SM Energy Company Annual Report 2012

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FY2012 Annual Report · SM Energy Company

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D R I V E N

P E R F O R M A N C

I O

F O L

E D P O R T

F O C U S

C A P T U R E

S O U R C

E A R L Y R E

T U R N S

H I G H R E

Oil & Gas Production

(MMCFE per day)

Oil & Gas Production Per Share

(MCFE)

Net Cash Provided by

Operating Activities

($ millions)

600

500

400

300

200

100

4.00

3.00

2.00

1.00

1000

800

600

400

200

Proved Reserves

Proved Reserves Per Share

(BCFE)

2000

1500

1000

500

(MCFE)

Stockholders’ Equity

($ millions)

Year-End Closing Stock Price

($ per share)

1500

1200

900

600

300

FINANCIAL HIGHLIGHTS

2012

2011

2010

2009

2008

(In thousands except production, proved reserves, price data, and per share amounts)

Income Statement Data

Oil and gas production revenues

$ 1,477,734

$ 1,311,685

$ 859,753

$ 756,601

$ 1,158,304

Divestiture activity and other

27,368

291,633

233,081

75,600

142,997

Total operating revenues

$ 1,505,102

$ 1,603,318

$ 1,092,834

$ 832,201

$ 1,301,301

Net income (loss)

$ (54,249)

$ 215,416

$ 196,837

$ (99,370)

87,348

Diluted earnings (loss) per share

(0.83)

3.19

3.04

$ (1.59)

Cash dividends declared and paid per share

0.10

1.38

0.10

Diluted weighted average common

shares outstanding

65,138

67,564

64,689

62,457

63,133

Balance Sheet Data

Working capital

Total assets

Long-term debt

Stockholders’ equity

Average Net Daily Production

Gas (MMcf)

Oil (MBbls)

NGL (MBbls)

MMCFE (6:1)

Average Sales Price, including

derivative cash settlements

Gas (per Mcf)

Oil (per Bbl)

NGL (per Bbl)

Reserves

Gas (MMcf)

Oil (MBbls)

NGL (MBbls)

MMCFE (6:1)

$ (200,982)

$ (42,601)

$ (227,408)

$ (87,625)

15,193

4,199,529

1,440,000

1,414,466

3,798,980

2,744,321

2,360,936

2,697,247

985,069

323,673

1,462,940

1,218,526

454,902

973,570

558,713

1,162,509

328.0

28.3

16.7

598.2

274.8

22.1

9.6

465.0

196.9

17.4

—

301.4

194.8

17.3

—

298.8

204.7

18.1

—

313.1

3.48

83.52

38.90

4.80

78.89

47.90

6.05

66.85

—

5.59

56.74

—

8.79

75.59

—

833,406

92,230

62,296

664,052

71,707

27,490

640,047

57,412

—

449,545

53,784

—

557,366

51,363

—

1,760,569

1,259,232

984,519

772,249

865,544

TO OUR SHAREHOLDERS

At SM Energy, we approach the E&P
business with a set of simple, yet powerful
core business disciplines: People Strategy;
Operational Excellence; Strong Balance Sheet;
and Capital Program Flexibility. These are the
foundations upon which our performance-
driven culture is built. In 2012, we applied
these principles by executing on our develop-
ment programs in the Eagle Ford shale and
Bakken/Three Forks plays, driving record
production and proved reserves. Additionally,
we applied these disciplines to our strategy of
early resource capture by bringing forward new
venture plays that we expect to drive future
growth, to provide high rates of return projects,
and allow the Company to continuously
upgrade its asset portfolio.

2012 Results

We increased our year-end proved reserves

by 40% to a record 1.76 TCFE in 2012. At
year end, 57% of our proved reserve base was
proved developed and was comprised of 53%
liquids. Oil and NGLs now comprise the
majority of our proved reserves, which is an
important milestone for the Company. It
is the ultimate indicator of our success in
developing high-return liquid weighted
programs in recent years, and it represents our
employees’ hard work. We added 900 BCFE
through the drill bit, primarily in our Eagle
Ford shale program, which we transitioned
from delineation to development during
2012. Drilling finding and development costs,
excluding revisions, decreased from the prior
year to a multi-year low of $1.74 per MCFE.
Our decreased finding and development costs
are a testament to the quality and repeatability
inherent in our upgraded portfolio. Drilling
reserve replacement, excluding revisions,
increased in 2012 to 411%, an impressive feat
considering our record production for the
year. As a result, we have lengthened our
proved reserves-to-production ratio (R/P).
In all, 2012 was a great year with regard to
proved reserves, as we reported strong reserve
metrics and showed an increased depth to our
drilling portfolio.

As a management team, our goal is to continually

add compelling prospects to our inventory. Having a

deep project inventory allows us to high grade our

projects and deploy capital in programs with the

highest rates of return.

— ANTHONY J. BEST
Chief Executive Officer

Production growth for the year was again

robust. We reported production growth of
29% over the prior year to an annual record of
219 BCFE. Additionally, we finished the year
strong with a quarterly production record of
61 BCFE in the fourth quarter of 2012. The
main drivers of production growth were our
Eagle Ford shale and Bakken/Three Forks
programs. These record production levels
resulted in the Company reporting increased
oil, gas, and NGL production revenue in 2012
of $1.5 billion, compared to $1.3 billion in
2011, despite significant downward pressure
on natural gas and NGL prices during the year.
We reported a net loss of $54 million for the
year, which was driven primarily by a non-cash
impairment on proved properties of $209
million. We posted strong cash flow from
operations of approximately $922 million in
2012, a 20% increase from the prior year,
driven largely by increased production volumes.
From a liquidity perspective, 2012 was

also a successful year for the Company. We
simplified the balance sheet with the redemption
of our outstanding senior convertible notes
early in the year, which was partially funded
by another successful high-yield note offering.
We are now a known and respected issuer in
the high-yield debt investment community,
which will benefit us going forward. The
borrowing base on our revolving credit facility
was increased in August of 2012 on the strength
of proved developed reserve growth to $1.55
billion, up from the prior year level of $1.3
billion. We exited the year with a debt-to-trailing
twelve month EBITDAX* ratio of 1.4 times,
and debt to book capital ratio of 50%. We have
significant credit available to us to fund our
capital program and as of December 31, 2013,
we had approximately $660 million of unused
commitments on our revolving credit facility.

Operations

Operationally, we executed on our core

plays in 2012, with the main focus of activity
on our two development programs in the
Eagle Ford shale and Bakken/Three Forks
formations. During the year, we also increased

*EBITDAX is a non-GAAP financial measure. Please refer to the definition
and reconciliation of EBITDAX to its related GAAP measure on page 87 of
the attached Form 10-K.

As we move to 2013, our drilling program is focused

entirely on liquids-rich projects that meet or exceed our

economic drilling hurdle. Approximately 90% of our

drilling and completion capital will be deployed in three

core areas — the Eagle Ford

shale, Bakken/Three Forks,

and Permian Basin.

— JAVAN D. OTTOSON

President and

Chief Operating Officer

We are now a known and respected issuer in the

high-yield debt investment community, which will

benefit us going forward.

— A. WADE PURSELL

Executive Vice President and

Chief Financial Officer

activity in our newer Mississippian lime
delineation program in the Permian Basin.
In our Eagle Ford program, we operate
approximately 145,000 of our total 191,000
net acres in the play. We saw tremendous
production growth in both our operated and
non-operated programs during 2012 with
combined annual production growing to 111
BCFE, a 67% increase from 2011. Additionally,
annual production in the combined program
has increased impressively by more than 529%
from 2010. In 2012, the operated portion of
our program primarily focused on increasing
the efficiency of our operations and determining
the ultimate development spacing on our
acreage. Throughout the year, we focused on
multi-well pad drilling and improved drilling
efficiencies, which decreases surface impact and
overall well costs. In addition to the savings we
received from multi-well pad drilling, we also
realized reduced stimulation costs that further
decreased overall well costs. By the end of
the year, we had completed our remaining
down-spacing pilots in the play, which support
tighter spacing in the northwestern portion
of our acreage position, thereby increasing the
number of potential drilling locations. At
year-end 2012, we had approximately 1,500
drilling locations with an associated 5.8 TCFE
of undrilled resource potential, an increase of
approximately 500 BCFE from 2011. As we
look to 2013, we will continue to refine our
development of the play, primarily by focusing
on greater drilling and completion efficiencies.
In our Bakken/Three Forks program in
the Williston Basin, we continued development
of our Gooseneck and Raven/Bear Den
prospects in North Dakota. Production in this
program grew substantially during 2012, with
year over year production growth of 92%.
During the year, we focused our efforts on
increasing efficiencies through various efforts,
including multi-well pad drilling.

In our Permian Basin program, we
ramped up activity significantly during the
year in the Mississippian limestone in the
Northern Midland Basin. Our program in this
play has moved from testing to delineation,
as we continue to test the aerial extent of our
acreage. Our focus for the year was to improve
our understanding of the play and strengthen

project economics through improved drilling
results and decreased costs. In addition to
our Mississippian program, we also expanded
an exploratory program in the Midland Basin
focused on various oily shale targets with
almost 30,000 net acres of new leasehold. We
will continue testing in 2013 and if successful,
we hope to add meaningful oily inventory to
our portfolio.

New Ventures

While execution on our current core plays
is of upmost importance, finding the next leg
of growth for the Company is of equal impor-
tance. As a management team, our goal is to
continually add compelling prospects to our
inventory. Having a deep project inventory
allows us to high grade our projects and deploy
capital in programs with the highest rates of
return. Our new ventures program focuses on
finding new growth opportunities for the
Company, both in the areas where we currently
operate and also in basins where we don’t
currently have a presence. We expect that
our new venture efforts will contribute to our
future success by further expanding our
drilling inventory of high-return drilling
programs. Our goal is to advance two of those
exploration ideas in 2013 as we test various
targets in the Permian Basin and East Texas,
where we have added almost 130,000 net
acres of new leasehold.

In retrospect, 2012 was a very successful

year for the Company. We had record produc-
tion, record year-end proved reserves, a
significant increase to liquids proved reserve
volumes, and over 180,000 acres of new
prospective leasehold. We reduced finding and
development costs, and increased our reserve
replacement ratio to a multi-year high. We
executed on our core development programs,
and brought forward new projects to drive
future growth for the Company.

Looking To 2013

As we move to 2013, our drilling program
is focused entirely on liquids-rich projects that
meet or exceed our economic drilling hurdle.
Approximately 90% of our drilling and

SM ENERGY AREAS OF OPERATION

completion capital will be deployed in three core
areas — the Eagle Ford shale, Bakken/Three
Forks, and Permian Basin. We have projected
that this focused program will provide 20%
production growth for the Company in 2013.
We published long-term growth objectives for
the first time last year by providing production
growth projections of 15% in 2014 and 2015.
It has taken several years and significant effort
to create a compelling project inventory that
can provide significant longer term growth
for our investors. We are very excited about
where our Company is positioned today with
technical and operating teams that can execute
on a deep inventory of economic projects,
provide significant production growth, and
pursue new venture prospects, all while main-
taining a strong balance sheet. We are truly
excited about what the future holds for the
Company and its investors.

