
66,250
8,090

(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to

our net income (loss) and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.

Non-GAAP Financial Measures

We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion,

depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized
derivative gains and losses, non-recurring income and expenses and non-cash stock-based compensation
expense, including stock option and grant expense and restricted stock grants. Adjusted EBITDA is not a
measure of net income or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental
non-GAAP financial measure that is used by management and external users of our consolidated financial
statements, such as industry analysts, investors, lenders and rating agencies.

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating
performance and compare the results of operations from period to period without regard to our financing
methods or capital structure. We exclude the items listed above from net income (loss) in calculating
Adjusted EBITDA because these amounts can vary substantially from company to company within our
industry depending upon accounting methods and book values of assets, capital structures and the method
by which certain assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or

cash flows from operating activities as determined in accordance with GAAP or as an indicator of our
operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant
components of understanding and assessing a company’s financial performance, such as a company’s cost
of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of
another company because all companies may not calculate Adjusted EBITDA in the same manner. The
following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA
to the GAAP financial measures of net income (loss) and net cash provided by operating activities,
respectively.

(In thousands)
Unaudited Adjusted EBITDA reconciliation to

Net Income (Loss):

Net (loss) income . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax (benefit) provision . . . . . . . . . . .
Depletion, depreciation and amortization . . . . . . . .
Accretion of asset retirement obligations . . . . . . . .
Full-cost ceiling impairment . . . . . . . . . . . . . . . . . .
Unrealized (gain) loss on derivatives . . . . . . . . . . .
Stock option and grant expense . . . . . . . . . . . . . . .
Restricted stock grants . . . . . . . . . . . . . . . . . . . . . .
Net loss (gain) on asset sales and inventory

impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Year Ended December 31,

2011

2010

2009

2008

2007

$(10,309)
683
(5,521)
31,754
209
35,673
(5,138)
2,362
44

$ 6,377
3
3,521
15,596
155
–
(3,139)
824
74

$(14,425)
–
(9,925)
10,743
137
25,244
2,375
622
34

$ 103,878
–
20,023
12,127
92
22,195
(3,592)
605
60

$ (300)
–
–
7,889
70
–
211
205
15

154

224

379

(136,977)

–

Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . .

$ 49,911

$23,635

$ 15,184

$ 18,411

$8,090

Year Ended December 31,

2011

2010

2009

2008

2007

(In thousands)
Unaudited Adjusted EBITDA reconciliation to
Net Cash Provided by Operating Activities:
Net cash provided by operating activities . . . . . . . . .
Net change in operating assets and liabilities . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current income tax (benefit) provision . . . . . . . . . . .

$ 61,868
(12,594)
683
(46)

$27,273
(2,230)
3
(1,411)

$ 1,791
15,717
–
(2,324)

$ 25,851
(17,888)
–
10,448

Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . .

$ 49,911

$23,635

$15,184

$ 18,411

$7,881
209
–
–

$8,090

Item 7.

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

The following discussion and analysis of our financial condition and results of operations should be
read in conjunction with our consolidated financial statements and related notes appearing elsewhere in
this report. The following discussion contains “forward-looking statements” that reflect our future plans,
estimates, beliefs and expected performance. We caution that assumptions, expectations, projections,
intentions or beliefs about future events may, and often do, vary from actual results and the differences can
be material. Some of the key factors which could cause actual results to vary from our expectations include
changes in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions,
uncertainties in estimating proved reserves and forecasting production results, operational factors affecting
the commencement or maintenance of producing wells, the condition of the capital markets generally, as
well as our ability to access them, the proximity to and capacity of transportation facilities, uncertainties
regarding environmental regulations or litigation and other legal or regulatory developments affecting our
business, as well as those factors discussed below and elsewhere in this report, all of which are difficult to
predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not
occur. See “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent energy company engaged in the exploration, development, production and

We were founded in July 2003 by Mr. Joseph Wm. Foran and Mr. Scott E. King, and we drilled our

first well in 2004. Since that time, we have drilled or participated in drilling 236 wells through
December 31, 2011, including 106 Haynesville and nine Eagle Ford wells. At December 31, 2011, based on
the reserves audit by our independent reservoir engineers, we had 193.2 Bcfe of estimated proved reserves
with a PV-10 of $248.7 million and a Standardized Measure of $215.5 million. At December 31, 2011, 34%
of our estimated proved reserves were proved developed reserves, 12% of our estimated proved reserves
were oil and 88% of our estimated proved reserves were natural gas. Our average daily production for the
year ended December 31, 2011 was 42.3 MMcfe per day, including 39.8 MMcf of natural gas per day and
422 Bbl of oil per day, as compared to an average daily production of 23.6 MMcfe per day, including 23.0
MMcf of natural gas per day and 91 Bbl of oil per day for the year ended December 31, 2010. We have
achieved this growth while lowering operating costs (consisting of lease operating expenses and production
taxes and marketing expenses) from $1.16 per Mcfe for the year ended December 31, 2009 to $0.88 per
Mcfe for the year ended December 31, 2011, or a decrease of approximately 24%.

Our business success and financial results are dependent on many factors beyond our control, such as

economic, political and regulatory developments, as well as competition from other sources of energy.
Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affected
by changes in market supply and demand, which is impacted by overall economic activity, weather, pipeline
capacity constraints, inventory storage levels, natural gas price differentials and other factors. Prices for oil

and natural gas will affect the cash flows available to us for capital expenditures and our ability to borrow
and raise additional capital. Declines in oil or natural gas prices would not only reduce our revenues, but
could also reduce the amount of oil and/or natural gas that we can produce economically, and as a result,
could have an adverse effect on our financial condition, results of operations, cash flows and reserves.

In response to the recent commodity price environment, and in particular, the general decline in natural
gas prices since July 2008 in contrast with the rebound in oil prices since February 2009, we have sought to
balance our exploration and development plans by targeting more oil prone reservoirs, such as the Eagle
Ford shale. While most of our historical and current production is natural gas, we believe that our future
production profile will reflect a more balanced oil and natural gas commodity mix as a result of our strategic
shift to target more oil development than we have historically.

In recent months, natural gas prices have declined to their lowest levels in many years, and at

March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at
$2.13 per MMBtu. We would not expect to drill any operated natural gas wells, except for natural gas wells
in specific exploratory prospects like the Meade Peak shale, until natural gas prices improved substantially
from these levels or unless the costs to drill and complete these wells were also to decline substantially from
their recent levels. See “Risk Factors – Our Identified Drilling Locations Are Scheduled Out Over Several
Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of
Their Drilling.”

During 2012, we intend to allocate 84% of our 2012 capital expenditure budget of $313.0 million to

the exploration, development and acquisition of additional interests in the Eagle Ford shale play. Including
these anticipated capital expenditures in the Eagle Ford shale, we plan to dedicate about 94% of our 2012
anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we
have budgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate
materially based on market conditions and our drilling results.

As we transition our operations from the Haynesville shale and Cotton Valley in northwest Louisiana
to the Eagle Ford shale in south Texas, we may face challenges associated with establishing operations and
securing the necessary services to drill and complete wells and with securing the necessary pipeline and
natural gas processing capabilities to transport, process and market the oil and natural gas that we produce.
We may also incur higher than anticipated costs associated with establishing new operating infrastructure
and facilities on our leases throughout the area. We believe we have successfully secured the necessary
drilling and completion services for our current Eagle Ford operations, and at March 30, 2012, we had two
contracted drilling rigs operating in south Texas: one in LaSalle County and one in Karnes County. We are
not currently experiencing difficulties in securing completion, and particularly hydraulic fracturing services,
for our newly drilled wells, although we experienced these problems at various times during 2011 in south
Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely
drilling and completion services and reducing drilling and completion costs will be essential to the
successful development and profitability of the Eagle Ford shale play. See “Risk Factors – The
Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel,
Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish
and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have
a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.”

capacity limitations at our Martin Ranch lease in LaSalle County and are currently flaring a portion of the
natural gas we are producing there as a result. We believe that these pipeline interruptions and capacity
constraints are temporary and that additional oil and natural gas pipeline infrastructure currently being built
throughout south Texas will help to alleviate these problems within 60 to 90 days. If we were required to
shut in our production for long periods of time due to these pipeline interruptions, it could have a material
adverse effect on our business, financial condition, results of operations and cash flows. See “Risk Factors –
The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering and Transportation
Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas
Transportation Agreements Would Have a Material Adverse Effect on Our Revenue.”

On February 2, 2012, our common stock began trading on the NYSE under the symbol “MTDR.” We

believe that our general and administrative expenses will increase as a result of us operating as a public
company. This increase will consist primarily of legal and accounting fees and additional expenses
associated with compliance with the Sarbanes-Oxley Act and other regulations and increases in our staff
compensation and other ongoing general and administrative expenses necessary to maintain and grow a
publicly traded exploration and production company. A large part of this increase will be due to the cost of
accounting and legal support services, filing annual and quarterly reports with the SEC, investor relations
activities, directors’ fees, incremental directors’ and officers’ liability insurance costs and transfer and
registrar agent fees. As a result, we believe that our general and administrative expenses for future periods
will increase significantly. Our consolidated financial statements for future periods will reflect the impact of
these increased expenses and affect the comparability of our financial statements with periods before the
completion of this offering.

Revenues

Our revenues are derived primarily from the sale of oil and natural gas production. Our revenues may
vary significantly from period to period as a result of changes in volumes of production sold or changes in
oil or natural gas prices.

Realized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigate our
exposure to fluctuations in oil and natural gas prices. This revenue item includes the net realized cash gains
and losses associated with the settlement of these derivative financial instruments for a given reporting period.

Unrealized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigate

our exposure to fluctuations in oil and natural gas prices. This revenue item recognizes the non-cash change
in the fair value of our open derivative contracts between reporting periods.

The following table summarizes our revenues and production data for the periods indicated:

Year Ended December 31,

2011

2010

2009

Operating Results:
Revenues (in thousands):

Oil
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total oil and natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$14,457
52,543

67,000
7,106
5,138

$ 2,507
31,535

34,042
5,299
3,139

$ 1,719
17,320

19,039
7,625
(2,375)

Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$79,244

$42,480

$24,289

Net Production Volumes:

Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (Bcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . .

Total natural gas equivalents (Bcfe) (1)
Average net daily production (MMcfe/d) (1)

154
14.5
15.4
42.3

33
8.4
8.6
23.6

30
4.8
5.0
13.7

Average Sales Prices:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil (per Bbl)
Natural gas, with realized derivatives (per Mcf) . . . . . . . . . . . . . . . . . . . . .
Natural gas, without realized derivatives (per Mcf) . . . . . . . . . . . . . . . . . .

$ 93.80
4.11
$
3.62
$

$ 76.39
4.38
$
3.75
$

$ 57.72
5.17
$
3.59
$

(1) Estimated using a conversion ratio of one Bbl per six Mcf.

Year Ended December 31, 2011 as Compared to Year Ended December 31, 2010

Oil and natural gas revenues. Our oil and natural gas revenues increased by $33.0 million to $67.0
million, or an increase of about 97%, for the year ended December 31, 2011 as compared to the year ended
December 31, 2010. This increase in oil and natural gas revenues corresponds with an increase of about 79%
in our oil and natural gas production to 15.4 Bcfe for the year ended December 31, 2011 from 8.6 Bcfe for the
year ended December 31, 2010. This increased production was almost entirely due to drilling operations in the
Eagle Ford and Haynesville shales. A portion of the increase in oil and natural gas revenues reflects the
approximate five-fold increase in our oil production for the year ended December 31, 2011 as compared to the
year ended December 31, 2010, as well as a higher average oil price of $93.80 per Bbl realized during 2011 as
compared to an average oil price of $76.39 per Bbl realized during 2010.

Realized gain (loss) on derivatives. Our realized gain on derivatives increased by approximately
$1.8 million to $7.1 million for the year ended December 31, 2011 from $5.3 million for the year ended
December 31, 2010. The realized gain from our open natural gas costless collar contracts increased primarily
as a result of the decline in natural gas prices during the comparable periods. We realized approximately $1.03
per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31,
2011 as compared to $0.89 per MMBtu hedged on all of our open natural gas costless collar contracts during
the year ended December 31, 2010. Our total natural gas volumes hedged for the year ended December 31,
2011 were also approximately 16% higher than the total natural gas volumes hedged for 2010.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $5.14
million for the year ended December 31, 2011 as compared to an unrealized gain of $3.14 million for the year
ended December 31, 2010. During the period from December 31, 2010 to December 31, 2011, the net fair
value of our open natural gas costless collar contracts increased from approximately $4.14 million to
approximately $9.28 million, resulting in an unrealized gain on derivatives of approximately $5.14 million for
the year ended December 31, 2011. This increase in the net fair value of our open natural gas costless collar
contracts was due primarily to a decrease in natural gas prices during 2011 as compared to 2010, as well as an
increase in the total number of our open contracts at December 31, 2011 as compared to December 31, 2010.

Year Ended December 31, 2010 as Compared to Year Ended December 31, 2009

Oil and natural gas revenues. Our oil and natural gas revenues increased by $15.0 million to

$34.0 million, or an increase of about 79%, for the year ended December 31, 2010 as compared to the year
ended December 31, 2009. Approximately $13.7 million of the increase was primarily due to a 72%
increase in our production to 8.6 Bcfe during the year ended December 31, 2010 from 5.0 Bcfe during the
year ended December 31, 2009, and approximately $1.3 million of the increase was due to increases in the
average prices we received for both oil and natural gas over these respective periods. For the year ended
December 31, 2010, we received an average natural gas price of $3.75 per Mcf and an average oil price of
$76.39 per Bbl as compared to an average natural gas price of $3.59 per Mcf and an average oil price of
$57.72 per Bbl for the year ended December 31, 2009. Our increased production during this period was
primarily due to drilling operations in the Haynesville shale.

Realized gain (loss) on derivatives. Our realized gain on derivatives decreased by approximately

$2.3 million to $5.3 million for the year ended December 31, 2010 from $7.6 million for the year ended
December 31, 2009. This decrease was due primarily to a decrease of about $1.50 per MMBtu in the
average price floor of our open natural gas costless collar contracts in 2010 as compared with 2009 and
despite the fact that we had almost twice the natural gas volumes hedged in 2010 as compared to 2009.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was $3.14 million for the

year ended December 31, 2010, compared to an unrealized loss of $2.38 million for the year ended
December 31, 2009. During the period from December 31, 2009 to December 31, 2010, the net fair value of
our open natural gas costless collar contracts increased from $1.00 million to $4.14 million, resulting in an
unrealized gain on derivatives of $3.14 million for the year ended December 31, 2010. This increase in the
net fair value of our open natural gas costless collar contracts was due primarily to lower natural gas prices
at December 31, 2010 as compared to December 31, 2009.

Expenses

Production taxes and marketing. Production taxes are paid on produced oil and natural gas based on a
percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established
by federal, state or local taxing authorities. We attempt to take advantage of all credits and exemptions in
our various taxing jurisdictions. In general, the production taxes we pay tend to correlate to the changes in
our oil and natural gas revenues. Marketing expenses are fees charged by the purchasers of the oil and
natural gas we produce and sell and principally include marketing, compression and transportation fees.

Lease operating expenses. Lease operating expenses are the daily costs incurred to produce oil and
natural gas, as well as the daily costs incurred to maintain our producing properties. Such costs also include
field personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasional
workover expenses related to our oil and natural gas properties.

Depletion, depreciation and amortization. Depletion, depreciation and amortization includes the
systematic expensing of the capitalized costs incurred in the acquisition, exploration and development of oil
and natural gas. We use the full-cost method of accounting and accordingly, we capitalize all costs
associated with the acquisition, exploration and development of oil and natural gas properties, including
unproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directly
related to acquisition, exploration or development activities and do not include any costs related to
production, selling or general corporate administrative activities. Capitalized costs of oil and natural gas
properties are amortized using the unit-of-production method based upon production and estimates of

proved oil and natural gas reserves quantities. Unproved and unevaluated property costs are excluded from
the amortization base used to determine depletion, depreciation and amortization.

Accretion of asset retirement obligations. Asset retirement obligations relate to the future costs

associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities
from leased acreage and returning such land to its original condition. We recognize the fair value of an asset
retirement obligation in the period it is incurred if a reasonable estimate of fair value can be made. The asset
retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase
recognized in oil and natural gas properties or support equipment and facilities on the balance sheet.
Periodic accretion of the discounted value of the estimated liability is recorded as an expense in our
statement of operations.

Full-cost ceiling impairment. The net capitalized costs of oil and natural gas properties are limited to

the lower of unamortized costs less related deferred income taxes or the cost center ceiling, with any excess
above the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceiling
is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil
and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the
lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being
amortized, if any, less (d) income tax effects related to the properties involved. Future net revenues from
proved non-producing and proved undeveloped reserves are reduced by the estimated costs of developing
these reserves. The fair value of our derivative instruments is not included in the ceiling test computation as
we do not designate these instruments as hedge instruments for accounting purposes.

General and administrative expenses. General and administrative expenses include, but are not limited
to, compensation and benefits for our employees, costs of renting and maintaining our headquarters, office
service contracts, board of directors fees, franchise taxes, stock-based compensation expense and
accounting, legal and other professional fees.

Other Income (Expense)

Net gain (loss) on asset sales and inventory impairment. This other income (expense) item includes the

net gain or loss we experience on infrequent asset sales or impairment charges associated with certain
equipment held in inventory. This item also includes infrequent sales of oil and natural gas properties that
we consider to be extraordinary when considered in relation to the normal course of our business.

Interest expense. Interest expense includes interest paid to our lenders as a result of borrowings under

our revolving credit agreement. We finance a portion of our working capital requirements, capital
expenditures and acquisitions with borrowings under the credit agreement, and as a result, we incur interest
expense that is affected by both fluctuations in interest rates and our financing decisions. In addition, we
include any amortization of deferred financing costs (including origination and amendment fees),
commitment or facility fees and annual agency fees as interest expense.

Interest and other income. Interest income includes interest earned periodically on the cash and cash
equivalents we hold in money market accounts composed of United States Treasury securities offering daily
liquidity and the interest earned periodically on our certificates of deposit. Other income includes income
we receive for providing salt water disposal and natural gas transportation services to other working interest
participants in wells that we operate.

Total income tax provision (benefit). Total income tax provision (benefit) includes the net current and
deferred portions of our estimated income tax liabilities. We file a United States federal income tax return
and state tax returns in those states where we conduct oil and natural gas operations. The current portion of
our income tax provision (benefit) reflects actual income tax payments made or refunds received by us as a
result of filing these income tax returns. The deferred portion of our income tax provision is the result of
temporary timing differences between the financial statement carrying values and the tax bases of our assets
and liabilities.

The following table summarizes our operating expenses and other income (expense) for the periods

indicated:

(In thousands, except expenses per Mcfe)
Expenses:

Production taxes and marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Full-cost ceiling impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating (loss) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (expense) income:

Net loss on asset sales and inventory impairment
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total other (expense) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Loss) income before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax (benefit) provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net (loss) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expenses per Mcfe:

Year Ended December 31,

2011

2010

2009

$ 6,278
7,244
31,754
209
35,673
13,394

94,552
(15,308)

(154)
(683)
315

(522)
(15,830)
(5,521)
$(10,309)

$
$
$
$

0.41
0.47
2.06
0.87

$ 1,982
5,284
15,596
155
–
9,702

32,719
9,761

(224)
(3)
364

137
9,898
3,521
$ 6,377

$
$
$
$

0.23
0.61
1.81
1.13

$ 1,077
4,725
10,743
137
25,244
7,115

49,041
(24,752)

(379)
–
781

402
(24,350)
(9,925)
$(14,425)

$
$
$
$

0.22
0.94
2.15
1.42

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Production taxes and marketing. Our production taxes and marketing expenses increased by $4.3 million

to $6.3 million, or an increase of approximately 217% for the year ended December 31, 2011 as compared to
the year ended December 31, 2010. The increase in our production taxes and marketing expenses reflects the
increases in both our oil and natural gas production and revenues by 79% and 97%, respectively, during the
year ended December 31, 2011 as compared to the year ended December 31, 2010. The majority of this
increase was due to higher marketing, transportation and compression charges on portions of our non-operated
Haynesville shale production in 2011 as compared to 2010. Some of this increase was also due to Haynesville
shale wells completed in 2011, several of which were turned to sales or produced their first significant
production volumes during 2011. Although we or our outside operating partners have applied for exemptions
from initial production taxes on these recently completed Haynesville shale wells, and although we expect
these applications will be approved by the state of Louisiana, some of these wells had not yet been approved
for production tax exemptions at December 31, 2011. Thus, we have paid and/or accrued for the associated
production taxes on these wells during the year ended December 31, 2011, although we expect these
production taxes will be refunded to us in future periods. We will adjust our production taxes and marketing

expenses accordingly when and if these production tax exemptions are approved. The remainder of the
increase in production taxes and marketing expenses for the year ended December 31, 2011 was due to
production taxes paid on production from our initial Eagle Ford shale wells in south Texas.