Anthony J. Best
Chief Executive Officer

Javan D. Ottoson
President and Chief Operating Officer

A. Wade Pursell
Executive Vice President and Chief Financial Officer

PA U L M . V E AT C H

On November 24, 2012, the SM Energy
family lost a valued leader, co-worker,
and friend with the passing of Paul Veatch.
Paul was a Senior Vice President and the
regional manager of our Mid-Continent
region. Over his years with SM Energy,
he successfully led two regional offices
and contributed greatly to the success of
the company. He was an example of the
best kind of people you can meet in our
business — intelligent but not arrogant,
sincere but full of good humor, hard-
working but involved in the lives of his
family members. It was a privilege to
know and work with Paul, and he will be
deeply missed.

OUR PEOPLE

(as of December 31, 2012)

Wanda Acree • Tonya Adam • Brady Adams • Susan Adamson • Judy Adamsson • James Adkins • Roslizah Ahmad • Rhonda Albright • Tina Allen
Jose Alvarez • Lincoln Anderson • Mark Andreason • Christopher Arnold • Debra Arroyo • Penny Ayers • Robert Bachman • Thomas Bagley
Bradley Baker • Cutler Bakke • Margarito Balcazar • Michael Barbula • Stella Bargas • Brianne Barkley • James Barnes • Jessica Baros
Tracy Bartholomew • Daniel Bassett • Jayme Bauman • Dana Baxter • Lauren Bean • Edward Beaumont • David Beers • Laura Beers • Melissa Beff
Erin Bell • Tina Benedict • Alan Bennett • Cynthia Bennett • William Bentley • Diane Bents • Frank Berry • Brandon Bertelsen • Tony Best
Samuel Bieber • Brandin Bignall • Roberta Bixhorn • Gary Bjerke • Kory Bjorgen • Jordan Blackburn • Carla Blair • Nathan Blu • Nicholas Bohrer
Mark Bondy • Shawna Bonini • Lewis Boothe • Grant Borer • Shawn Bose • Cristin Bracken • Gary Breitling • Linda Brewer • Levi Briese
Stephen Briggs • Alonzo Brinkerhoff • Luis Briseno • Chasity Broadbrooks • Cynthia Brogren • Gregory Brooks • Nancy Brostuen • Alyson Brown
Deborah Brown • Jared Brown • Leah Brumlow • Kristyn Bryan • Michael Bryant • Darren Buck • Jason Buckley • Willis Buckley • Rita Buress
Jacqueline Burgesser • Susan Burk • Donna Burkart • Karen Burns • Katharen Burns • Linda Burrow • William Burruss • Paul Button
Julio Cabrera • Debra Calhoun • Virginia Calhoun • Diane Cameron • Cade Campbell • Jed Campbell • Guadalupe Campos • Heather Cangemi
Bruce Carathers • Javier Cardenas • Roel Cardona • William Carignan • Nicholas Carlson • Randall Carlson • Tara Carnell • David Carrillo
Bartow Carroll • Darrell Carter • Vicki Cartledge • Robert Casey • Wilson Cash • Robert Caskey • Paul Castillo • Joanne Celentano
Melanie Chaffin • Jarrod Charlifue • Louis Chemin • Terri Chen • Karen Chism • Frank Chomout • Aubrey Christian • Avis Clark • Donald Clark
Leonard Clark • Cody Clickner • Carole Clingman • Amy Close • Mark Cody • Shanika Coleman • Mauro Collazo • Brent Collins • Kelly Collins
Anthony Cook • William Cooper • David Copeland • William Cowart • James Craig • Bruce Crain • Danielle Crane • Darcy Critchfield • Aaron Cross
Tina Crutchmer • Kerry Culbertson • Thomas Dahill • Lukas Dahmus • Jeffrey Damm • Adrian Davis • Benjamin Davis • Joseph Davis • Kelly Davis
Lonnie Davis • Ryan Davis • Aaron Day • Marilee Day • Arnab De • Carla Deangelis • Margo DeHaas • Daisy Delval • Michael Detrick
Marian Devasher • Jimmy Dew • Anna Di Iorio • Ricardo Diaz Jr • Jorge Diaz • Robin Diedrich • Murray Dighans • Debra Dinner
Ronald Divine • Clare Domingue • Jamie Donovan • Carolyn Doolittle • Alisha Dossett • Cal Dowhaniuk • Angelina Downing • Jeffrey Downing
William Downs • Robert Drake • Karla Drange • Deanna Duell • Amy Duncan • Mark Dunham • William Dunn • Kristal Duval • Joyce Eckardt
James Edwards • Sarah Edwards • Tanner Egan • Kevin Eide • Matthew Ellard • Patricia Ellington • Dustin Ellis • Robert Elrod • Teri Elrod
Wayne Engberg • James Erlandson • Rodrigo Escamilla • Claudia Escobar • Brent Evans • Tracy Fair • Ryan Fairfield • Michael Farr
Thomas Ferguson • Sandy Ferris • Olexandra Fields • Gary Fifer • Douglas Fiske • Margarito Flores Jr • Bobby Flores • Blain Flowers
Bryce Flowers • Roger Flowers • Samuel Fluckiger • David Flurry • Steven Focht • Dana Fox • Julie Fragnito • Debra Frazier • Will Frederick
Christopher French • Cam Friede • George Friesen • Paula Frisbee • Richard Fritz • Samuel Frydenlund • Eric Fugate • Jenice Fugere
Jeffrey Fulco • Jared Fuser • Ryan Garcia • Albert Garza Jr • Carlos Garza • Gayle Gaul • Katrina George • Bob Geries • Karun Ghimire
Kathryn Giansiracusa • Karen Gibbs • Amy Giles • Mac Gilger • Katie Gillmore • Jesse Gilman • Aric Glasser • Robert Gleeson • Jeremy Goett
Leonard Gonzales • Vicky Gonzales • Jose Gonzalez • Dianne Goodrich • Maria Gordon • Erin Graham • Donna Grant • Bryan Graves
Dan Gray • Julie Gray Daniel Green • David Greene Jr • Connie Greenlee • Angela Gregerson • Delitha Gregory • Thomas Grier
David Griffith • Lorena Griggs • Jack Griswold • Dennis Guenther • Gregory Gurley • Loy Hahn • Christopher Hall • David Hall • Gloria Hall
Rex Hansen • Angela Hanson • Vera Harris • Robert Hart • Dannet Harvey • Thomas Haugeberg • Eric Hauwert • Amber Hawkins • William Hearne
Thomas Hedegaard • Daniel Heggem • Stephanie Helmstaedter • Roxie Helstad • Meghan Hendershot • Andrew Hennes • Chris Henson
Shawn Heringer • Angel Hernandez • Randy Herr • Jerardo Herrera • Connie Heston • Donald Hill • Garth Hill • Kevin Hillyard • Greg Hilton
Ezequiel Hinojosa • Kevin Hinshaw • Mary Hirsch • Betty Hodge • Tina Hoefler • Cory Hoffman • Troy Hoffmann • Pamela Hornsby
Arlin Howles • Lorraine Huck • Donna Huddleston • Gary Hughes • Carrie Hunter • Christopher Hunter • Carmine Iadarola • Kathryn Jackson
Robert Jackson • Joey Jafek • Jeffery Jankoski • Liliana Jasso • Shannon Jeffries • Bridgett Jenefor • Richard Jenkins • Jette Jenks • Monica Jennings
Jenny Jensen • John Jensen • T Hutch Jobe • Deanna Johnson • Debra Johnson • Randy Johnson • Robin Johnson • Austin Johnsrud
Lisa Johnston • Brian Jones • Joel Jones • Roberta Jones • Brecken Joos • Damon Jordan • Francis Jordan • Kyle Jordison • Alley Juma
Mark Juma • Valeri Kaae • Patrick Kadel • Valerie Kanelopoulos • Rachel Kastelic • Aaron Kastner • Timothy Keating • Christopher Kelley
Patrick Kelly • Benjamin Kennedy • Jason Kent • Raymond Killpack • Wesley Kindel • Johnathan King • Kent King • Malcolm Kintzing
Carolyn Kircher • Jill Klein • David Klenk • Kimberly Kleven • Jeremy Kline • Stephen Knapp • Craig Knighten • Mark Knogge • Kenneth Knott
Janice Knotts • Candice Kohn • Brady Kolb • Eileen Kosakowski • Shellene Kraft • Alicia Kucharek • Ingrid Kuesel • Sarah Lacey • Joshua Lackey
Kendra LaFountain • Norma LaGuardia • Twyla Lance • Mark Landry • Jason Lara • Patricia Larremore • Dustin Larsen • Barbara Larson
Paul Larson • Michael Latimer • Sarah Lawson • Kathryn Leathers • James Lebeck • Mildred Leblanc • James Legare • Myron Leintz • Kaci Lenz
Gregory Leyendecker • Dennis Lindberg • Gregory Little • Leonel Lopez • Whitney Lott • Kory Lough • Ryan Lowden • Jeremy Loyd
Nathan Luoma • David Lustig • Dean Lutey • Mary Ellen Lutey • Robert Lynn • Candace Lyon • Patrick Lytle • Melissa Macune • Robyn Maez
Meghan Mahala • Jennifer Major • Luke Malsam • Joan Maner • Sarah Mann • Dustin Manuel • Nathan Markham • Deborah Markley
Jesse Martin • Joanna Martin • Jeffrey Martinez • Victoria Martinez • Michael Mataalii • Thomas Mathis • Randi Mauro • Donna McCann
Kem McCready • Stephanie McCutcheon • Danny McDonald • Monty McElveen • Derek McFarlane • Joseph McFerran • Michael McGoveran
LaKesha McGuire • John Mcleod • Kevin McMaster • Charles McNaney • Michael McNeely • Darren Meeks • Robbin Mekelburg • Brandy Mendez
Charles Mercer • Glenn Merritt • Mark Millard • Virginia Minturn • John Mitchell • Dee Mittler • Jamie Mitzo • Dustin Mo bley
Matthew Modjeski • Shane Mogensen • John Monark • Steven Moore • Shane Moran • Joshua Morel • Ruben Morris • Barry Morrison
Paul Morrison • Thomas Morrow • Bruce Mortenson • Matthew Morton • Daniel Moss • Donald Mueller • Mark Mueller • Teresa Muhic
Chad Mulliniks • Robert Munsch • Pamela Murillo • James Myers • Billy Neal • Justin Nelson • Rodney Nelson • Lehman Newton
Van-Tuyet Nguyen • Casey Nichols • John Nightengale • Matthew Nikkel • Jonathan Nix • Patrick Noon • Elmer Nordsven • Robert Norman
Lori O’Boyle • Steven O’Brien • Breanne Oakley • Ryan Okland • Dusty Orchard • Juan Orosco Jr • Samuel Osborne • Tiffany Osburn
Freddie Otis • Valen Ott • Jay Ottoson • Sylvia Padilla • Billie Ann Pagliasotti • Guadalupe Parham • Donna Parker • Vernon Parks • Randall Parpart
Susan Penner • Carlos Perez • Kelly Perrin • Adam Perry • Isaac Perry • Randy Pester • Karla Petty • Susan Piehl • Julie Pike • Elizabeth Poirier
Clayton Pollard • David Ponto • Wanda Pontz • Donald Poole • Charles Porter • Wesley Portra • Susan Potts • Orval Powell • Robert Prescott
Loren Prigan • Bonnie Pritchett • Leah Protz • Stephanie Pruett • Sandra Puettman • David Purcell • Matthew Purchase • Wade Pursell
Raul Ramos Jr • John Ramsey • Lanette Rasmusson • Patricia Rau • Sarah Ray • Carolyn Reagin • Susan Reams • Warren Redd • Jeff Reeves
Roger Rehbein • Jennifer Rehm • James Reichenbach • Daniel Rex • Gayle Richardson • Paul Richardson • Dean Richmond • Don Riggs
Rogelio Rincon • Michael Roach • Shawn Roach • Rebecca Roark • Ari Robert • Charles Robertson • James Robertson • Curt Rodriguez
James Rodriguez • Cristopher Rogers • David Romines • Chanon Romo • Lester Ronholdt • John Rosata • Floyd Roth • Jon Ruby
Jamie Ruppelt • Jimmy Rush • Christopher Rybowiak • Robin Ryder • Ricardo Saldana • Azzeldeen Saleh • Pat Salwey • Jose Sanchez
Ann Sandate • Dorothy Sanders • Rock Sanders • Jason Sands • John Sanford • Karin Sanford • Ronald Santi • Jose Scagliusi • Joseph Scarfarotti
Alan Schaeffer • Michael Schanck • Richard Schauffler • Carol Schellhouse • Dinah Schlecht • Brittany Schmid • Gregory Schrab • Beverly Schreiner
Jeffrey Schurbon • Joshua Schwab • Tyson Schwartz • John Scott • Kelly Scott • Nikita Segura • Calvin Serpas • Janice Setzler • Robert Seymour
Edward Shannon • Leonard Sharp • Tiffany Sharp • Michael Shaw • Andrew Shea • Michelle Shiling • Joseph Shults • Deborah Siegmund
Eric Siegmund • Christopher Simon • Lilly Simpson • Scott Simpson • Tejay Simpson • Eric Skaalure • Jared Slade • Michael Slay • Roger Slife
Benjamin Smith • James Smith • Sabrina Smith • Keith Soine • Mark Solomon • Jason Sorensen • Erika Soto • Brian Southern • Roy Spann
Victoria Sparks • Zachary Spence • Robert Srader • Mary St. Germain • Catherine Stiles • Amber Stockdale • Diane Stokes • Karen Stroup
Luke Studer • Tyler Sullins • Bradford Sutton • Kelly Sutton • Pamela Sweet • Christopher Swoboda • Hans Swolfs • Janice Tabbert • George Tadla
John Takach • Elizabeth Taruscio • Sollie Thames • Benjamin Thogersen • Donna Thomas • Estelle Thomas • Jason Thomas • Nathan Thome
Dave Thompson • Linda Thompson • Kit Thorson • Connie Thunem • Jenna Tice • Kelby Timmons • Scotty Tjepkes • Kerin Todaro
Meghan Tonello • Joy Torgerson • Aaren Torrence • John Trahan • Janet Tran • Daniel Transtrom • Peter Transtrom • Staci Tribelhorn
Kristin Turner • George Ulmo • Marin Untiedt • Andrew Urie • David Van Brunt • Joseph Van • Kirk Vanderbeek • Charlotte Vangsnes
Michael VanMatre • Rhonda Vardeman • Juanita Vela • Troy Venhorst • Shari Vitt • Herbert Vogel • Margaret Vogl • Kelli Wahrmund
Edwin Wakefield • Wilford Walker • Vicky Wallace • Buckley Walsh • Lindsay Ward • Zachary Watson • Galen Watt • Robert Watt • Justin Watts
Lynette Watts • Cynthia Wedge • Randall Weeks • Brian Wehner • Jon Weible • Daniel Wells • Marlon Wells • Miranda Wells • Dianna West
Ryan West • David Whitcomb • Sarah Whitehouse • William Whitmire • Lonnie Whitson • Shane Wiggins • Linda Wilkins • Eric Williams
Kathy Willis • Ronald Willoughby • Jason Wilson • Kelsey Wilson • Kenneth Wilson • Matthew Wilson • James Winfield • William Wofford
Mat Wolf • Traci Woller • Christopher Wolter • Celesta Worley • Roger Worrell • Jay Wright • Karin Writer • Brenda Young • David Youngquist
William Zacek • Michael Zatkowsky • Jeffrey Zawila • Alina Zawislanski • Nathaniel Zeigler • Lindsey Zevenbergen • Clayton Ziler • Steven Zody
Dennis Zubieta • Frances Zwick