Lease operating expenses. Our lease operating expenses increased by $2.0 million to $7.2 million, or

an increase of about 37%, for the year ended December 31, 2011 as compared to the year ended
December 31, 2010. During these respective periods, however, our oil and natural gas production increased
79% from 8.6 Bcfe to 15.4 Bcfe. As a result, our lease operating expenses per unit of production decreased
by 23% to $0.47 per Mcfe for the year ended December 31, 2011 as compared to $0.61 per Mcfe for the
year ended December 31, 2010. During the year ended December 31, 2011, both our total Haynesville shale
production, as well as the percentage of our Haynesville production for which we were the operator
increased, as compared to the year ended December 31, 2010. The unit lease operating costs associated with
the Haynesville production are much less than those associated with our Cotton Valley natural gas
production, primarily due to the greater salt water disposal costs associated with the Cotton Valley
production and given the early stages of production associated with many of these Haynesville wells.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses
increased by $16.2 million to $31.8 million, or an increase of about 104%, for the year ended December 31,
2011 as compared to the year ended December 31, 2010. The increase in our depletion, depreciation and
amortization expenses was due primarily to an increase of approximately 79% in our oil and natural gas
production from 8.6 Bcfe to 15.4 Bcfe during the respective time periods. Our depletion, depreciation and
amortization expenses on a unit-of-production basis increased to $2.06 for the year ended December 31,
2011, or an increase of about 14%, from $1.81 per Mcfe for the year ended December 31, 2010. This per
unit increase reflects increases in drilling and completion costs for wells drilled to the Haynesville shale
during 2011, as well as higher drilling and completion costs on a per Mcfe basis associated with oil reserves
added in the Eagle Ford shale in south Texas.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expenses
increased by approximately $54,000 to approximately $209,000, or an increase of about 35%, for the year
ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in our accretion
of asset retirement obligations was due primarily to the addition of new wells through our drilling of
operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item
is an insignificant component of our overall expenses.

Full-cost ceiling impairment. During the quarter ended March 31, 2011, the net capitalized costs of our

oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0
million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our
oil and natural gas properties and a deferred income tax credit of $12.7 million, which is reflected in our
expenses for the year ended December 31, 2011. No impairment to the net carrying value of our oil and
natural gas properties on the balance sheet resulting from the full-cost ceiling limitation was recorded at
December 31, 2010.

General and administrative. Our general and administrative expenses increased by $3.7 million to
$13.4 million, or an increase of about 38%, for the year ended December 31, 2011 as compared to the year
ended December 31, 2010. The increase in our general and administrative expenses was due primarily to
increased cash and non-cash compensation expenses and increased accounting expenses for the year ended
December 31, 2011 as compared to the year ended December 31, 2010. We recorded approximately $2.4
million in non-cash compensation expense for the year ended December 31, 2011 as compared to
approximately $0.9 million recorded for the year ended December 31, 2010. This increase was primarily

due to a change in accounting method for valuing our outstanding stock options. We awarded no new stock
options during 2011. As a result of our increased oil and natural gas production, however, our general and
administrative expenses decreased by 27% on a unit-of-production basis to $0.87 per Mcfe for the year
ended December 31, 2011 as compared to $1.13 per Mcfe for the year ended December 31, 2010.

Net gain (loss) on asset sales and inventory impairment. We incurred a loss on asset sales and

inventory impairment of approximately $154,000 for the year ended December 31, 2011, as compared to a
loss of approximately $224,000 for the year ended December 31, 2010. During the year ended
December 31, 2011, this loss was primarily related to the sale of pipe and other equipment and the
impairment of certain equipment held in inventory, consisting primarily of drilling rig parts. During the year
ended December 31, 2010, we wrote off the Boise South pipeline asset in Orange County, Texas and
recognized a net loss of approximately $174,000. We also recognized an impairment of approximately
$50,000 to some of our equipment held in inventory following a determination that the market value of the
equipment, consisting primarily of drilling rig parts, was less than the cost.

Interest expense. For the year ended December 31, 2011, we incurred total interest expense of
approximately $2.0 million. We capitalized approximately $1.3 million of our interest expense on certain
qualifying projects for the year ended December 31, 2011 and expensed the remaining $683,000 to
operations. During the year ended December 31, 2011, we incurred incremental net borrowings of $88.0
million under our credit agreement to finance a portion of our working capital requirements and capital
expenditures. Our total outstanding borrowings at December 31, 2011 were $113.0 million, and the interest
rate on these borrowings was approximately 5.3% per annum. In early January 2012, we converted this
$113.0 million base rate advance to a Eurodollar-based advance, which then bore interest at 3.5% per
annum. In December 2010, we borrowed $25.0 million under our credit agreement to finance a portion of
our working capital requirements and capital expenditures, which remained outstanding at December 31,
2010. We incurred interest expense of approximately $3,000 for the year ended December 31, 2010.

Interest and other income. Our interest and other income decreased by approximately $50,000 to
approximately $314,000, or a decrease of about 14%, for the year ended December 31, 2011 as compared to
the year ended December 31, 2010. The decrease in our interest and other income was due primarily to a
decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we
received interest income between the two periods. Our cash and cash equivalents and certificates of deposit
decreased to approximately $11.6 million at December 31, 2011 from approximately $23.4 million at
December 31, 2010, as we used cash and incremental borrowings to acquire additional leasehold acreage in
the Eagle Ford shale play in south Texas and in the core area of the Haynesville shale play in northwest
Louisiana and to fund our operated and non-operated drilling and completion activities in both areas.

Total income tax provision (benefit). We recorded a total income tax benefit of approximately $5.5
million for the year ended December 31, 2011 as compared to a total income tax provision of approximately
$3.5 million for the year ended December 31, 2010. The total income tax benefit for the year ended
December 31, 2011 reflected deferred income taxes almost entirely, with the exception of a state of Louisiana
income tax refund of approximately $46,000 recorded during this period. During the first quarter ended
March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income
taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of
$35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit
of $12.7 million. We recorded a total income tax provision of approximately $3.5 million for the year ended
December 31, 2010. The total income tax provision for the year ended December 31, 2010 included a deferred
income tax provision of approximately $4.9 million and a current income tax benefit of approximately $1.4
million, which was attributable to a refund of U.S. federal income taxes received by us. For the year ended

December 31, 2010, the deferred income tax provision was consistent with our income before income taxes,
which included approximately $3.1 million in unrealized hedging gains. We had a net loss for the year ended
December 31, 2011, and our effective tax rate for the year ended December 31, 2010 was 35.57%.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Production taxes and marketing. Our production taxes and marketing expenses increased by $0.9 million to
$2.0 million, or an increase of about 84%, for the year ended December 31, 2010 as compared to the year ended
December 31, 2009. The increase in our production taxes and marketing expenses was due primarily to the
increase in our oil and natural gas revenues from $19.0 million to $34.0 million, or an increase of about 79%,
during the respective time periods. On a unit-of-production basis, our production taxes and marketing expenses
remained relatively constant year-over-year, increasing to $0.23 per Mcfe for the year ended December 31, 2010
from $0.22 per Mcfe for the year ended December 31, 2009.

Lease operating expenses. Our lease operating expenses increased by $0.6 million to $5.3 million, or

an increase of about 12%, for the year ended December 31, 2010 as compared to the year ended
December 31, 2009. During these respective periods, however, our oil and natural gas production increased
72% to 8.6 Bcfe from 5.0 Bcfe. As a result, our lease operating expenses per unit of production decreased
by 35% to $0.61 per Mcfe for the year ended December 31, 2010 as compared to $0.94 per Mcfe for the
year ended December 31, 2009. In 2010, the percentage of our production attributed to the Haynesville
shale continued to increase. The unit lease operating costs associated with the Haynesville production are
much less than those associated with our Cotton Valley natural gas production, primarily due to the greater
salt water disposal costs associated with the Cotton Valley production.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses
increased by $4.9 million to $15.6 million, or an increase of about 45%, for the year ended December 31,
2010 as compared to the year ended December 31, 2009. The increase in our depletion, depreciation and
amortization expenses was due primarily to the increase in our oil and natural gas production to 8.6 Bcfe
from 5.0 Bcfe during the respective time periods. The finding and development costs associated with our
Haynesville shale reserves have been less than finding and development costs associated with our reserves
producing from the Cotton Valley and other formations. As a result, our depletion, depreciation and
amortization expenses on a unit-of-production basis decreased as our Haynesville production increased;
these expenses decreased to $1.81 per Mcfe during the year ended December 31, 2010 from $2.15 per Mcfe
during the year ended December 31, 2009.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expenses
increased by approximately $18,000 to approximately $155,000, or an increase of about 13%, for the year
ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in our accretion
of asset retirement obligations was due primarily to the addition of new wells through our drilling of
operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item
is an insignificant component of our overall expenses.

Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas
properties on the balance sheet resulting from the full-cost ceiling limitation was recorded at December 31,
2010. At December 31, 2009, the net capitalized costs of our oil and natural gas properties less related
deferred income taxes exceeded the cost center ceiling by $16.3 million. As a result, we recorded an
impairment charge of $25.2 million to the net capitalized costs of our oil and natural gas properties and a
deferred income tax credit of $8.9 million. A corresponding charge of $25.2 million was also recorded to
the consolidated statement of operations for the year ended December 31, 2009.

General and administrative. Our general and administrative expenses increased by $2.6 million to $9.7
million, or an increase of about 36%, for the year ended December 31, 2010 as compared to the year ended
December 31, 2009. Approximately $1.0 million of this increase was due to legal and other due diligence
fees resulting from an unsuccessful effort to acquire oil and natural gas producing properties and associated
acreage. The remainder of the increase was due primarily to increased compensation expenses resulting
from both increased salaries and retention and performance bonuses paid to certain employees during the
year ended December 31, 2010. As a result of our increased oil and natural gas production, however, our
general and administrative expenses decreased by 20% on a unit-of-production basis to $1.13 per Mcfe for
the year ended December 31, 2010 as compared to $1.42 per Mcfe for the year ended December 31, 2009.

Net gain (loss) on asset sales and inventory impairment. During the year ended December 31, 2010,

we wrote off the Boise South Pipeline asset in Orange County, Texas and recognized a net loss of
approximately $174,000. We also recognized an impairment of approximately $50,000 to some of our
equipment held in inventory following a determination that the market value of the equipment, consisting
primarily of drilling rig parts, was less than the cost. During the year ended December 31, 2009, we
recognized impairments to these drilling rig parts and tubular goods held in inventory and sold rod parts
held in inventory, recognizing a net loss of approximately $379,000.

Interest expense. In December 2010, we borrowed $25.0 million under our credit agreement to finance
a portion of our working capital requirements and capital expenditures. We incurred approximately $3,000
in interest expense for the year ended December 31, 2010. At December 31, 2010, the interest rate on the
outstanding borrowings was approximately 1.6% per annum. We had no borrowings under the credit
agreement in 2009, and as a result, we incurred no interest expense for the year ended December 31, 2009.

Interest and other income. Our interest and other income decreased by approximately $0.4 million to
approximately $0.4 million, or a decrease of about 53%, for the year ended December 31, 2010 as compared
to the year ended December 31, 2009. The decrease in our interest and other income was due primarily to a
decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we
receive interest income during the year ended December 31, 2010 as compared to the year ended
December 31, 2009. Our cash and cash equivalents and certificates of deposit decreased to $23.4 million at
December 31, 2010 from $119.9 million at December 31, 2009, as we used cash during this period
primarily to acquire additional leasehold acreage in the Eagle Ford shale play in south Texas and in the core
area of the Haynesville shale play in northwest Louisiana and to fund our operated and non-operated drilling
and completion activities in both areas.

Total income tax provision (benefit). We recorded a total income tax provision of approximately $3.5
million for the year ended December 31, 2010 as compared to a total income tax benefit of approximately
$9.9 million recorded for the year ended December 31, 2009. For the year ended December 31, 2010, we
recorded a current income tax benefit of approximately $1.4 million, which was attributable to a refund of
U.S federal income taxes received by us, and we also recorded a deferred income tax provision of $4.9
million consistent with the increase in our income before income taxes for that year. For the year ended
December 31, 2009, we recorded a current income tax benefit of approximately $2.3 million, primarily
attributable to a net refund of U.S. federal income taxes and a refund of income taxes from the state of
Louisiana. We also recorded a deferred income tax benefit of approximately $7.6 million, primarily
attributable to the full-cost ceiling impairment recorded in 2009. Our effective tax rate for the year ended
December 31, 2010 was 35.57%, and we had a net loss for the year ended December 31, 2009.

Liquidity and Capital Resources

Prior to the consummation of our initial public offering on February 7, 2012, our primary sources of

liquidity were capital contributions from private investors, our cash flows from operations, borrowings
under our credit agreement and the proceeds from a significant sale of a portion of our assets in 2008. Our
primary use of capital has been, and will continue to be during 2012 and for the foreseeable future, for the
acquisition, exploration and development of oil and natural gas properties. We continually evaluate
potential capital sources, including equity and debt financings and additional borrowings, in order to meet
our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves
and production will be highly dependent on our ability to access outside sources of capital. At December 31,
2011, we had cash and certificates of deposits totaling approximately $11.6 million.

In December 2011, we amended and restated our senior secured revolving credit agreement for which

Comerica Bank serves as administrative agent. This amendment increased the maximum facility amount
from $150.0 million to $400.0 million. Borrowings are limited to the lesser of $400.0 million or the
borrowing base. At December 31, 2011, the borrowing base was $125.0 million, and we had $113.0 million
of outstanding indebtedness, excluding $1.3 million in outstanding letters of credit. Subsequent to year end,
we used the net proceeds from our initial public offering to repay the outstanding indebtedness under our
credit agreement in full and our borrowing base was reduced to $100.0 million. On February 28, 2012, our
borrowing base increased to $125.0 million pursuant to a borrowing base redetermination made by the
lenders at our request. We may request additional redeterminations in accordance with our credit agreement
as we increase our proved reserves. The new amended and restated credit agreement matures in December
2016. In March 2012, we borrowed $15.0 million under the credit agreement to finance a portion of our
working capital requirements. At March 30, 2012, our borrowings bore interest at a variable rate of 1.75%
plus a Eurodollar-based rate per annum, which equated to approximately 2.0% per annum.

We actively review acquisition opportunities on an ongoing basis. While we believe our cash and cash

equivalents, together with our cash flows and future potential borrowings under our credit agreement, will
be adequate to fund our capital expenditure requirements and any acquisitions of interests and acreage for
2012, funding for future acquisitions of interests and acreage or our future capital expenditure requirements
for 2013 and subsequent years may require additional sources of financing, which may not be available. As
a result of our anticipated increases in production and reserves, we expect to have a sufficient increase in
our cash flows from operations during the year ending December 31, 2012, as compared to our cash flows
from operations in prior periods, as well as a sufficient increase in the borrowing base under our credit
agreement to help fund our 2012 capital expenditure budget. A majority of our anticipated increase in cash
flows during the year ending December 31, 2012 is expected to come from our exploration activities on
unproved properties at December 31, 2011 in the Eagle Ford shale play assuming such exploration activities
are successful. These anticipated increases in our cash flows from operations are based upon current oil and
natural gas prices and the hedges we currently have in place. If our exploration activities result in less cash
flows than anticipated, we may seek additional sources of capital, including through borrowings under our
credit agreement (assuming availability under our borrowing base). In addition to future borrowings under
our credit agreement, we may also seek to raise additional funds by selling shares of our common stock or
securities convertible or exercisable into our common stock (including debt securities or other preferential
securities) in the public markets or otherwise. It is likely that any such sales would dilute the ownership
interest of our existing shareholders. It is also possible that, to the extent we are not able to obtain additional
sources, we may modify our planned capital expenditure budget for 2012 accordingly. Exploration activities
are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our
reserves, cash flows from operations and borrowing base under our credit agreement. See “Risk Factors —
Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That

May Exceed Our Cash Flows From Operations and Potential Borrowings, and We May Be Unable to
Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk
Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High
Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors —
Our Identified Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to
Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.”

Our cash flows for the years ended December 31, 2011, 2010 and 2009 are presented below:

(In thousands)
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 61,868
(160,087)
87,444

$ 27,273
(147,334)
36,891

$ 1,791
(49,415)
1,086

Net change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ (10,775)

$ (83,170)

$(46,538)

Year Ended December 31,

2011

2010

2009

Cash Flows Provided by Operating Activities

Net cash provided by operating activities increased by $34.6 million to $61.9 million for the year
ended December 31, 2011 as compared to net cash provided by operating activities of $27.3 million for the
year ended December 31, 2010. Net cash provided by oil and natural gas operations increased significantly
to $49.3 million for the year ended December 31, 2011 from $25.0 million for the year ended December 31,
2010. This increase reflects primarily the 79% increase in our oil and natural gas production to 15.4 Bcfe
from 8.6 Bcfe between the respective periods. A portion of the increase in net cash provided by operating
activities also reflects the approximate five-fold increase in our oil production for the year ended
December 31, 2011 as compared to the year ended December 31, 2010, as well as a higher average oil price
of $93.80 per Bbl realized during 2011 as compared to an average oil price of $76.39 per Bbl realized
during 2010. Some of this increase in net cash provided by operating activities is also due to changes in our
operating assets and liabilities totaling approximately $10.3 million between December 31, 2010 and
December 31, 2011. Our accounts payable and accrued liabilities increased to approximately $44.3 million
at December 31, 2011 from approximately $27.0 million at December 31, 2010 due to our increased
operating activity in south Texas. Our accounts receivable increased to $13.2 million at December 31, 2011
as compared to $11.6 million at December 31, 2010 due primarily to the increase in our oil and natural gas
production and associated revenues.

Net cash provided by operating activities increased by $25.5 million to $27.3 million for the year
ended December 31, 2010 as compared to net cash provided by operating activities of $1.8 million for the
year ended December 31, 2009. The increase in cash flows provided by operations reflects an increase in
our production to 8.6 Bcfe from 5.0 Bcfe and an increase in the average prices we received for oil and
natural gas production for the year ended December 31, 2010 as compared to the year ended December 31,
2009. Our accounts payable and accrued liabilities were approximately $26.8 million at December 31, 2010
as a result of operated horizontal wells that we were drilling and/or completing in the Haynesville and Eagle
Ford shale plays and in the Cotton Valley formation during the fourth quarter of 2010. Our accounts
payable and accrued liabilities were $7.3 million at December 31, 2009 as we were drilling and completing
only one operated horizontal Haynesville shale well at that time.

Our operating cash flows are sensitive to a number of variables, including changes in our production and
volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity,
weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil

and natural gas. These factors are beyond our control and are difficult to predict. For additional information on
the impact of changing prices on our financial position, see “Quantitative and Qualitative Disclosures About
Market Risk” below. See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas.
Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial
Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.”

Cash Flows Used in Investing Activities

Net cash used in investing activities increased by $12.8 million to $160.1 million for the year ended
December 31, 2011 from $147.3 million for the year ended December 31, 2010. This increase in net cash
used in investing activities reflected a decrease of $2.6 million in our oil and natural gas properties capital
expenditures for the year ended December 31, 2011 as compared to the year ended December 31, 2010,
offset almost exactly by an increase of approximately $3.0 million in expenditures for other property and
equipment, which includes new pipeline infrastructure associated with our initial wells in the Eagle Ford
shale. Although our capital expenditures were relatively flat year-over-year, approximately 75% of our
capital expenditures were allocated to drilling and completion operations and 25% to the acquisition of
additional acreage for the year ended December 31, 2011, as compared to approximately 43% allocated to
drilling and completion operations and 57% allocated to acquisition of additional acreage for the year ended
December 31, 2010. Our oil and natural gas properties capital expenditures for the year ended December 31,
2011 were primarily due to expenditures associated with our operated and non-operated drilling and
completion activities in the Eagle Ford and Haynesville shale plays and our acreage acquisition in Karnes,
DeWitt, Wilson and Gonzales Counties, Texas that we believe to be prospective for the Eagle Ford shale.

Net cash used in investing activities increased by $97.9 million to $147.3 million for the year ended
December 31, 2010 from $49.4 million for the year ended December 31, 2009. This increase in net cash used in
investing activities reflects primarily an increase of $104.8 million in our oil and natural gas properties capital
expenditures for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The
increased oil and natural gas properties capital expenditures for the year ended December 31, 2010 were due to
the acquisition of leasehold acreage in the Eagle Ford shale play and the acquisition of additional leasehold
acreage in the Haynesville shale play, as well as expenditures associated with our operated and non-operated
drilling and completion activities in both plays as compared to the year ended December 31, 2009.

Expenditures for the acquisition, exploration and development of oil and natural gas properties are the

primary use of our capital resources. We anticipate investing $313.0 million in capital for acquisition,
exploration and development activities in 2012 as follows:

Exploration and development drilling and associated infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Leasehold acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other capital expenditures, 2-D and 3-D seismic data and recompletions of existing wells . . . . . . . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Amount
(in millions)

$284.5
24.0
4.5

$313.0

For further information regarding our anticipated capital expenditure budget in 2012, see “Business—

General.”

Our 2012 capital expenditures may be adjusted as business conditions warrant. The amount, timing and

allocation of capital expenditures is largely discretionary and within our control. If oil or natural gas prices
decline or costs increase significantly, we could defer a significant portion of our anticipated capital
expenditures until later periods to conserve cash or to focus on those projects that we believe have the

highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust
our capital expenditures in response to changes in prices, availability of financing, drilling, completion and
acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or
lack of success in our exploration and development activities, contractual obligations and other factors both
within and outside our control.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities was $87.4 million for the year ended December 31, 2011, as

compared to net cash provided by financing activities of $36.9 million for the year ended December 31,
2010. The net cash provided by financing activities for the year ended December 31, 2011 was due almost
entirely to additional borrowings of $88.0 million under our credit agreement to fund our working capital
requirements as well as our acquisition of acreage prospective for the Eagle Ford shale play in Karnes,
DeWitt, Wilson and Gonzales Counties, Texas. In January 2011, we sold 53,772 shares of our Class A
common stock in a private placement and received net proceeds of approximately $0.6 million. During
2011, we also received proceeds from the exercise of stock options totaling approximately $0.8 million. For
the year ended December 31, 2011, we also incurred cash expenditures related to preparation for our initial
public offering of approximately $1.7 million.