Information About Forward
Looking Statements

This annual report contains forward looking state-

ments within the meaning of securities laws, including

forecasts and projections. The words “will,” “believe,”

“budget,” “anticipate,” “plan,” “intend,” “estimate,”

“forecast,” and “expect” and similar expressions are

intended to identify forward looking statements.

These statements involve known and unknown risks,

which may cause SM Energy’s actual results to differ

materially from results expressed or implied by the

forward looking statements. These risks include

factors such as the availability, proximity and capacity

of gathering, processing and transportation facilities,

the uncertainty of negotiations to result in an agree-

ment or a completed transaction, the uncertain nature

of the expected benefits from the actual or expected

acquisition, divestiture, farm down or joint venture

of oil and gas properties, the uncertain nature of

announced divestiture, joint venture, farm down or

similar efforts and the ability to complete such

transactions, the volatility and level of oil, natural

gas, and natural gas liquids prices, uncertainties

inherent in projecting future rates of production

from drilling activities and acquisitions, the imprecise

nature of estimating oil and gas reserves, the

availability of additional economically attractive

exploration, development, and acquisition opportu-

nities for future growth and any necessary financings,

unexpected drilling conditions and results, unsuccess-

ful exploration and development drilling, the

availability of drilling, completion, and operating

equipment and services, the risks associated with

the Company's commodity price risk management

strategy, uncertainty regarding the ultimate impact

of potentially dilutive securities, and other such

matters discussed in the “Risk Factors” section of

SM Energy's 2012 Annual Report on Form 10-K.

The forward looking statements contained herein

speak as of February 21, 2013. Although SM Energy

may from time to time voluntarily update its prior

forward looking statements, it disclaims any commit-

ment to do so except as required by securities laws.

Directors

Officers

William D. Sullivan(1)
The Woodlands, Texas
Chairman of the Board
SM Energy Company

Barbara M. Baumann(1)(4)
Denver, Colorado
President of
Cross Creek Energy Corporation

Anthony J. Best(1)
Denver, Colorado
Chief Executive Officer
SM Energy Company

Larry W. Bickle(2)(3)
Houston, Texas
Private Investor

Stephen R. Brand(2)(4)
Houston, Texas
Senior Executive Advisor
Welltec, Inc.

William J. Gardiner(1)(3)
Houston, Texas
Senior Vice President and
Chief Financial Officer
King Ranch, Inc.

Loren M. Leiker(2)(3)
Houston, Texas
Director
SM Energy Company

Julio M. Quintana(2)(3)
Houston, Texas
President and Chief Executive Officer
TESCO Corporation

John M. Seidl(4)
Houston, Texas
Chairman of the Board
EnviroFuels, LLC

Anthony J. Best
Chief Executive Officer

Javan D. Ottoson
President and Chief Operating Officer

A. Wade Pursell
Executive Vice President and
Chief Financial Officer

David W. Copeland
Senior Vice President,
General Counsel and Corporate Secretary

Gregory T. Leyendecker
Senior Vice President and
Regional Manager — South Texas
& Gulf Coast

Mark D. Mueller
Senior Vice President and
Regional Manager — Rockies

Lehman E. Newton, III
Senior Vice President and
Regional Manager — Permian

Herbert S. Vogel
Senior Vice President —
Portfolio Development and
Technical Services

T. Hutch Jobe
Vice President —
Geoscience and Exploration

Kenneth J. Knott
Vice President — Land

Mary Ellen Lutey
Vice President and
Regional Manager — Mid-Continent

John R. Monark
Vice President — Human Resources

(1) Executive Committee

(2) Nominating and Corporate Governance Committee

Mark T. Solomon
Vice President — Controller

(3) Audit Committee

(4) Compensation Committee

David J. Whitcomb
Vice President — Marketing

Dennis A. Zubieta
Vice President —
Engineering, Evaluation and A&D

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2012
or

Commission file number 001-31539

SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction
of incorporation or organization)

41-0518430
(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)

80203
(Zip Code)

(303) 861-8140
(Registrant’s telephone number, including area code)

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

Title of each class
Common stock, $.01 par value

Name of each exchange on which registered
New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act.

Non-accelerated filer

Large accelerated filer
(Do not check if a smaller reporting company)

Accelerated filer
Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes

The aggregate market value of the 64,586,179 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price
of the registrant's common stock on June 29, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, of
$49.11 per share, as reported on the New York Stock Exchange; was $3,171,827,251. Shares of common stock held by each director and
executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the
registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination
for other purposes.

As of February 14, 2013, the registrant had 66,205,901 shares of common stock outstanding, which is net of 50,581 treasury shares held by
the registrant.

DOCUMENTS INCORPORATED BY REFERENCE
Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s definitive
proxy statement relating to its 2013 annual meeting of stockholders to be filed within 120 days after December 31, 2012.

ITEM

TABLE OF CONTENTS

PART I

PAGE

ITEMS 1. and 2.

BUSINESS and PROPERTIES

General
Strategy
Significant Developments in 2012
Outlook for 2013
Core Operational Areas
Reserves
Production
Productive Wells
Drilling Activity
Acreage
Delivery Commitments
Major Customers
Employees and Office Space
Title to Properties
Seasonality
Competition
Government Regulations
Cautionary Information about Forward-Looking Statements
Available Information
Glossary of Oil and Gas Terms

ITEM 1A.
ITEM 1B.
ITEM 3.
ITEM 4.

ITEM 5.
ITEM 6.

ITEM 7.

RISK FACTORS
UNRESOLVED STAFF COMMENTS
LEGAL PROCEEDINGS
MINE SAFETY DISCLOSURES

PART II

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

Overview of the Company
Financial Results of Operations and Additional Comparative Data
Comparison of Financial Results and Trends between 2012 and 2011
Comparison of Financial Results between 2011 and 2010
Overview of Liquidity and Capital Resources
Critical Accounting Policies and Estimates
Accounting Matters
Environmental
Non-GAAP Financial Measures

4
4
4
4
5
6
8
12
13
13
14
15
15
15
15
15
16
16
20
22
23
28
49
49
50
51

51
53

55
55
63
67
70
73
83
86
86
87

ITEM

ITEM 7A.
ITEM 8.

ITEM 9.
ITEM 9A.
ITEM 9B.

ITEM 10.
ITEM 11.

ITEM 12.

ITEM 13.
ITEM 14.

TABLE OF CONTENTS
(Continued)

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK (included within the content of ITEM 7)
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
OTHER INFORMATION

PART III

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

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

PAGE

88
89

141
141
144
144

144
147

147

149
149
150
150

PART I

When we use the terms “SM Energy,” “the Company,” “we,” “us,” or “our,” we are referring to SM Energy

Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms
important to an understanding of our business under Glossary of Oil and Gas Terms. Throughout this document we
make statements that may be classified as “forward-looking.” Please refer to the Cautionary Information about
Forward-Looking Statements section of this document for an explanation of these types of statements.

ITEMS 1. and 2. BUSINESS and PROPERTIES

General

We are an independent energy company engaged in the acquisition, exploration, development, and
production of crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and
“NGLs” throughout the document) in onshore North America, with a current focus on oil and liquids-rich resource
plays. We were founded in 1908 and incorporated in Delaware in 1915. Our initial public offering of common
stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol
“SM.”