Net cash provided by financing activities was $36.9 million for the year ended December 31, 2010 as

compared to net cash provided by financing activities of $1.1 million for the year ended December 31,
2009. For the year ended December 31, 2010, the most significant financing activities occurred in the fourth
quarter of 2010. During that time, we sold approximately 1.9 million shares of our Class A common stock
in a private placement and received net proceeds of approximately $21.0 million, and we borrowed $25.0
million under our credit agreement. In addition, in April 2010, we repurchased 1,000,000 shares of Class A
common stock from five shareholders, all advised by Wellington Management Company, for a total of $9.0
million. We also received proceeds of approximately $2.0 million from the periodic exercise of stock
options during the year ended December 31, 2010. For the year ended December 31, 2009, the most
significant financing activities occurred in April 2009 when we repurchased approximately 5.4 million
shares of Class A common stock from Gandhara Capital, one of our largest shareholders at the time, for a
total of $27.1 million and in May through September 2009 when we sold approximately 5.0 million shares
of Class A common stock in a private placement and received net proceeds of approximately $28.0 million.
We also received proceeds of approximately $1.3 million from the periodic exercise of stock options for the
year ended December 31, 2009.

Credit Agreement

In December 2011, we amended and restated our senior secured revolving credit agreement for which

Comerica Bank serves as administrative agent. Among other things, this amendment increased the size of
the facility and extended the term until December 2016. MRC Energy Company is the borrower under the
new amended credit agreement. Borrowings are secured by mortgages on substantially all of our oil and
natural gas properties and by the equity interests of all of MRC Energy Company’s wholly owned
subsidiaries, which are also guarantors. In addition, all obligations under the credit agreement are
guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging
agreements with one of the lenders under the credit agreement (or an affiliate thereof) are also secured by
the collateral and guaranteed by the subsidiaries of MRC Energy Company.

The amount of the borrowings under our amended and restated credit agreement is limited to the lesser

of $400.0 million or the borrowing base, which is determined semi-annually as of May 1 and November 1

by the lenders based primarily on the estimated value of our existing and future acquired oil and gas
reserves, but also on external factors, such as the lenders’ lending policies and the lenders’ estimates of
future oil and natural gas prices, over which we have no control. At December 31, 2011, the borrowing base
was $125.0 million and we had $113.0 million in outstanding borrowings under the credit agreement. In
January 2012, we borrowed an additional $10.0 million to finance a portion of our working capital
requirements, bringing the then total outstanding indebtedness under the credit agreement to $123.0 million.
Following the completion of our initial public offering, we used a portion of the net proceeds to repay the
$123.0 million outstanding under our credit agreement in February 2012, at which time the borrowing base
was reduced to $100.0 million. On February 28, 2012, the borrowing base was increased to $125.0 million
pursuant to a special borrowing base redetermination made at our request. This borrowing base increase was
determined by our lenders based upon, among other items, the increase in our oil and natural gas reserves at
December 31, 2011.

In March 2012, we borrowed $15.0 million under the credit agreement to finance a portion of our

working capital requirements and capital expenditures. At March 30, 2012, we had $15.0 million in
borrowings outstanding under the credit agreement, approximately $1.3 million in outstanding letters of
credit issued pursuant to the credit agreement and approximately $108.7 million available for additional
borrowings. At March 30, 2012, our outstanding borrowings bore interest at approximately 2.0% per
annum. We expect to access future borrowings under our credit agreement to fund a portion of our 2012
capital expenditure requirements in excess of amounts available from our cash flows. During 2012, we also
intend to seek additional redeterminations of our borrowing base as a result of, among other items, any
increases to our proved oil and natural gas reserves during the year.

Both we and the lenders may each request an unscheduled redetermination of the borrowing base twice

at any time during the first year of the credit agreement and once between scheduled redetermination dates
thereafter. As noted above, we requested one such unscheduled redetermination in February 2012. In the
event of a borrowing base increase, we are required to pay a fee to the lenders equal to a percentage of the
amount of the increase, which will be determined based on market conditions at the time of the borrowing
base increase. If the borrowing base were to be less than the outstanding borrowings under the credit
agreement at any time, we would be required to provide additional collateral satisfactory in nature and value
to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the
deficit in equal installments over a period of six months.

If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher

of (i) the weighted average of rates used in overnight federal funds transactions with members of the
Federal Reserve System plus 1.0% or (ii) the prime rate for Comerica Bank then in effect or (iii) a daily
adjusted LIBOR rate plus 1.0% plus, in each case, an amount from 0.375% to 1.75% of such outstanding
loan depending on the level of borrowings under the agreement. If we borrow funds as a Eurodollar loan,
such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the interest rate
appearing on Page BBAM of the Bloomberg Financial Markets Information Service by (B) a percentage
equal to 100% minus the maximum rate during such interest calculation period at which Comerica Bank is
required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of
Governors of the Federal Reserve System), plus (ii) an amount from 1.375% to 2.75% of such outstanding
loan depending on the level of borrowings under the agreement. The interest period for Eurodollar
borrowings may be one, two, three or six months as designated by us. A facility fee of 0.375% to 0.50%,
depending on the amounts borrowed, is also paid quarterly in arrears. We include the facility fee in our
interest rate calculations and related disclosures.

Key financial covenants under the credit agreement require us to maintain (1) a minimum current ratio,
which is defined as consolidated total current assets plus the unused availability under the credit agreement
divided by consolidated total current liabilities, of 1.0 for all reporting periods beginning March 31, 2012,
and (2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter
EBITDA calculation, of 4.0 to 1.0 or less, beginning December 31, 2011.

Subject to certain exceptions, our credit agreement contains various covenants that limit our, along

with our subsidiaries’, ability to take certain actions, including, but not limited to, the following:

• incur indebtedness or grant liens on any of our assets;

• enter into commodity hedging agreements;

• declare or pay dividends, distributions or redemptions;

• merge or consolidate;

• make any loans or investments;

• engage in transactions with affiliates; and

• engage in certain asset dispositions, including a sale of all or substantially all of our assets.

If an event of default exists under the credit agreement, the lenders will be able to accelerate the
maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not
limited to, the following events:

• failure to pay any principal or interest on the notes or any reimbursement obligation under any

letter of credit when due or any fees or other amount within certain grace periods;

• failure to perform or otherwise comply with the covenants and obligations in the credit agreement

or other loan documents, subject, in certain instances, to certain grace periods;

• bankruptcy or insolvency events involving us or our subsidiaries; and

• a change of control, as defined in the credit agreement.

In December 2010, the credit agreement was amended to increase the borrowing base to $55.0 million.

At December 31, 2010, we had $25.0 million of outstanding borrowings and $50,000 in letters of credit
issued pursuant to the credit agreement. At December 31, 2010, all borrowings under the credit agreement
were Eurodollar loans, and the interest rate on the outstanding borrowings was approximately 1.6% per
annum. We had an additional $325,000 in letters of credit secured by certificates of deposit at Comerica
Bank at December 31, 2010.

At December 31, 2011, the borrowing base available for revolving borrowings was $125.0 million, and
we had $113.0 million in revolving borrowings outstanding under the credit agreement, approximately $1.3
million in outstanding letters of credit issued pursuant to the credit agreement and approximately $10.7
million available for additional borrowings. At December 31, 2011, our outstanding revolving borrowings
bore interest at the rate of approximately 5.3% per annum. Prior to the December 2011 amendment, the
outstanding revolving borrowings under our credit agreement were scheduled to mature in March 2013.

In addition to our revolving borrowings under our credit agreement, in May 2011, we borrowed

$25.0 million in a term loan pursuant to the credit agreement to help finance the acquisition of the Eagle Ford
shale acreage from Orca ICI Development, JV in Karnes, DeWitt, Wilson and Gonzales Counties, Texas. The
term loan was due and payable on December 31, 2011, and there was no penalty for prepayment. The term loan
was refinanced by borrowings under the amended and restated credit agreement in December 2011.

We believe that we were in compliance with the terms of our credit agreement and with all our bank

covenants at December 31, 2011. We obtained a written extension until May 1, 2012 to comply with a
covenant under the credit agreement requiring the submission of certain year-end 2011 operating
information for the lenders’ use on or before March 1, 2012.

Off-Balance Sheet Arrangements

At December 31, 2011, we did not have any off-balance sheet arrangements.

Obligations and Commitments

We had the following material contractual obligations and commitments at December 31, 2011:

Payments Due by Period

Total

Less Than
1 Year

1-3 Years

3-5 Years

More Than
5 Years

(in thousands)
Contractual Obligations:
Revolving credit borrowings and term loan, including letters of

credit(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Office lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-operated drilling commitments(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling rig contracts(3)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employee bonuses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$114,300
6,243
5,100
2,667
1,240
4,270

$26,300
287
5,100
2,667
–
263

–
1,150
–
–
1,240
413

$88,000
1,193
–
–
–
993

–
3,613
–
–
–
2,601

Total contractual cash obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$133,820

$34,617

$2,803

$90,186

$6,214

(1) At December 31, 2011, we had $113.0 million in revolving borrowings outstanding under our amended and restated credit agreement

and approximately $1.3 million in outstanding letters of credit issued pursuant to the credit agreement. A total of $25.0 million of these
borrowings was scheduled to mature on December 31, 2012, and the remaining borrowings were scheduled to mature in December 2016.
These amounts do not include estimated interest on the obligations, because our revolving borrowings had short-term interest periods,
and we are unable to determine what our borrowing costs may be in future periods.

(2) At December 31, 2011, we had outstanding commitments to participate in the drilling and completion of various non-operated wells in
the Haynesville shale. Our working interests in these wells are small, and most of these wells were in progress at December 31, 2011. If
all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these
wells of approximately $5.1 million at December 31, 2011, which we expect to incur within the next 12 months.

(3) At December 31, 2011, we had entered into two drilling rig contracts to explore and develop our Eagle Ford acreage in south Texas. The
two rigs began drilling on our acreage in September 2011 and October 2011, respectively. Both contracts are for a term of six months.
Should we elect to terminate one or both contracts and if the drilling contractor were unable to secure work for one or both rigs or if the
drilling contractor were unable to secure work for one or both rigs at the same daily rates being charged to us prior to the end of their
respective contract terms, we would incur termination obligations. Our maximum outstanding aggregate termination obligations under
these contracts were approximately $2.7 million at December 31, 2011.

General Outlook and Trends

For the year ended December 31, 2011, oil prices ranged from a high of approximately $114.00 per
Bbl in April to a low of approximately $76.00 per Bbl in October, based upon the NYMEX West Texas
Intermediate oil futures contract price for the earliest delivery date. Generally, oil prices remained above
$90.00 per Bbl for much of the year. We realized an average oil price of $93.80 per Bbl for our oil
production for the year ended December 31, 2011 as compared to $76.39 per Bbl for the year ended
December 31, 2010. At March 30, 2012, the NYMEX West Texas Intermediate oil futures contract for the
earliest delivery date closed at $103.02 per Bbl as compared to $104.27 per Bbl at March 30, 2011.