Our principal offices are located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our

telephone number is (303) 861-8140.

Strategy

Our business strategy is to focus on the early capture of resource plays in order to create and then enhance

value for our shareholders, while maintaining a strong balance sheet. We strive to leverage industry-leading
acquisition, exploration, and operations teams to quickly acquire and test new resource play concepts at a
reasonable cost. Once we have identified potential value through these efforts, our goal is to develop such potential
through top-tier operational and project execution, and as appropriate, mitigate our risks by selectively divesting
certain assets. We continually examine our portfolio for opportunities to improve the quality of our asset base in
order to optimize our returns and preserve our financial strength.

Significant Developments in 2012

• Resource Play Delineation and Development Results in Record Production and Increase in Year-End
Proved Reserve Estimates. Our estimated proved reserves increased 40 percent to 1,760.6 BCFE
(293.4 MMBOE) at December 31, 2012, from 1,259.2 BCFE (209.9 MMBOE) at December 31, 2011.
We added 900.2 BCFE through drilling activity during the year, which was primarily led by our efforts
in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We
achieved record levels of production in 2012. Our average daily production was composed of 28.3
MBbl of oil, 328.0 MMcf of gas, and 16.7 MBbl of NGLs for an average equivalent production rate of
598.2 MMCFE per day, which was an increase of 29 percent from 465.0 MMCFE per day in 2011.
Costs incurred in 2012 for drilling and exploration activities and acquisitions increased nine percent, to
$1.7 billion, compared with $1.6 billion in 2011 due mainly to increased activity in plays with
significant oil and NGL-rich gas components, such as our Eagle Ford shale and Bakken/Three Forks
programs. Please refer to Core Operational Areas below for additional discussion concerning our 2012
estimated proved reserves, production, and capital investment.

•

Impairments. We recorded impairment of proved properties expense of $208.9 million for the year
ended December 31, 2012. During the fourth quarter of 2012, we recorded proved property impairment
expense of $170.4 million. This non-cash charge was driven by downward engineering revisions that
resulted in the write-down of Wolfberry assets in our Permian region. We also recorded proved
property impairment expense of $38.5 million in the second quarter of 2012 related to our Haynesville
shale assets in our Mid-Continent region due to low natural gas prices.

• Volatility and Decline in Commodity Prices. Our financial condition and the results of our operations
are significantly affected by the prices we receive for oil, natural gas, and NGLs, which can fluctuate
dramatically. Oil prices were volatile throughout 2012, reaching their peak for the year in February
when the spot price for NYMEX crude oil hit a high of $109.49 per Bbl. The spot price for NYMEX
crude oil during 2012 was at its lowest of $77.69 per Bbl in June. The average spot price for oil during
2012 was $94.10 per Bbl, down slightly from the $95.05 per Bbl average NYMEX price in 2011. In
2012, oil prices were impacted by concerns over international supply disruptions, rising U.S. oil
production, and changes in global economic growth expectations throughout the year.

Natural gas prices were also volatile in 2012. The spot price for natural gas at Henry Hub in Erath,
Louisiana, a widely-used industry measuring point, averaged $2.75 per MMBtu in 2012, down from an
average price of $4.00 per MMBtu in 2011. The 2012 average price was the lowest average annual
price at Henry Hub since 1999. The high at Henry Hub for 2012 of $3.77 per MMBtu was recorded in
November, and the low of $1.84 per MMBtu was reached in April. Natural gas prices were under
downward pressure in 2012 as a result of sustained high natural gas inventories and rising natural gas
production in the Marcellus and Eagle Ford basins. Natural gas prices rose throughout the remainder of
the year after reaching their low in April.

NGL prices decreased throughout 2012 largely due to a growing supply of NGLs as increased numbers
of industry participants targeted projects producing NGLs. The average spot price for NGLs in 2012 at
Mont Belvieu was $44.91 per Bbl, which was down from $59.47 per Bbl in 2011. Please refer to
Overview of the Company and Oil, Gas, and NGL Prices included in Part II, Item 7 of this report for
additional information regarding our NGL prices.

Outlook for 2013

We enter 2013 with a projected $1.5 billion capital program, approximately $1.2 billion of which we expect

to allocate to drilling and completion activities. Our 2013 capital program allocates all drilling and completion
capital to oil and liquids-rich programs. Please refer to Core Operational Areas below and Outlook for 2013 under
Part II, Item 7 of this report for additional discussion surrounding our capital plans for 2013.

Core Operational Areas

Our operations are concentrated in four core operating areas in the onshore United States. Effective
January 1, 2012, we combined our former ArkLaTex region with our Mid-Continent region, based in Tulsa,
Oklahoma, for operational and reporting purposes. The following table summarizes estimated proved reserves,
PV-10 reserve value, and production for the year ended December 31, 2012, for our core operating areas:

South Texas
& Gulf Coast

Rocky
Mountain

Mid-
Continent

Permian

Total (1)

Proved Reserves
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE (1)

Relative percentage

Proved Developed %
PV-10 Values (in millions) (2)
Proved Developed
Proved Undeveloped
Total Proved

30.9
530.7
60.5
1,079.2
61%
43%

49.2
42.7
—
337.9
19%
65%

0.9
233.4
1.6
248.6
14%
89%

11.2
26.6
0.2
94.8
6%
93%

92.2
833.4
62.3
1,760.6
100%
57%

1,308.7
591.5
1,900.2

974.4
248.5
1,222.9

295.9
4.8
300.7

403.6
21.7
425.3

2,982.6
866.5
3,849.1

Relative percentage

49%

32%

11%

100%

3.2
59.1
5.7
112.7

Production
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE (1)
Avg. Daily Equivalents
(MMCFE/d)
Relative percentage
(1) Totals may not sum or recalculate due to rounding.
(2) The standardized measure PV-10 calculation is presented in the Supplemental Oil and Gas Information section located in
Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown in the
Reserves section below.

0.4
53.4
0.4
58.1

5.4
4.4
—
36.9

1.3
3.2
—
11.3

158.6
27%

100.9
17%

307.9
51%

10.4
120.0
6.1
218.9

30.8
5%

598.2
100%

South Texas & Gulf Coast Region. Operations in our South Texas & Gulf Coast region are managed from

our office in Houston, Texas. Our current operations in this region focus primarily on our Eagle Ford shale
program. Our acreage position covers a significant portion of the western Eagle Ford shale play, including acreage
in the oil, NGL-rich gas, and dry gas windows of the play. As of December 31, 2012, we had roughly 191,500 net
acres in the play. We operate approximately 145,000 of the 191,500 net acres, with an average working interest of
nearly 100 percent.

Nearly all of our capital deployed in the South Texas & Gulf Coast region in 2012 targeted our operated

Eagle Ford shale program. Production in 2012 increased 62 percent from the 69.7 BCFE produced in 2011.
Estimated proved reserves at year-end 2012 increased 123 percent from 483.6 BCFE at year-end 2011. Of the 2012
reserve additions in this region, approximately 767.3 BCFE of estimated proved reserves were added through
drilling activities. The increase in production and proved reserves reflects the success we are having in our Eagle
Ford shale program and the resulting consistent pace of investment. Our capital expenditures in our South Texas &
Gulf Coast region decreased from $932.3 million in 2011 to $848.4 million in 2012, as a result of being carried for
substantially all of our drilling and completion costs in our outside operated Eagle Ford program pursuant to our
Acquisition and Development Agreement with Mitsui E&P Texas LP (“Mitsui”), an indirect subsidiary of Mitsui &
Co., Ltd. (the “Acquisition and Development Agreement”).
6

Rocky Mountain Region. Operations in our Rocky Mountain region are managed from our office in

Billings, Montana. Our capital expenditures in 2012 primarily targeted the Bakken/Three Forks formations in the
North Dakota portion of the Williston Basin, where we have approximately 80,500 net acres. In 2012, we
continued to focus our drilling and completion activities in three main areas. In our Raven and Bear Den prospects,
in Williams and McKenzie Counties, North Dakota, we have largely completed our drilling program intended to
establish held by production status and have transitioned our program primarily to infill drilling. Our efforts are
focused on optimizing our completions and spacing for development of the Bakken formation. In our Gooseneck
prospect in Divide County, North Dakota, our efforts focused on the Three Forks formation, where we are also
transitioning to infill drilling. As our program moves to infill development, we will continue our transition to multi-
well pad drilling to improve the efficiency of our drilling and completion operations. Elsewhere in our Rocky
Mountain region, we are in the exploratory phase of drilling test wells of various formations in the Powder River
Basin. At year-end 2012, we had approximately 65,000 net acres in the Powder River Basin that we believe to be
prospective in various target horizons.

Capital expenditures in our Rocky Mountain region increased from $288.0 million in 2011 to $406.8

million in 2012, as we increased activity in our Bakken/Three Forks program. Estimated proved reserves for the
region at the end of 2012 increased 11 percent from 303.4 BCFE at year-end 2011. During the year, we added
approximately 90.0 BCFE of proved reserves in this region through drilling activities. Total regional production for
2012 was up 38 percent from the 26.7 BCFE produced in 2011. The increase in capital, production, and proved
reserves reflects the increased activity in our Bakken/Three Forks program.

Mid-Continent Region. Operations in our Mid-Continent region are managed from our office in Tulsa,

Oklahoma. Our current operations in the Mid-Continent region are primarily focused on the horizontal
development of the Granite Wash formation in western Oklahoma. Our Mid-Continent region also manages our
Haynesville and Woodford shale assets, on which we minimized activity in 2012 due to the low natural gas price
environment, which resulted in a decrease in our 2012 capital expenditures, production, and year-end reserves, as
discussed below. Our 2012 Granite Wash program targeted the shallower, liquids-rich washes of our approximately
34,000 net acres in the play, substantially all of which are held by production.

In 2012, we incurred costs of $168.2 million in our Mid-Continent region for exploration, development, and

acquisition activities, compared to $247.0 million incurred in 2011. In 2012, our Mid-Continent region’s
production was 58.1 BCFE, a decrease from the 61.8 BCFE produced in 2011. Estimated proved reserves at the
end of 2012 decreased 32 percent from 365.2 BCFE as of the end of 2011.

Permian Region. Operations in our Permian region are managed from our office in Midland, Texas. Our

Permian region covers western Texas and eastern New Mexico. Our primary area of focus in this region is the
delineation of our Mississippian limestone play, in which we hold approximately 65,500 net acres. In addition to
this delineation program, we have an exploration program targeting various shale intervals in the Midland Basin.
These programs resulted in an increase in our 2012 capital expenditures, as discussed below.

We incurred costs of $232.5 million in the region for exploration, development, and acquisition activities in

2012 compared to $80.7 million in 2011. A significant portion of the 2012 costs incurred in this region were for
leasing activities and a drilling program that was weighted toward the last half of the year. The region’s 2012
production was 11.3 BCFE, compared to 2011 production of 11.5 BCFE. The decrease in production was due to
natural decline in our Wolfberry assets as the field matured. Estimated proved reserves at the end of 2012 were
94.8 BCFE, which was a decrease from 2011 year-end proved reserves of 107.0 BCFE.

Reserves

The table below presents summary information with respect to the estimates of our proved reserves for each

of the years in the three-year period ended December 31, 2012. We engaged Ryder Scott Company, L.P. (“Ryder
Scott”) to audit our internal engineering estimates of at least 80 percent of the PV-10 value of our estimated proved
reserves in each year presented. The prices used in the calculation of proved reserve estimates as of December 31,
2012, were $94.71 per Bbl for oil, $2.76 per MMBtu for natural gas, and $45.65 per Bbl for NGLs.

Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are

more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are
expected to change as new information becomes available. The PV-10 values shown in the following table are not
intended to represent the current market value of our estimated proved reserves. Neither prices nor costs have been
escalated. The actual quantities and present values of our estimated proved reserves may be less than we have
estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority
or agency, other than the Securities and Exchange Commission (“SEC”), since the beginning of the last fiscal year.
The following table should be read along with the section entitled Risk Factors – Risks Related to Our Business
contained herein.

Our ability to replace our production is important to our sustainability. Please refer to the reserve
replacement terms in the Glossary of Oil and Gas Terms section of this report for information describing how our
reserve replacement metrics are calculated. Our reserve replacement percentages are calculated using information
from the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information located in Part II, Item 8
of this report.

We believe the concept of reserve replacement as described in the Glossary of Oil and Gas Terms section of
this report, as well as permutations that may include other captions of the Oil and Gas Reserve Quantities section of
Supplemental Oil and Gas Information located in Part II, Item 8 of this report, are widely understood by those who
make investment decisions related to the oil and gas exploration business.

Reserve data:
Proved developed
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE (1)

Proved undeveloped

Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE (1)
Total Proved

Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE (1)

Proved developed reserves %
Proved undeveloped reserves %

2012

As of December 31,
2011

2010

58.8
483.2
27.2
999.1

33.5
350.2
35.1
761.5

92.2
833.4
62.3
1,760.6

57%
43%

50.3
451.2
15.2
844.0

21.4
212.8
12.3
415.2

71.7
664.0
27.5
1,259.2

67%
33%

46.0
411.0
—
687.3

11.4
229.0
—
297.2

57.4
640.0
—
984.5

70%
30%

Reserve value data (in millions):
Proved developed PV-10
Proved undeveloped PV-10
Total proved PV-10
Standardized measure of discounted future cash flows

$
$

2,982.6
866.5
3,849.1
3,021.0

$
$

2,836.3
624.9
3,461.2
2,580.0

$
$

2,053.5
290.8
2,344.3
1,666.4

Reserve replacement – drilling, excluding revisions
All in – including sales of reserves
All in – excluding sales of reserves
Reserve life (years)
(1) Totals may not sum or recalculate due to rounding.

411%
329%
337%
8.0

310%
262%
317%
7.4

349%
293%
372%
8.9

Note: NGL reserve data for 2010 has not been reclassified to conform to the current presentation given the immateriality of the
volumes in 2010. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices under Part II, Item 7 of this
report.

The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the

PV-10 value (Non-GAAP). The difference is a result of the PV-10 value measure excluding the impact of income
taxes. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the
Glossary of Oil and Gas Terms.

Standardized measure of discounted future net

cash flows

Add: 10 percent annual discount, net of income

taxes

Add: future undiscounted income taxes
Undiscounted future net cash flows
Less: 10 percent annual discount without tax

effect
PV-10 value

Proved Undeveloped Reserves

2012

As of December 31,
2011
(in millions)

2010

3,021.0

2,580.0

1,666.4

1,742.1
1,609.4
6,372.5

(2,523.4)
3,849.1

1,727.6
1,740.4
6,048.0

(2,586.8)
3,461.2

1,294.6
1,335.5
4,296.5

(1,952.2)
2,344.3

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on

undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development
areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable
certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a
development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific
circumstances justify a longer time period. As of December 31, 2012, we had no undrilled proved undeveloped
reserves that had been on our books in excess of five years.

During 2012, the Company utilized reliable geologic and engineering technology to add approximately

177.7 BCFE of proved undeveloped reserves for locations that are more than one location removed from developed
locations in the more developed portions of our Eagle Ford shale position. We incorporated public and proprietary
data from multiple sources to establish geologic continuity of the formation and its producing properties. This
included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and
horizontally collected), and petrophysical analysis of the log data, mud logs, gas sample analysis, measurements of
total organic content, thermal maturity, test production, fluid properties, and core data as well as significant
statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas.
These locations were limited to only those areas where both established geologic consistency and sufficient
statistical performance data could be demonstrated to provide reasonably certain results. In all other areas, we
restricted proved undeveloped locations to immediate offsets to producing wells.

As of December 31, 2012, we had 761.5 BCFE of proved undeveloped reserves, which is an increase of
346.3 BCFE, or 83 percent, over proved undeveloped reserves of 415.2 BCFE at December 31, 2011. We added
549.7 BCFE of proved undeveloped reserves through our drilling program, 278.1 BCFE of which were extensions
and discoveries, primarily in our Eagle Ford shale play, as well as an additional 271.6 BCFE of infill proved
undeveloped reserves that were mostly concentrated in our assets in the Bakken/Three Forks and the Eagle Ford
shale plays. A negative price revision of 29.1 BCFE was primarily due to gas weighted projects in our South Texas
& Gulf Coast and Mid-Continent regions that no longer generated positive cash flow utilizing 12-month average
benchmark pricing required by the SEC. Extensive delineation drilling in our Eagle Ford shale program during
2012 resulted in an increase in statistical data available in the play. This information, combined with extensive data
demonstrating the geologic continuity of the reservoir, allowed us to add 491.2 BCFE of new proved undeveloped
reserves in the Eagle Ford shale play and led to a downward engineering revision of 39.2 BCFE primarily related to
10

previously booked Eagle Ford shale proved undeveloped locations. We removed 42.7 BCFE of proved
undeveloped reserves from our books, primarily in the Woodford shale, due to low natural gas prices and as a result
of the five-year limitation on the number of years that proved undeveloped reserves may be booked without being
developed. During the year, we sold proved undeveloped assets in our Rocky Mountain region, comprising 3.2
BCFE. During 2012, we converted 89.2 BCFE of proved undeveloped reserves to proved developed reserves,
primarily in our Eagle Ford shale and Bakken/Three Forks plays at a total capital cost of $203.6 million, of which
$159.4 million was incurred in 2012. Please refer to Note 12 - Acquisition and Development Agreement and Carry
and Earning Agreement for discussion of the carry of 90 percent of certain of our drilling and completion costs. As
of December 31, 2012, estimated future development costs relating to our proved undeveloped reserves are
approximately $660 million, $451 million, and $359 million in 2013, 2014, and 2015, respectively.

Internal Controls Over Reserves Estimates

Our internal controls over the recording of proved reserves are structured to objectively and accurately

estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and
monitoring the Company’s proved reserves is delegated to our reservoir engineering group, which is managed by
Dennis A. Zubieta, our Vice President - Engineering, Evaluation and A&D, subject to the oversight of our
management and the Audit Committee of our Board of Directors, as discussed below. Mr. Zubieta joined us in June
2000 as a Corporate Acquisition & Divestiture Engineer, assumed the role of Reservoir Engineer in February 2003,
was appointed Reservoir Engineering Manager in August 2005, was appointed Vice President - Engineering and
Evaluation in August 2008, and was appointed Vice President - Engineering, Evaluation and A&D in October 2012.
Mr. Zubieta was employed by Burlington Resources Oil and Gas Company from June 1988 to May 2000 in various
operations and reservoir engineering capacities. Mr. Zubieta received a Bachelor of Science degree in Petroleum
Engineering from Montana Tech of The University of Montana in May 1988. Technical reviews are performed
throughout the year by regional staff who evaluate geological and engineering data. This data, in conjunction with
economic data and our ownership information, is used in making a determination of estimated proved reserve
quantities. Our regional engineering technical staff do not report directly to Mr. Zubieta; they report to either their
respective regional technical managers or directly to the regional manager. This is intended to promote objective
and independent analysis within our regions in the reserves estimation process.

Third-party Reserves Audit

Ryder Scott performed an independent audit using its own engineering assumptions but with economic and

ownership data we provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve
PV-10 value. In the aggregate, the proved reserve values of our audited properties determined by Ryder Scott are
required to be within 10 percent of our proved reserve valuations for the total company, as well as for each
respective region. Ryder Scott is an independent petroleum engineering consulting firm that has been providing
petroleum engineering consulting services throughout the world for over seventy years. The technical person at
Ryder Scott primarily responsible for overseeing our reserves audit is a Managing Senior Vice President who
received a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970,
and who is a registered Professional Engineer in Colorado and Utah. He is also a member of the Society of
Petroleum Engineers. The Ryder Scott 2012 report concerning our reserves is included as Exhibit 99.1.

In addition to a third party audit, our reserves are reviewed by management with the Audit Committee of
our Board of Directors. Management, which includes our Chief Executive Officer, President and Chief Operating
Officer, Executive Vice President and Chief Financial Officer, and Senior Vice President - Portfolio Development
and Technical Services, is responsible for reviewing and verifying that the estimate of proved reserves is
reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in
conjunction with Ryder Scott’s results and also meets with Ryder Scott representatives from time to time to discuss
its processes and findings.

Production

The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced and sold

from properties in which we held an interest during the periods indicated. Realized prices presented below exclude
the effects of hedges and derivative contracts. Also presented is a summary of related production costs per MCFE.

For the Years Ended December 31,
2011

2010

2012

Net production

Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE

Eagle Ford net production(1)
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE

Average net daily production

Oil (MBbl per day)
Gas (MMcf per day)
NGLs (MBbl per day)
MMCFE per day

Eagle Ford average net daily production(1)

Oil (MBbl per day)
Gas (MMcf per day)
NGLs (MBbl per day)
MMCFE per day

Realized price

Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Per MCFE
Production costs per MCFE

Lease operating expense
Transportation costs
Production taxes

10.4
120.0
6.1
218.9

3.1
58.1
5.7
110.9

28.3
328.0
16.7
598.2

8.6
158.8
15.5
303.1

85.45
2.98
37.61
6.73

0.82
0.63
0.33

$
$
$
$

$
$
$

8.1
100.3
3.5
169.7

2.5
32.9
3.1
66.6

22.1
274.8
9.6
465.0

6.8
90.1
8.6
182.5

88.23
4.32
53.32
7.85

0.88
0.51
0.32

$
$
$
$

$
$
$

6.4
71.9
—
110.0

0.8
13.0
—
17.6

17.4
196.9
—
301.4

2.1
35.6
—
48.3

72.65
5.21
—
7.60

1.10
0.19
0.48

$
$
$
$

$
$
$

(1) In each of the years 2012, 2011, and 2010, total estimated proved reserves attributed to our Eagle Ford shale properties
exceeded 15 percent of our total proved reserves expressed on an equivalent basis.

Note: NGL production volumes and prices for 2010 have not been reclassified to conform to the current presentation given the
immateriality of the volumes in 2010. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices under
Part II, Item 7 of this report.

Productive Wells

As of December 31, 2012, we had working interests in 1,184 gross (730 net) productive oil wells and 3,018

gross (1,078 net) productive gas wells. Productive wells are either wells producing in commercial quantities or
wells that are mechanically capable of commercial production, but are currently shut-in. Multiple completions in
the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or
a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may
not be indicative of the current production mix.

Drilling Activity

All of our drilling activities are conducted using independent drilling contractors. We do not own any
drilling equipment. The following table summarizes the number of operated and non-operated wells drilled or
recompleted on our properties in 2012, 2011, and 2010, excluding non-consented projects, active injector wells, and
any wells in which we own only a royalty interest:

2012

For the Years Ended December 31,
2011

2010

Gross

Net

Gross

Net

Gross

Net

Development wells:
Oil
Gas
Non-productive

Exploratory wells:
Oil
Gas
Non-productive

127
337
10
474

9
8
8
25

47.2
124.5
6.3
178.0

6.9
6.8
6.8
20.5

125
273
11
409

16
48
3
67

32.1
81.0
4.0
117.1

6.3
8.6
1.0
15.9

Total

499

198.5

476

133.0

191
72
4
267

36
83
1
120

387

36.5
17.0
1.1
54.6

11.5
37.9
0.8
50.2

104.8

A productive well is an exploratory, development, or extension well that is producing oil, gas, and/or NGLs
or that is capable of commercial production of those products. A non-productive well, frequently referred to within
the industry as a dry hole, is an exploratory, development, or extension well that proves to be incapable of
producing either oil, gas, and/or NGLs in commercial quantities.

As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in

a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled
within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be
productive and is part of a development project, which is defined as the means by which petroleum resources are
brought to economically producible status. The number of wells drilled refers to the number of wells completed at
any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation
of equipment for production of oil, gas, and/or NGLs, or in the case of a dry well, the reporting to the appropriate
authority that the well has been plugged and abandoned.

In addition to the wells drilled and completed in 2012 (included in the table above), as of February 14,

2013, we were participating in the drilling of 44 gross wells. We operate 25 of these wells on a gross basis (17 on a
net basis) and other companies operate the remaining 19 gross wells (two on a net basis). With respect to
completion activity, at such date, there were 234 gross wells in which we have an interest that were being
completed. We operate 45 of these completion activities on a gross basis (40 on a net basis), and were participating
in 189 gross (34 net) non-operated completion activities. Substantially all of these operations relate to the drilling
of wells during the primary term of the respective oil and gas lease or leases.

Acreage

The following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold,

fee properties, and mineral servitudes held by us as of December 31, 2012. Undeveloped acreage includes
leasehold interests that contain proved undeveloped reserves.

Total

Undeveloped Acres (2)
Gross

Louisiana
Montana
Nevada
North Dakota
Oklahoma
Pennsylvania
Texas
Wyoming
Other (3)

Developed Acres (1)
Net
Gross
24,794
39,877
—
102,579
82,441
282
152,195
21,897
2,011
426,076
10,499
4,217
14,716
440,792

Net
55,783
250,103
197,634
164,694
110,874
23,085
472,705
211,722
31,948
1,518,548
24,914
8,624
33,538
1,552,086
(1) Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation.
Our developed acreage that includes multiple formations with different well spacing requirements may be considered
undeveloped for certain formations, but has been included only as developed acreage in the presentation above.
(2) Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the

Net
30,989
210,226
197,634
62,115
28,433
22,803
320,510
189,825
29,937
1,092,472
14,415
4,407
18,822
1,111,294

Gross
110,854
370,344
197,634
264,421
314,348
26,552
816,203
313,222
47,356
2,460,934
24,914
12,195
37,109
2,498,043

39,104
312,758
197,634
105,932
64,642
26,270
570,504
267,961
42,926
1,627,731
14,415
4,769
19,184
1,646,915

71,750
57,586
—
158,489
249,706
282
245,699
45,261
4,430
833,203
10,499
7,426
17,925
851,128

Louisiana Fee Properties
Louisiana Mineral Servitudes

Total (4)

production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net
proved reserves.

(3) Includes interests in Arkansas, Colorado, Kansas, Illinois, Mississippi, Nebraska, New Mexico, and Utah.
(4) As of the filing date of this report, we had approximately 63,368, 79,048, and 162,422 net acres scheduled to expire by

December 31, 2013, 2014, and 2015, respectively, if production is not established or we take no other action to extend the
terms of the applicable lease or leases.

Delivery Commitments

As of December 31, 2012, we had gathering, processing, and transportation through-put commitments with

various parties that require us to deliver fixed, determinable quantities of production over specified time frames.
We have an aggregate minimum commitment to deliver 1,515 Bcf of natural gas and 36 MMBbls of oil. These
contracts expire at various dates through 2023. We are required to make periodic deficiency payments for any
shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume commitment for
natural gas is projected, we have rights under certain contracts to arrange for third party gas to be delivered, and
such volume will count toward our minimum volume commitment. Our current production is insufficient to offset
these aggregate contractual liabilities, but we expect to fulfill the delivery commitments with production from the
future development of our proved undeveloped reserves and from the future development of resources not yet
characterized as proved reserves in our Eagle Ford shale and Haynesville shale resource plays. Therefore, we
currently do not expect any significant shortfalls.

Major Customers

For the year ended December 31, 2012, we had two major customers, Regency Gas Services LLC and
Plains Marketing LP, which accounted for approximately 21 percent and 13 percent, respectively, of our total
revenue. During 2011 and 2010, we had one major customer, Regency Gas Services LLC, which individually
accounted for approximately 18 percent and 11 percent, respectively, of our total revenue.

Employees and Office Space

As of February 14, 2013, we had 725 full-time employees. None of our employees are subject to a

collective bargaining agreement, and we consider our relations with our employees to be good.

As of December 31, 2012, we leased approximately 98,000 square feet of office space in Denver, Colorado

for our executive and administrative offices; approximately 45,000 square feet of office space in Tulsa, Oklahoma;
approximately 62,000 square feet in Houston, Texas; approximately 30,000 square feet in Billings, Montana;
approximately 22,000 square feet in Midland, Texas; approximately 7,000 total square feet in Williston and
Watford City, North Dakota; and approximately 2,000 square feet in Casper, Wyoming. As of December 31, 2012,
we own field office facilities containing approximately 12,000 square feet of office space in Catarina, Texas;
approximately 3,000 square feet of office space in Belfield, North Dakota; and approximately 4,000 square feet of
office space in Sidney, Montana.

Title to Properties

Substantially all of our interests are held pursuant to oil and gas leases from third parties. A title opinion is
usually obtained prior to the commencement of initial drilling operations. We have obtained title opinions or have
conducted other title review on substantially all of our producing properties and believe that we have satisfactory
title to such properties in accordance with standards generally accepted in the oil and gas industry. Substantially all
of our producing properties are subject to mortgages securing indebtedness under our credit facility, royalty and
overriding royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere
with the use of, or affect the value of, such properties. We typically perform only minimal title investigation before
acquiring undeveloped leasehold acreage.

Seasonality

Generally, but not always, the demand and price levels for natural gas increase during winter months and

decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution
companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated
winter requirements during the summer. However, increased summertime demand for electricity can place
increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the
summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal
15

anomalies, such as mild winters, sometimes lessen these fluctuations. The impact of seasonality on oil has been
somewhat magnified by overall supply and demand economics attributable to the narrow margin of worldwide
production capacity in excess of existing worldwide demand for oil. Certain of our drilling, completion, and other
operations are also subject to seasonal limitations. Seasonal weather conditions and lease stipulations adversely
affect our ability to conduct drilling activities in some of the areas where we operate. See Risk Factors - Risks
Related to Our Business for additional discussion.

Competition

The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and
natural gas properties. We believe our leasehold position provides a sound foundation for a solid drilling program
and our future growth. Our competitive position also depends on our geological, geophysical, and engineering
expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling,
operational, and production expertise; available technologies; our financial resources and expertise; and the
experience and knowledge of our management and technical teams enable us to compete in our core operating
areas. However, we face intense competition from a substantial number of major and independent oil and gas
companies, which in some cases have larger technical staffs and greater financial and operational resources than we
do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil
and natural gas reserves, but also have refining operations, market refined products, own drilling rigs and other
equipment, and generate electricity.

We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment

and services necessary for the drilling, completion, and maintenance of wells. Consequently, we may face
shortages or delays in securing these services from time to time. The oil and gas industry also faces competition
from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas.
Competitive conditions may be affected by future new energy, climate-related, financial, and/or other policies,
legislation, and regulations.

In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other

professionals. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time
when the availability of individuals with these skills is becoming more limited due to the evolving demographics of
our industry. We are not insulated from the competition for quality people, and we must compete effectively in
order to be successful.

Government Regulations

Our business is extensively regulated by numerous federal, state, and local laws and governmental

regulations. These laws and regulations may be changed from time to time in response to economic or political
conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations
have the potential of increasing our cost of doing business and, consequently, could affect our profitability.
However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.

Energy Regulations. Many of the states in which we conduct our operations have adopted laws and
regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations that
require permits for the drilling of wells, impose bonding requirements in order to drill or operate wells, and govern
the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and restoration
of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also
subject to various state conservation laws and regulations, including regulations governing the size of drilling and
spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the
unitization or pooling of oil and gas properties. In addition, state conservation laws sometimes establish maximum
rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and may impose certain
requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the

Bureau of Land Management (“BLM”). These leases contain relatively standardized terms and require compliance
with detailed regulations and orders that are subject to change. In addition to permits required from other
regulatory agencies, lessees must obtain a permit from the BLM before drilling and must comply with regulations
governing, among other things, engineering and construction specifications for production facilities, safety
procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds
to ensure that lessee obligations are met. Under certain circumstances, the BLM may suspend or terminate our
operations on federal leases.

In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things,
a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in
the development of master leasing and development plans prior to leasing areas where intensive new oil and gas
development is anticipated, and a comprehensive parcel review process. These changes have increased the amount
of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM.

Our sales of natural gas are affected by the availability, terms, and cost of gas pipeline transportation. The

Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of
natural gas in interstate commerce. FERC’s current regulatory framework generally provides for a competitive and
open access market for sales and transportation of natural gas. However, FERC regulations continue to affect the
midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for
natural gas production. In addition, the less stringent regulatory approach currently pursued by FERC and the
United States Congress may not continue indefinitely.

Environmental, Health and Safety Matters

General. Our operations are subject to stringent and complex federal, state, tribal and local laws and
regulations governing protection of the environment and worker health and safety as well as the discharge of
materials into the environment. These laws and regulations may, among other things:

•

require the acquisition of various permits before drilling commences;

•

restrict the types, quantities and concentration of various substances that can be released into the
environment in connection with oil and natural gas drilling and production and saltwater disposal
activities;

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected
areas, including areas containing certain wildlife or threatened and endangered plant and animal
species; and

•

require remedial measures to mitigate pollution from former and ongoing operations, such as
requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate

that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of
doing business in the industry and consequently affects profitability. Additionally, environmental laws and
regulations are revised frequently, and any changes that result in more stringent and costly permitting, waste
handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on
our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our business is

subject.

Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes
regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous
wastes. Under the auspices of the federal Environmental Protection Agency (the “EPA”), the individual states
administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent
requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration,
development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste
provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified
as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase
in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of
operations and financial position.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive

Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes
joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to
be responsible for the release of a hazardous substance into the environment. These persons include the owner or
operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a
hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability
for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to
natural resources and for the costs of certain health studies. 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 the
hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas
exploration and production for many years. Although we believe that we have utilized operating and waste disposal
practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have
been released on or under the properties owned or leased by us, or on or under other locations, including off-site
locations, where such substances have been taken for disposal. In addition, some of our properties have been
operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances,
wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on
them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to
remove previously disposed substances and wastes, remediate contaminated property, or perform remedial
operations to prevent future contamination.

Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state

laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of
oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated
waters is prohibited, except in accordance with the terms of a permit issued by the EPA, U.S. Army Corps of
Engineers or analogous state agencies. Federal and state regulatory agencies can impose administrative, civil and
criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and
analogous state laws and regulations.

The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability

associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects
owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain
other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants
from our operations could result in governmental penalties and civil liability.

Air emissions. The federal Clean Air Act (“CAA”), and comparable state laws, regulate emissions of
various air pollutants through air emissions permitting programs and the imposition of other requirements. In
addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air
pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal
penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws
and regulations.

Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and

other “greenhouse gases” present an endangerment to public health and the environment because emissions of such
gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.
Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to
restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives
related to climate change could have an adverse effect on our operations and the demand for oil and gas. See “Risk
Factors - Risks Related to Our Business - Legislative and regulatory initiatives related to global warming and
climate change could have an adverse effect on our operations and the demand for crude oil, natural gas and
NGLs.” In addition to the effects of regulation, the meteorological effects of global climate change could pose
additional risks to our operations, including physical damage risks associated with more frequent, more intensive
storms and flooding, and could adversely affect the demand for our products.

Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that

could have an adverse effect on threatened or endangered species. Some of our well drilling operations are
conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and
implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting
drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our
operations could have an adverse effect on the species. It is also possible that a federal or state agency could order
a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious
adverse effect on a protected species. The presence of a protected species in areas where we perform drilling
activities could impair our ability to timely complete well drilling and development and could adversely affect our
future production from those areas.

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal

lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including
the Department of Interior, to evaluate major agency actions having the potential to significantly impact the
environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses
the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more
detailed environmental impact statement that may be made available for public review and comment. All of our
current exploration and production activities, as well as proposed exploration and development plans, on federal
lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to
delay development of some of our oil and natural gas projects.

OSHA and other laws and regulation. We are subject to the requirements of the federal Occupational

Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the
EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we
organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant
to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to
workplace exposure to hazardous substances and employee health and safety. We believe that we are in substantial
compliance with the applicable requirements of OSHA and comparable laws.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate

production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of
our drilling and completion programs. The process involves the injection of water, sand and chemicals under
pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically
regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority
over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (the “SDWA”)
Underground Injection Control Program. The federal SDWA protects the quality of the nation’s public drinking
water through the adoption of drinking water standards and controlling the injection of waste fluids into below-
ground formations that may adversely affect drinking water sources.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition

to oil and gas activities using hydraulic fracturing techniques, which could potentially cause a decrease in the
completion of new oil and gas wells, increased compliance costs and delays, all of which could adversely affect our
financial position, results of operations and cash flows. If new laws or regulations that significantly restrict
hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to
stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal
level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become
subject to additional permitting requirements, and also to attendant permitting delays and potential increases in
costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are
ultimately able to produce from our reserves.

We believe that it is reasonably likely that the trend in environmental legislation and regulation will

continue toward stricter standards. While we believe that we are in substantial compliance with existing
environmental laws and regulations applicable to our current operations and that our continued compliance with
existing requirements will not have a material adverse impact on our financial condition and results of operations,
we cannot give any assurance that we will not be adversely affected in the future.

Cautionary Information about Forward-Looking Statements

This Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities

Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of
historical facts, included in this Form 10-K that address activities, events, or developments with respect to our
financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or
may occur in the future, or that address plans and objectives of management for future operations, are forward-
looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,”
“intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements.
Forward-looking statements appear in a number of places in this Form 10-K, and include statements about such
matters as:

•

the amount and nature of future capital expenditures and the availability of liquidity and capital
resources to fund capital expenditures;

the drilling of wells and other exploration and development activities and plans, as well as possible
future acquisitions;

the possible divestiture or farm-down of, or joint venture relating to, certain properties;

proved reserve estimates and the estimates of both future net revenues and the present value of future
net revenues associated with those proved reserve estimates;

future oil, gas, and NGL production estimates;

our outlook on future oil, gas, and NGL prices, well costs, and service costs;

•

cash flows, anticipated liquidity, and the future repayment of debt;

business strategies and other plans and objectives for future operations, including plans for expansion
and growth of operations or to defer capital investment, and our outlook on our future financial
condition or results of operations; and

other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial
Condition and Results of Operations section in Item 7 of this report.

Our forward-looking statements are based on assumptions and analyses made by us in light of our

experience and our perception of historical trends, current conditions, expected future developments, and other
factors that we believe are appropriate under the circumstances. These statements are subject to a number of known
and unknown risks and uncertainties, which may cause our actual results and performance to be materially different
from any future results or performance expressed or implied by the forward-looking statements. These risks are
described in the Risk Factors section of this report, and include such factors as:

•

the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial
condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;

the continued weakness in economic conditions and uncertainty in financial markets;

our ability to replace reserves in order to sustain production;

our ability to raise the substantial amount of capital that is required to replace our reserves;

our ability to compete against competitors that have greater financial, technical, and human resources;

our ability to attract and retain key personnel;

the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL
reserves;

the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;

the possibility that exploration and development drilling may not result in commercially producible
reserves;

our limited control over activities on non-operated properties;

our reliance on the skill and expertise of third-party service providers on our operated properties;

the possibility that title to properties in which we have an interest may be defective;

the possibility that our planned drilling in existing or emerging resource plays using some of the latest
available horizontal drilling and completion techniques is subject to drilling and completion risks and
may not meet our expectations for reserves or production;

the uncertainties associated with divestitures, joint ventures, farm-downs, farm-outs and similar
transactions with respect to certain assets, including whether such transactions will be consummated or
completed in the form or timing and for the value that we anticipate;

•

the uncertainties associated with enhanced recovery methods;

•

our commodity derivative contracts may result in financial losses or may limit the prices that we
receive for oil, gas, and NGL sales;

the inability of one or more of our vendors, customers, or contractual counterparties to meet their
obligations;

price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;

the impact that lower oil, gas, or NGL prices could have on the amount we are able to borrow under our
credit facility;

the possibility that our amount of debt may limit our ability to obtain financing for acquisitions, make
us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments
on our debt;

operating and environmental risks and hazards that could result in substantial losses;

complex laws and regulations, including environmental regulations, that result in substantial costs and
other risks;

the availability and capacity of gathering, transportation, processing, and/or refining facilities;

our ability to sell and/or receive market prices for our oil, gas, and NGLs;

new technologies may cause our current exploration and drilling methods to become obsolete;

the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or
otherwise impacting, our facilities and systems; and

litigation, environmental matters, the potential impact of government regulations, and the use of
management estimates regarding such matters.

We caution you that forward-looking statements are not guarantees of future performance and that actual

results or performance may be materially different from those expressed or implied in the forward-looking
statements. The forward-looking statements in this report speak as of the filing date of this report. Although we
may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do
so except as required by securities laws.

Available Information

Our internet website address is www.sm-energy.com. We routinely post important information for investors
on our website. Within our website’s investor relations section, we make available free of charge our annual report
on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed
with or furnished to the SEC under applicable securities laws. These materials are made available as soon as
reasonably practical after we electronically file such materials with or furnish such materials to the SEC. We also
make available through our website’s corporate governance section our Corporate Governance Guidelines, Code of
Business Conduct and Ethics, Financial Code of Ethics, and the Charters of the Audit, Compensation, Executive,
and Nominating and Corporate Governance Committees of our Board of Directors. Information on our website is
not incorporated by reference into this report and should not be considered part of this document.

Glossary of Oil and Gas Terms

The oil and gas terms defined in this section are used throughout this report. The definitions of the terms

developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from
the respective definitions under SEC Rule 4-10(a) of Regulation S-X, as amended effective for fiscal years ending
on or after December 31, 2009. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be
located through the SEC’s website at www.sec.gov.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to oil or other liquid
hydrocarbons.

Bcf. Billion cubic feet, used in reference to natural gas.

BCFE. Billion cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six
Mcf of natural gas to one Bbl of oil or NGLs.

BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl
of oil or NGLs.

BTU. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water
by one degree Fahrenheit.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of
production.

Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing
equipment and operating methods or in which the cost of the required equipment is relatively minor compared to
the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of
the reserves estimate if the extraction is by means not involving a well.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a
stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing either oil, natural gas, and/or NGLs in commercial quantities.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir.

Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil
and natural gas) rights.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same
individual geological structural feature and/or stratigraphic condition.

Finding and development cost. Expressed in dollars per MCFE. Finding and development cost metrics provide
information as to the cost of adding proved reserves from various activities, and are widely utilized within the
exploration and production industry, as well as by investors. The information used to calculate these metrics is
included in the Supplemental Oil and Gas Information section in Part II, Item 8 of this report. It should be noted
that finding and development cost metrics have limitations. For example, exploration efforts related to a particular
set of proved reserve additions may extend over several years. As a result, the exploration costs incurred in earlier
periods are not included in the amount of exploration costs incurred during the period in which that set of proved
reserves is added. In addition, consistent with industry practice, future capital costs to develop proved undeveloped
reserves are not included in costs incurred. Since the additional development costs that will need to be incurred in

the future before the proved undeveloped reserves are ultimately produced are not included in the amount of costs
incurred during the period in which those reserves were added, those development costs in future periods will be
reflected in the costs associated with adding a different set of reserves. The calculations of various finding and
development cost metrics are explained below.

Finding and development cost – Drilling, excluding revisions. Calculated by dividing the amount of costs incurred
for development and exploration activities, by the amount of estimated net proved reserves added through
discoveries, extensions, and infill drilling, during the same period.

Finding and development cost – Drilling, including revisions. Calculated by dividing the amount of costs incurred
for development and exploration activities, by the amount of estimated net proved reserves added through
discoveries, extensions, infill drilling, and revisions of previous estimates, during the same period.

Finding and development cost – Drilling and acquisitions, excluding revisions. Calculated by dividing the amount
of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net
proved reserves added through discoveries, extensions, infill drilling, and acquisitions, during the same period.

Finding and development cost – Drilling and acquisitions, including revisions. Calculated by dividing the amount
of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net
proved reserves added through discoveries, extensions, infill drilling, revisions of previous estimates, and
acquisitions, during the same period.

Finding and development cost –All in, including sales of reserves. Calculated by dividing the amount of total
capital expenditures for oil and natural gas activities, by the amount of estimated net proved reserves added through
discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates less sales of reserves, during
the same period.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

Gross acre. An acre in which a working interest is owned.

Gross well. A well in which a working interest is owned.

Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical.

Lease operating expenses. The expenses incurred in the lifting of crude oil, natural gas, and/or associated liquids
from a producing formation to the surface, constituting part of the current operating expenses of a working interest,
and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other
expenses incidental to production, but not including lease acquisition, drilling, or completion costs.

MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.

MMBbl. One million barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet, used in reference to natural gas.

MCFE. One thousand cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio
of six Mcf of natural gas to one Bbl of oil or NGLs.

MMcf. One million cubic feet, used in reference to natural gas.

MMCFE. One million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio
of six Mcf of natural gas to one Bbl of oil or NGLs.

MMBtu. One million British thermal units.

Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells.

Net asset value per share. The result of the fair market value of total assets less total liabilities, divided by the total
number of outstanding shares of common stock.

NGLs. The combination of ethane, propane, butanes, and natural gasolines that when removed from natural gas
become liquid under various levels of higher pressures and lower temperatures.