For the year ended December 31, 2011, natural gas prices ranged from a high of approximately $4.80 per

MMBtu in January and June to a low of approximately $3.00 per MMBtu in December, based upon the
NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices

remained relatively flat during the first six months of 2011 trading between approximately $3.80 per MMBtu
and $4.80 per MMBtu. Beginning in mid-July 2011, natural gas prices began a steady decline of more than
50% to their lowest levels in many years. We realized a natural gas price of $3.62 per Mcf ($4.11 per Mcf
including realized gains from natural gas derivatives) for our natural gas production for the year ended
December 31, 2011 as compared to $3.75 per Mcf ($4.38 per Mcf including realized gains from natural gas
derivatives) for the year ended December 31, 2010. At March 30, 2012, the NYMEX Henry Hub natural gas
futures contract for the earliest delivery date closed at $2.13 per MMBtu as compared to $4.36 per MMBtu at
March 30, 2011.

The prices we receive for oil and natural gas heavily influence our revenue, profitability, cash flow

available for capital expenditures, access to capital and future rate of growth. Oil and natural gas are
commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor
changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and these
markets will likely continue to be volatile in the future. Declines in oil or natural gas prices not only reduce
our revenue, but could also reduce the amount of oil and natural gas we can produce economically. From
time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk
associated with oil and natural gas prices. Even so, decisions as to whether and what production volumes to
hedge are difficult and depend on market conditions and our forecast of future production and oil and
natural gas prices, and we may not always employ the optimal hedging strategy. Should oil or natural gas
prices decrease to economically unattractive levels and remain there for an extended period of time, we may
elect to delay some of our exploration and development plans for our prospects, or to cease exploration or
development activities on certain prospects due to the anticipated unfavorable economics from such
activities, each of which would have a material adverse effect on our business, financial condition, results of
operations and reserves. This, in turn, may affect the liquidity that can be accessed through our borrowing
base under our credit agreement and through the capital markets.

Like other oil and natural gas producing companies, our properties are subject to natural production

declines. By their nature, our wells in the Eagle Ford shale and the Haynesville shale will experience rapid
initial production declines. We attempt to overcome these production declines by drilling to develop and
identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During
times of severe oil and natural gas price declines, however, we may find it necessary to reduce capital
expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital
expenditures and drilling activities could materially impact our production volumes, revenues, reserves and
cash flows.

We must focus our efforts on increasing oil and gas reserves and production while controlling costs at

a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of
oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and
development costs are subject to changes in the costs of acquiring, drilling and completing our prospects.

Critical accounting policies and estimates

We have outlined below certain accounting policies that are of particular importance to the

presentation of our financial condition and results of operations and require the application of significant
judgment or estimates by our management.

The preparation of financial statements requires us to make other estimates and assumptions that affect

the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We
believe that our estimates and assumptions are reasonable and reliable, and believe that the ultimate actual

results will not differ significantly from those reported; however, such estimates and assumptions are
subject to a number of risks and uncertainties, and such risk and uncertainties could cause the actual results
to differ materially from our estimates.

Property and Equipment

We use the full-cost method of accounting for our investments in oil and natural gas properties. Under
this method of accounting, all costs associated with the acquisition, exploration and development of oil and
natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as
incurred and accumulated in a single cost center representing our activities, which are undertaken
exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical
expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive
wells, capitalized interest on qualifying projects and general and administrative expenses directly related to
exploration and development activities, but do not include any costs related to production, selling or general
corporate administrative activities.

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs

less related deferred income taxes or the cost center ceiling, with any excess above the cost center ceiling
charged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of
(a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves,
plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or
estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any,
less (d) income tax effects related to the properties involved. Future net revenues from proved
non-producing and proved undeveloped reserves are reduced by the estimated costs of developing these
reserves. The fair value of our derivative instruments is not included in the ceiling test computation as we
do not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method

based upon production and estimates of proved reserves quantities. Unproved and unevaluated property
costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated
properties are assessed for impairment on a periodic basis based upon changes in operating or economic
conditions. This assessment includes consideration of the following factors, among others: the assignment
of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling
activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately
included in the amortization base. Exploratory dry holes are included in the amortization base immediately
upon the determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no

gain or loss recognized, unless such adjustments would significantly alter the relationship between net
capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and
maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’
reserves are capitalized.

Other property and equipment are stated at cost. Computer equipment, furniture, software and other
equipment are depreciated over their useful life (five to seven years) using the straight-line method. Support
equipment and facilities include the pipelines and salt water disposal systems owned by Longwood
Gathering and Disposal Systems, LP and are depreciated over a 30-year useful life using the straight-line,
mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful life
or the term of the lease.

Derivative Financial Instruments

From time to time, we use derivative financial instruments to hedge our exposure to commodity price
risk associated with oil and natural gas prices. These instruments consist of put and call options in the form
of costless (or zero-cost) collars. A costless collar provides us with downside price protection through the
purchase of a put option which is financed through the sale of a call option. Because the call proceeds are
used to offset the cost of the put option, this arrangement is initially “costless” to us. Our derivative
financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair
value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and
as a result, we recognize the change in derivative fair value between reporting periods currently in our
consolidated statement of operations. The fair value of our derivative financial instruments is determined
using purchase and sale information available for similarly traded securities. Realized gains and realized
losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses
from valuation changes in the remaining unsettled derivative financial instruments are reported under
“Revenues” in our consolidated statement of operations.

Revenue Recognition

We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize

revenue, net of royalties, on all oil or natural gas sold to purchasers regardless of whether the sales are
proportionate to our ownership in the property. Under this method, revenue is recognized at the time the oil
and natural gas are produced and sold, and we accrue for revenue earned but not yet received.

Stock-based Compensation

Non-qualified stock option expense is typically recognized in our consolidated statement of operations
on the date of grant. Incentive stock options vest over four years, and the associated compensation expense
is recognized on a straight-line basis over the vesting period. We account for stock based compensation in
accordance with ASC 718. At December 31, 2011, we used the fair value method to measure and recognize
the liability associated with our outstanding stock options. As our shares were not publicly traded prior to
February 2, 2012, we estimate the future volatility of our stock using the historical volatility of the common
stock of a group of companies we consider to be a representative peer group. Management believes that
these average historical volatility rates are currently the best available indicator of future volatility.

We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for

estimating the expected term of awards. The risk free interest rate is the rate for constant yield U.S.
Treasury securities with a term to maturity that is consistent with the expected term of the award.

Assumptions are reviewed each time there is a new grant and may be impacted by actual fluctuations
in our stock price, movements in market interest rates and options terms. The use of different assumptions
produces a different fair value for the options granted or outstanding, when accounted for as a liability

award, and impacts the amount of stock compensation expense recognized in our consolidated statement of
operations. The fair value of restricted stock awards are recognized based upon the fair value of our stock
on the date of the grant.

Prior to November 22, 2010, all of our outstanding stock options were classified as equity instruments,

with all stock-based compensation expense measured on the date of grant and recognized over the vesting
period, if any. On November 22, 2010, we changed our method of accounting for outstanding stock options,
reclassifying all outstanding stock options from equity to liability instruments. This change was made as a
result of purchasing shares from certain of our employees to assist them in the exercise of outstanding
options of our Class A common stock. As a result, at December 31, 2010, we measured and recognized the
fair value of the liability associated with our outstanding stock options using the intrinsic value method.

Income Taxes

We account for income taxes using the asset and liability approach for financial accounting and
reporting. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide
a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income
tax benefit in the future does not meet the more likely than not criteria for recognition.

We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax

position only after determining that the relevant tax authority would more likely than not sustain the
position following an audit. For tax positions meeting the more likely than not threshold, the amount
recognized in the financial statements is the benefit that has a greater than 50 percent likelihood of being
realized upon ultimate settlement with the relevant tax authority.

We have evaluated all tax positions for which the statute of limitations remained open, and we believe that
the material positions taken would more likely than not be sustained by examination. Therefore, at December 31,
2011, we had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain
tax positions. When necessary, we include interest assessed by taxing authorities in “Interest expense” and
penalties related to income taxes in “Other expense” on our consolidated statement of operations.

Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue

Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated
future net revenues. While the SEC has recently adopted rules which allow us to disclose proved, probable
and possible reserves, we have elected to present only proved reserves in this report. The SEC’s revised
rules define proved reserves as the 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. Our
engineers and technical staff must make many subjective assumptions based on their professional judgment
in developing reserves estimates. Reserves estimates are updated at least annually and consider recent
production levels and other technical information about each well. Estimating oil and natural gas reserves is
complex and is not exact because of the numerous uncertainties inherent in the process. The process relies
on interpretations of available geological, geophysical, petrophysical, engineering and production data. The
extent, quality and reliability of both the data and the associated interpretations can vary. The process also

requires certain economic assumptions, including, but not limited to, oil and natural gas prices, revenues,
development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil
and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of
recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are
generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant
variance could materially and adversely affect our future reserves estimates, financial position, results of
operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such
revisions are significant, they could significantly affect future amortization of capitalized costs and result in
impairment of assets that may be material.

Recent Accounting Pronouncements

Balance Sheet. In December 2011, the FASB issued Accounting Standards Update, or ASU, 2011-11,
Balance Sheet. The requirements amend the disclosure requirements to offsetting in Accounting Standards
Codification, or ASC, 210-20-50. The amendments require enhanced disclosures by requiring improved
information about financial instruments and derivative instruments that are either (1) offset in accordance
with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting agreement or
similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or
ASC 815-10-45. The adoption of ASU 2011-11 is not expected to have a material effect on our consolidated
financial statements, but may require certain additional disclosures. The amendments in ASU 2011-11 are to
be applied for annual reporting periods beginning on or after January 1, 2013 and are to be applied
retrospectively for all reporting periods presented.

Fair Value. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair

Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-04 amends ASC
820, Fair Value Measurements, providing a consistent definition and measurement of fair value, as well as
similar disclosure requirements between GAAP and International Financial Reporting Standards. ASU
2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value
measurements and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value
measurements. The adoption of ASU 2011-04 is not expected to have a material impact on our consolidated
financial statements, but may require certain additional disclosures. The amendments in ASU 2011-04 are to
be applied prospectively. For public entities, the amendments are effective during interim and annual
periods beginning after December 15, 2011.

In January 2010, the FASB issued authoritative guidance to update certain disclosure requirements and

added two new disclosure requirements related to fair value measurements. The guidance requires a gross
presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of
significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new
disclosures are required for all companies that are required to provide disclosures about recurring and
non-recurring fair value measurements, and are effective the first interim or annual reporting period
beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward
information, which is required for annual reporting periods beginning after December 15, 2010 and for
interim reporting periods within those years. We adopted the first portion of this guidance beginning
January 1, 2010 and the remaining portions beginning January 1, 2011. The adoption of this new guidance
did not have a significant impact on our financial position, results of operations or cash flows.

Oil and Natural Gas Reserves Reporting Requirements. In January 2009, the SEC issued The

Modernization of Oil and Gas Reporting, Final Rule. In January 2010, the Financial Accounting Standards
Board, or FASB, amended Topic 932, Extractive Activities — Oil and Gas to align with this rule. The

changes are designed to modernize and update the oil and natural gas disclosure requirements to align them
with current practices and changes in technology. The new rules made a number of important changes
including the following: (i) expanded the definition of oil and natural gas producing activities to include the
extraction of saleable hydrocarbons from oil sands, shale, coalbeds or other nonrenewable natural resources,
(ii) amended the required price for estimating economic quantities for year-end reserves reporting to be the
unweighted, arithmetic average of the first-day-of-the-month price for each month within the previous
12-month period, rather than the year-end price and (iii) permitted proved reserves to be claimed beyond
those development spacing areas that are immediately adjacent to developed spacing areas if it can be
established with reasonable certainty that these reserves are economically producible. At December 31,
2009, we adopted the provisions of this new rule, and we have applied this new guidance for the reserves
estimates shown for December 31, 2011, 2010 and 2009 included herein.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

We are exposed to a variety of market risks including commodity price risk, interest rate risk and
counterparty and customer risk. We address these risks through a program of risk management including the
use of derivative financial instruments.

Commodity price exposure. We are exposed to market risk as the prices of oil and natural gas fluctuate
as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these
market fluctuations, we have entered into derivative financial instruments in the past and expect to enter
into derivative financial instruments in the future to cover a significant portion of our future production.

We use costless (or zero-cost) collars to manage risks related to changes in oil and natural gas prices.
A costless collar provides us with downside price protection through the purchase of a put option which is
financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the
put option, this arrangement is initially “costless” to us.

We record all derivative financial instruments at fair value. The fair value of our derivative financial

instruments is determined using purchase and sale information available for similarly traded securities.
Comerica Bank is the single counterparty for all of our derivative instruments. We have evaluated the credit
standing of Comerica Bank in determining the fair value of our derivative financial instruments.

At December 31, 2011, 2010 and 2009, we used costless collar options to reduce the volatility of

natural gas prices on a significant portion of our future expected natural gas production. For each
calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these
transactions is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery
month corresponding to the calculation period’s calendar month for the last day of that contract period.
When the settlement price is below the price floor established by these collars, we receive from Comerica
Bank, as counterparty, an amount equal to the difference between the settlement price and the price floor
multiplied by the contract natural gas volume. When the settlement price is above the price ceiling
established by these collars, we pay to Comerica, as counterparty, an amount equal to the difference
between the settlement price and the price ceiling multiplied by the contract natural gas volume.

The following is a summary of our open natural gas costless collar contracts at February 29, 2012.

Commodity

Natural Gas
Natural Gas
Natural Gas

Total

Calculation Period

Notional Quantity

Price Floor

Price
Ceiling

07/01/2011 — 12/31/2012
07/01/2011 — 07/31/2013
01/01/2012 — 12/31/2012

(MMBtu/month)
300,000
150,000
150,000

($/MMBtu)
4.50
4.50
4.25

($/MMBtu)
5.60
5.75
6.17

Fair Value
of Asset

(thousands)
$ 4,948
3,584
2,120

$10,652

All of our existing natural gas derivative contracts will expire at varying times during 2012 and 2013.

Between November 2011 and February 2012, we entered into various costless collar transactions to
mitigate our exposure to oil price volatility for the first time. For each calculation period, the specified price
for determining the realized gain or loss to us pursuant to any of these oil hedging transactions is the
arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for
the first nearby month corresponding to the calculation period’s calendar month. When the settlement price
is below the price floor established by these collars, we receive from Comerica Bank, as counterparty, an
amount equal to the difference between the settlement price and the price floor multiplied by the contract oil
volume hedged. When the settlement price is above the price ceiling established by these collars, we pay
Comerica Bank, as counterparty, an amount equal to the difference between the settlement price and the
price ceiling multiplied by the contract oil volume hedged.

The following table is a summary of our open oil costless collar contracts at February 29, 2012.

Commodity

Calculation Period

Notional Quantity

Price Floor

Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil

Total

12/01/2011 — 12/31/2012
01/01/2012 — 12/31/2012
01/01/2012 — 12/31/2012
02/01/2012 — 06/30/2012
04/01/2012 — 12/31/2012
04/01/2012 — 03/31/2013
07/01/2012 — 12/31/2012
07/01/2012 — 12/31/2012
01/01/2013 — 12/31/2013
01/01/2013 — 12/31/2013
01/01/2013 — 12/31/2013
01/01/2013 — 12/31/2013
01/01/2013 — 06/30/2014
01/01/2013 — 06/30/2014

(Bbls/month)
20,000
10,000
10,000
20,000
20,000
20,000
20,000
20,000
20,000
20,000
20,000
20,000
8,000
12,000

($/Bbl)
90.00
90.00
90.00
90.00
90.00
90.00
90.00
95.00
85.00
90.00
85.00
85.00
90.00
90.00

Price
Ceiling

Fair Value
of Liability

($/Bbl)
104.20
108.00
109.50
113.75
111.00
110.00
111.90
116.00
102.25
115.00
110.40
108.80
114.00
115.50

(thousands)
$ (1,475)
(526)
(455)
(150)
(762)
(1,117)
(509)
(165)
(2,056)
(330)
(1,102)
(1,231)
(121)
(71)

$(10,070)

All of our existing oil derivative contracts will expire at varying times during 2012, 2013 and 2014.

Effect of Recent Derivatives Legislation

On July 21, 2010, President Obama signed into law the Dodd-Frank Act, which is intended to

modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things,
sets forth the new framework for regulating certain derivative products including the commodity hedges of
the type used by us, but many aspects of this law are subject to further rulemaking and will take effect over
several years. As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability

or willingness to continue entering into and maintaining such commodity hedges and the terms thereof.
Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the
possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into
and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation
of position limits and additional regulatory requirements on our derivative arrangements, which could
include new margin, reporting and clearing requirements. In addition, this legislation could have a
substantial impact on our counterparties and may increase the cost of our derivative arrangements in the
future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse
Impact on Our Ability to Hedge Risks Associated with Our Business.”

Interest rate risk. We do not use interest rate derivatives to alter interest rate exposure in an attempt to
reduce interest rate expense on existing debt since we borrowed under our existing credit agreement for the first
time in December 2010 and had $113.0 million in revolving borrowings outstanding at December 31, 2011 under
our amended and restated credit agreement at an interest rate of approximately 5.3% per annum. In addition to
our revolving borrowings, in May 2011, we borrowed $25.0 million in a term loan pursuant to the credit
agreement. The term loan was refinanced through revolving borrowings in December 2011 under our amended
and restated credit agreement. At March 30, 2012, we had $15.0 million in revolving debt outstanding under our
credit agreement at an interest rate of 2.0% per annum. If we incur additional indebtedness in the future and at
higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify
interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own

partial interest in the wells we operate. These entities participate in our wells primarily based on their
ownership in leases on which we wish to drill. We have limited ability to control participation in our wells.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with several
significant customers. The inability or failure of our significant customers to meet their obligations to us or
their insolvency or liquidation may adversely affect our financial position, results of operations and cash
flows. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of
nonperformance by counterparties.

While we do not require our customers to post collateral and we do not have a formal process in place to
evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the
counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we
deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating,
latest financial information and, in the case of a customer with which we have receivables, its historical payment
record, the financial ability of the customer’s parent company to make payment if the customer cannot and
undertaking the due diligence necessary to determine credit terms and credit limits. The counterparty on our
derivative instruments currently in place is Comerica Bank and we are likely to enter into any future derivative
instruments with Comerica Bank or one of the other lenders party to the credit agreement.

Impact of Inflation. Inflation in the United States has been relatively low in recent years and did not
have a material impact on our results of operations for the years ended December 31, 2011, 2010 and 2009.
Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the
United States economy and we tend to specifically experience inflationary pressure on the cost of oilfield
services and equipment with increases in oil and natural gas prices and with increases in drilling activity in
our areas of operations, including the Eagle Ford shale and Haynesville shale plays. See “Business —
General.” See also “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion
Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel,

Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within
Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition,
Results of Operations and Cash Flows.”

Item 8.

Financial Statements and Supplementary Data.

Our financial statements appear at the end of this Form 10-K. Please see the index to the financial

statements in Item 15.

Item 9.

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

Not applicable.

Item 9A. Controls and Procedures.

This Annual Report does not include a report of management’s assessment regarding internal control
over financial reporting or an attestation report of the company’s registered public accounting firm due to a
transition period established by rules of the SEC for newly public companies.

Prior to the completion of our initial public offering, we maintained limited accounting personnel to

perform our accounting processes and limited supervisory resources with which to address our internal
control over financial reporting. In connection with our audit for the year ended December 31, 2011, our
independent registered public accountants identified and communicated a material weakness related to
accounting for stock compensation expense. A material weakness is a control deficiency, or a combination
of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility
that a material misstatement of our annual and interim financial statements will not be prevented or detected
and corrected on a timely basis.

We have begun the process of evaluating our internal control over financial reporting and expect to put

into place new accounting processes and control procedures to address the weakness described above,
including the hiring of outside consultants to review significant or complex accounting issues and
calculations, the implementation of a more formalized closing process, the formation of a disclosure
committee and the hiring of additional personnel. We cannot predict the outcome of this process at this
time. We will be required to make our first assessment of our internal control over financial reporting at
December 31, 2012.

We became a public company on February 1, 2012 in connection with the completion of our initial
public offering. Prior to that date, we were a private company and were not required to file or submit reports
under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and maintained disclosure
controls and procedures in accordance with being a private company. As of the end of the period covered by
this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rule 13a-15(e)) under the Exchange Act was performed under the supervision and
with the participation of our management, including our Chief Executive Officer and Chief Financial
Officer. Based upon this evaluation, as of the end of the period covered by this report, our Chief Executive
Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were not
effective because we were not yet a public company and, therefore, had not yet established formal
disclosure controls and procedures and because the material weakness described above relating to our
internal control over financial reporting was identified.

Item 9B. Other Information.

None.

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 promulgated under the
Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report.

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 promulgated under the
Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters.

Certain information regarding securities authorized for issuance under our equity compensation plans

is included under the caption “Equity Compensation Plan Information” in Part II, Item 5, above, of this
Annual Report and is incorporated by reference herein. Other 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 promulgated under the Exchange Act not later than 120 days after the end of
the fiscal year covered by this Annual Report.

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 promulgated under the
Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.

Item 14.

Principal Accounting 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 promulgated under the
Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.

Item 15.

Exhibits and Financial Statement Schedules.

The following documents are filed as part of this report:

PART IV

1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting

Firm, Consolidated Balance Sheets as of December 31, 2011 and 2010, Consolidated Statements of
Operations for the years ended December 31, 2011, 2010 and 2009, Consolidated Statements of
Shareholders’ Equity for the years ended December 31, 2011, 2010 and 2009 and Consolidated Statements
of Cash Flows for the years ended December 31, 2011, 2010 and 2009.

2. Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index

accompanying this report.