NYMEX WTI. New York Mercantile Exchange West Texas Intermediate.

OPIS. Oil Price Information Service Mont Belvieu.

PV-10 value (Non-GAAP). The present value of estimated future gross revenue to be generated from the production
of estimated net proved reserves, net of estimated production and future development costs, based on prices used in
estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change
pursuant to contractual provisions), without giving effect to non-property related expenses such as general and
administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization,
discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income
taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does
provide an indicative representation of the relative value of the Company on a comparative basis to other companies
and from period to period. This is a Non-GAAP measure.

Productive well. A well that is producing crude oil, natural gas, and/or NGLs or that is capable of commercial
production of those products.

Proved reserves. Those quantities of oil, gas, and NGLs 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. Existing economic
conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the
price to be used is the average price during the 12-month period prior to the ending date of the period covered by
the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month
within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future
conditions.

Recompletion. The completion in an existing wellbore in a formation other than that in which the well has
previously been completed.

Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual
production for the preceding 12-month period.

Reserve replacement. Reserve replacement metrics are used as indicators of a company’s ability to replenish annual
production volumes and grow its reserves, and provide information related to how successful a company is at
growing its proved reserve base. These are believed to be useful non-GAAP measures that are widely utilized
within the exploration and production industry, as well as by investors. They are easily calculable metrics, and the
information used to calculate these metrics is included in the Supplemental Oil and Gas Information section of Part
II, Item 8 of this report. It should be noted that reserve replacement metrics have limitations. They are limited
because they typically vary widely based on the extent and timing of new discoveries and property acquisitions.
Their predictive and comparative value is also limited for the same reasons. In addition, because the metrics do not
embed the cost or timing of future production of new reserves, they cannot be used as a measure of value creation.
The calculations of various reserve replacement metrics are explained below.

Reserve replacement – Drilling, excluding revisions. Calculated as a numerator comprised of the sum of reserve
extensions and discoveries and infill reserves in an existing proved field divided by production for that same period.
This metric is an indicator of the relative success a company is having in replacing its production through drilling
activity.

Reserve replacement – Drilling, including revisions. Calculated as a numerator comprised of the sum of reserve
extensions, discoveries, and infill reserves, and revisions of previous estimates in an existing proved field divided
by production for that same period. This metric is an indicator of the relative success a company is having in
replacing its production through drilling activity with an adjustment for revisions.

Reserve replacement – Drilling and acquisitions, excluding revisions. Calculated as a numerator comprised of the
sum of reserve acquisitions and reserve extensions, discoveries, and infill reserves in an existing proved field
divided by production for that same period. This metric is an indicator of the relative success a company is having
in replacing its production through drilling and acquisition activities.

Reserve replacement – Drilling and acquisitions, including revisions. Calculated as a numerator comprised of the
sum of reserve acquisitions and reserve extensions, discoveries, and infill reserves, and revisions of previous
estimates in an existing proved field divided by production for that same period. This metric is an indicator of the
relative success a company is having in replacing its production through drilling and acquisition activities with an
adjustment for revisions.

Reserve replacement percentage – All in, excluding sales of reserves. The sum of reserve extensions and
discoveries, infill drilling, reserve acquisitions, and reserve revisions of previous estimates for a specified period of
time divided by production for that same period.

Reserve replacement percentage –All in, including sales of reserves. The sum of sales of reserves, infill drilling,
reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified
period of time divided by production for that same period.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude
oil, natural gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is
individual and separate from other reservoirs.

Resource play. A term used to describe an accumulation of crude oil, natural gas, and/or associated liquid resources
known to exist over a large areal expanse, which when compared to a conventional play typically has a lower
expected geological and/or commercial development risk.

Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross
income from crude oil, natural gas, and NGLs produced and sold unencumbered by expenses relating to the drilling,
completing, and operating of the affected well.

Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of crude oil, natural gas,
and NGL production free of costs of exploration, development, and production operations.

Seismic. The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the
type, size, shape, and depth of subsurface rock formations.

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently
occurring sedimentary rock.

Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved
reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10 percent
annual discount rate. The information for this calculation is included in the supplemental information regarding
disclosures about oil and gas producing activities following the Notes to Consolidated Financial Statements
included in this report.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage
contains estimated net proved reserves.

Undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be
classified as having undeveloped reserves only if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating
activities on the property and to share in the production, sales, and costs.

ITEM 1A.

RISK FACTORS

In addition to the other information included in this report, the following risk factors should be carefully

considered when evaluating an investment in us.

Risks Related to Our Business

Crude oil, natural gas, and NGL prices are volatile, and declines in prices adversely affect our profitability,
financial condition, cash flows, access to capital, and ability to grow.

Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and

natural gas properties depend heavily on the prices we receive for crude oil, natural gas and NGL sales. Crude oil,
natural gas, and NGL prices also affect our cash flows available for capital expenditures and other items, our
borrowing capacity, and the amount and value of our crude oil, natural gas, and NGL reserves. For example, the
amount of our borrowing base under our credit facility is subject to periodic redeterminations based on crude oil,
natural gas, and NGL prices specified by our bank group at the time of redetermination. In addition, we may have
crude oil and natural gas property impairments or downward revisions of estimates of proved reserves if prices fall
significantly.

Historically, the markets for crude oil, natural gas, and NGLs have been volatile, and they are likely to
continue to be volatile. Wide fluctuations in crude oil, natural gas, and NGL prices may result from relatively
minor changes in the supply of and demand for crude oil, natural gas, and NGLs, market uncertainty, and other
factors that are beyond our control, including:

•

global and domestic supplies of crude oil, natural gas, and NGLs, and the productive capacity of the
industry as a whole;

the level of consumer demand for crude oil, natural gas, and NGLs;

overall global and domestic economic conditions;

• weather conditions;

•

the availability and capacity of gathering, transportation, processing, and/or refining facilities in
regional or localized areas that may affect the realized price for crude oil, natural gas, or NGLs;

liquefied natural gas deliveries to and from the United States;

the price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural
gas;

the price and availability of alternative fuels;

technological advances and regulations affecting energy consumption and conservation;

the ability of the members of the Organization of Petroleum Exporting Countries and other exporting
countries to agree to and maintain crude oil price and production controls;

political instability or armed conflict in crude oil or natural gas producing regions;

strengthening and weakening of the United States dollar relative to other currencies; and

governmental regulations and taxes.

These factors and the volatility of crude oil, natural gas, and NGL markets make it extremely difficult to
predict future crude oil, natural gas, and NGL price movements with any certainty. Declines in crude oil, natural
gas, and NGL prices would reduce our revenues and could also reduce the amount of crude oil, natural gas, and
NGLs that we can produce economically, which could have a materially adverse effect on us.

Continued weakness in economic conditions or uncertainty in financial markets may have material adverse impacts
on our business that we cannot predict.

United States and global economies and financial systems have recently experienced turmoil and upheaval
characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability,
inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, increased levels
of unemployment, and an unprecedented level of intervention by the United States federal government and other
governments. Although some portions of the economy appear to have stabilized and there have been signs of the
beginning of a recovery, the extent and timing of a recovery, and whether it can be sustained, are uncertain.
Continued weakness in the United States or other large economies could materially adversely affect our business
and financial condition. For example:

•

the demand for crude oil, natural gas, and NGLs in the United States has declined and may remain at
low levels or further decline if economic conditions remain weak, and continue to negatively impact
our revenues, margins, profitability, operating cash flows, liquidity, and financial condition;

natural gas prices have recently been lower than at various times in the last decade because of increased
supply resulting from, among other things, increased drilling in unconventional reservoirs, and reduced
demand in connection with the recent recession, which sustained low prices could affect our financial
condition and results of operations;

the tightening of credit or lack of credit availability to our customers could adversely affect our ability
to collect our trade receivables;

the liquidity available under our credit facility could be reduced if any lender is unable to fund its
commitment;

our ability to access the capital markets may be restricted at a time when we would like, or need, to
raise capital for our business, including for exploration and/or development of our reserves;

our commodity derivative contracts could become economically ineffective if our counterparties are
unable to perform their obligations or seek bankruptcy protection; and

variable interest rate spread levels, including for LIBOR and the prime rate, could increase
significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings
under our credit facility.

If we are unable to replace reserves, we will not be able to sustain production.

Our future operations depend on our ability to find, develop, or acquire crude oil, natural gas, and NGL

reserves that are economically producible. Our properties produce crude oil, natural gas, and NGLs at a declining
rate over time. In order to maintain current production rates, we must locate and develop or acquire new crude oil,
natural gas, and NGL reserves to replace those being depleted by production. In addition, competition for crude oil
and natural gas properties is intense, and many of our competitors have financial, technical, human, and other
resources needed to evaluate and integrate acquisitions that are substantially greater than those available to us.

In the event we do complete an acquisition, its successful impact on our business will depend on a number

of factors, many of which are beyond our control. These factors include the purchase price, future crude oil, natural

gas, and NGL prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future
production and future net revenues attainable from reserves, future operating and capital costs, results of future
exploration, exploitation and development activities on the acquired properties, and future abandonment and
possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities
of proved oil and gas reserves, actual future production rates, and associated costs and potential liabilities with
respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the
estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.

Additionally, significant acquisitions can change the nature of our operations and business depending upon
the character of the acquired properties if they have substantially different operating and geological characteristics
or are in different geographic locations than our existing properties. To the extent that acquired properties are
substantially different than our existing properties, our ability to efficiently realize the expected economic benefits
of such transactions may be limited.

Integrating acquired businesses and properties involves a number of special risks. These risks include the
possibility that management may be distracted from regular business concerns by the need to integrate operations
and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and
assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term
effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the
acquisitions. Without successful drilling or acquisition activities, our reserves and production will decline over
time.

Substantial capital is required to replace our reserves.

We must make substantial capital expenditures to find, acquire, develop, and produce crude oil, natural gas,

and NGL reserves. Future cash flows and the availability of financing are subject to a number of factors, such as
the level of production from existing wells, prices received for crude oil, natural gas, and NGL sales, our success in
locating and developing and acquiring new reserves, and the orderly functioning of credit and capital markets. If
crude oil, natural gas, and NGL prices decrease or if we encounter operating difficulties that result in our cash flows
from operations being less than expected, we must reduce our capital expenditures unless we can raise additional
funds through debt or equity financing or the divestment of assets. Debt or equity financing may not always be
available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestitures
may not always be of acceptable value to us.

If our revenues decrease due to lower crude oil, natural gas, or NGL prices, decreased production, or other

reasons, and if we cannot obtain funding through our credit facility, other acceptable debt or equity financing
arrangements, or through the sale of assets, our ability to execute development plans, replace our reserves, maintain
our acreage, or maintain production levels could be greatly limited.

Competition in our industry is intense, and many of our competitors have greater financial, technical, and human
resources than we do.

We face intense competition from major oil and gas companies, independent oil and gas exploration and

production companies, financial buyers, and institutional and individual investors who seek oil and gas investments
throughout the world, as well as the equipment, expertise, labor, and materials required to operate crude oil and
natural gas properties. Many of our competitors have financial, technical, and other resources vastly exceeding
those available to us, and many crude oil and natural gas properties are sold in a competitive bidding process in
which our competitors may be able and willing to pay more for development prospects and productive properties, or
in which our competitors have technological information or expertise that is not available to us to evaluate and
successfully bid for the properties. In addition, shortages