Exhibit
Number

EXHIBIT INDEX

Description

1.1

2.1

3.1

3.2

3.3

3.4

3.5

3.6

3.7

3.8

4.1

10.1

10.2

Underwriting Agreement (incorporated by reference to Exhibit 1.1 to the Current Report on
Form 8-K filed on February 7, 2012).

Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC
Energy Company), Matador Holdco, Inc. (now known as Matador Resources Company) and Matador
Merger Co., dated August 8, 2011 (incorporated by reference to Exhibit 2.1 to our Registration
Statement on Form S-1 filed on August 12, 2011).

Certificate of Formation of Matador Resources Company (formerly known as Matador Holdco, Inc.)
(incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 filed on
August 12, 2011).

Certificate of Amendment to Certificate of Formation of Matador Resources Company (formerly
known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.2 to our Registration
Statement on Form S-1 filed on August 12, 2011).

Certificate of Amendment to Certificate of Formation of Matador Resources Company (formerly
known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.3 to our Registration
Statement on Form S-1 filed on August 12, 2011).

Certificate of Merger between Matador Resources Company (now known as MRC Energy Company)
and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration Statement on
Form S-1 filed on August 12, 2011).

Bylaws of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by
reference to Exhibit 3.5 to our Registration Statement on Form S-1 filed on August 12, 2011).

Amendment to the Bylaws of Matador Resources Company (formerly known as Matador Holdco,
Inc.) (incorporated by reference to Exhibit 3.6 to our Registration Statement on Form S-1 filed on
August 12, 2011).

Amended and Restated Certificate of Formation of Matador Resources Company (formerly known as
Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K
filed on February 13, 2012).

Amended and Restated Bylaws of Matador Resources Company (formerly known as Matador
Holdco, Inc.) (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on
February 13, 2012).

Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to
our Registration Statement on Form S-1 filed on January 19, 2012).

Amended and Restated Credit Agreement, dated at May 19, 2011, by and among Matador Resources
Company (now known as MRC Energy Company), Comerica Bank and the Lenders signatory thereto
(incorporated by reference to Exhibit 10.1 to Amendment No. 1 to our Registration Statement on
Form S-1 filed on November 14, 2011).

Pledge and Security Agreement, by and between Matador Resources Company (formerly known as
Matador Holdco, Inc.) and Comerica Bank, dated at August 9, 2011 (incorporated by reference to
Exhibit 10.2 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14,
2011).

10.3†

Employment Agreement between Matador Resources Company (formerly known as Matador
Holdco, Inc.) and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1
to our Registration Statement on Form S-1 filed on November 14, 2011).

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†

10.17†

10.18†

Employment Agreement between Matador Resources Company (formerly known as Matador Holdco,
Inc.) and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to our
Registration Statement on Form S-1 filed on November 14, 2011).

Employment Agreement between Matador Resources Company (formerly known as Matador Holdco,
Inc.) and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to our
Registration Statement on Form S-1 filed on November 14, 2011).

Employment Agreement between Matador Resources Company (formerly known as Matador Holdco,
Inc.) and Bradley M. Robinson (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to
our Registration Statement on Form S-1 filed on November 14, 2011).

Independent Contractor Agreement between Matador Resources Company (formerly known as
Matador Holdco, Inc.) and David F. Nicklin (incorporated by reference to Exhibit 10.7 to
Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company (formerly
known as Matador Holdco, Inc.) and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to
Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company (formerly
known as Matador Holdco, Inc.) and David E. Lancaster (incorporated by reference to Exhibit 10.9 to
Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company (formerly
known as Matador Holdco, Inc.) and Matthew Hairford (incorporated by reference to Exhibit 10.10
to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company (formerly
known as Matador Holdco, Inc.) and Bradley M. Robinson (incorporated by reference to Exhibit
10.11 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company (formerly
known as Matador Holdco, Inc.) and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12
to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company (formerly
known as Matador Holdco, Inc.) and David E. Lancaster (incorporated by reference to Exhibit 10.13
to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company (formerly
known as Matador Holdco, Inc.) and Matthew Hairford (incorporated by reference to Exhibit 10.14
to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company (formerly
known as Matador Holdco, Inc.) and Bradley M. Robinson (incorporated by reference to Exhibit
10.15 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011).

First Amendment to the Independent Contractor Agreement between Matador Resources Company
(formerly known as Matador Holdco, Inc.) and David F. Nicklin (incorporated by reference to
Exhibit 10.16 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30,
2011).

2012 Long-Term Incentive Plan of Matador Resources Company (formerly known as Matador
Holdco, Inc.) (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration
Statement on Form S-1 filed on December 30, 2011).

Matador Resources Company (formerly known as Matador Holdco, Inc.) Annual Incentive Plan for
Management and Key Employees (incorporated by reference to Exhibit 10.18 to Amendment No. 2
to our Registration Statement on Form S-1 filed on December 30, 2011).

10.19†

10.20†

10.21†

10.22†

10.23†

10.24†

10.25†

10.26†

10.27†

10.28

10.29

10.30

10.31

Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated October 23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to our
Registration Statement on Form S-1 filed on November 14, 2011).

First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003
Stock and Incentive Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to
Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003
Stock and Incentive Plan, dated February 3, 2005 incorporated by reference to Exhibit 10.17 to
Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003
Stock and Incentive Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to
Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003
Stock and Incentive Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to
Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003
Stock and Incentive Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to
Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003
Stock and Incentive Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to
Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003
Stock and Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26 to
Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011).

Form of Indemnification Agreement between Matador Resources Company (formerly known as
Matador Holdco, Inc.) and each of the directors and executive officers thereof (incorporated by
reference to Exhibit 10.22 to Amendment No. 1 to our Registration Statement on Form S-1 filed on
November 14, 2011).

Participation Agreement, by and among MRC Rockies Company, Matador Resources Company (now
known as MRC Energy Company), Matador Production Company, Roxanna Rocky Mountains, LLC,
Roxanna Oil, Inc., Alliance Capital Real Estate, Inc. and AllianceBernstein L.P., dated at May 14,
2010 (incorporated by reference to Exhibit 10.23 to Amendment No. 1 to our Registration Statement
on Form S-1 filed on November 14, 2011).

Assignment, Bill of Sale and Conveyance, by and among Winn Exploration Co., Inc., Pinion
Exploration, LLP, McDay Oil & Gas, Inc. and Matador Resources Company (now known as MRC
Energy Company), dated effective at December 1, 2010 (incorporated by reference to Exhibit 10.24
to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).

Purchase, Sale and Participation Agreement, by and between Matador Resources Company (now
known as MRC Energy Company) and Orca ICI Development, JV, dated at May 16, 2011
(incorporated by reference to Exhibit 10.25 to Amendment No. 1 to our Registration Statement on
Form S-1 filed on November 14, 2011).

Second Amended and Restated Credit Agreement dated as of December 30, 2011, by and among
MRC Energy Company, Comerica Bank and the Lenders party thereto from time to time
(incorporated by reference to Exhibit 10.31 to Amendment No. 3 to our Registration Statement on
Form S-1 filed on January 13, 2012).

10.32

10.33

10.34†

10.35†

10.36†

10.37†

10.38†

10.39†

10.40†

21.1

23.1

31.1

31.2

32.1

32.2

Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company,
Longwood Gathering and Disposal Systems GP, Inc. and Comerica Bank, dated as of December 30,
2011 (incorporated by reference to Exhibit 10.32 to Amendment No. 3 to our Registration Statement
on Form S-1 filed on January 13, 2012).

Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian
Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and
Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources
Company (formerly known as Matador Holdco, Inc.) and Comerica Bank, dated at December 30,
2011 (incorporated by reference to Exhibit 10.33 to Amendment No. 3 to our Registration Statement
on Form S-1 filed on January 13, 2012).

Employment Agreement between Matador Resources Company (formerly known as Matador Holdco,
Inc.) and Wade Massad (incorporated by reference to Exhibit 10.34 to Amendment No. 3 to our
Registration Statement on Form S-1 filed on January 13, 2012).

Nonqualified Stock Option Agreement, dated February 1, 2012, by and between Matador Resources
Company and Wade Massad (incorporated by reference to Exhibit 10.1 to the Current Report on
Form 8-K filed on February 7, 2012).

Form of Non-Qualified Stock Option Agreement granted pursuant to the Matador Resources
Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (filed herewith).

Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company
(now known as MRC Energy Company) 2003 Stock and Incentive Plan (filed herewith).

Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company
(formerly known as Matador Holdco, Inc.) 2012 Long-Term Incentive Plan (filed herewith).

Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company
(formerly known as Matador Holdco, Inc.) 2012 Long-Term Incentive Plan (filed herewith).

Form of Restricted Stock Award Agreement relating to the Matador Resources Company (formerly
known as Matador Holdco, Inc.) 2012 Long-Term Incentive Plan (filed herewith).

List of Subsidiaries of Matador Resources Company (formerly known as Matador Holdco, Inc.)
(incorporated by reference to Exhibit 21.1 to our Registration Statement on Form S-1 filed on August
12, 2011).

Consent of Netherland, Sewell & Associates, Inc. (filed herewith).

Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of
2002 (filed herewith).

Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of
2002 (filed herewith).

Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

99.1

Audit report of Netherland, Sewell & Associates, Inc. (filed herewith).

†

Indicates a management contract or compensatory plan or arrangement.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

MATADOR RESOURCES COMPANY

April 2, 2012

By:

/s/ Joseph Wm. Foran

Joseph Wm. Foran
Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below

by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

Date

/s/

Joseph Wm. Foran

/s/ David E. Lancaster

David E. Lancaster

/s/ Kathryn L. Wayne

Kathryn L. Wayne

/s/ Charles L. Gummer

Charles L. Gummer

/s/ Stephen A. Holditch

Stephen A. Holditch

/s/ David M. Laney

David M. Laney

/s/ Gregory E. Mitchell

Gregory E. Mitchell

/s/ Steven W. Ohnimus

Steven W. Ohnimus

/s/ Michael C. Ryan

Michael C. Ryan

/s/ Margaret B. Shannon

Margaret B. Shannon

Chairman, President and Chief
Executive Officer (Principal
Executive Officer)

Executive Vice President, Chief
Operating Officer and Chief
Financial Officer
(Principal Financial Officer)

Controller and Treasurer
(Principal Accounting Officer)

Director

April 2, 2012

Exhibit 31.1

I, Joseph Wm. Foran, certify that:

CERTIFICATION

1. I have reviewed this annual report on Form 10-K of Matador Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit

to state a material fact necessary to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and

procedures to be designed under our supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;

b. Paragraph omitted pursuant to Exchange Act Rule 13a-14(a);

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented

in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of
the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting
that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in
the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation

of internal control over financial reporting, to the registrant’s auditors and the audit committee of the
registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely affect the registrant’s ability
to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a

significant role in the registrant’s internal control over financial reporting.

April 2, 2012

/s/ Joseph Wm. Foran

Joseph Wm. Foran
Chairman, President and Chief Executive Officer
(Principal Executive Officer)

Exhibit 31.2

I, David E. Lancaster, certify that: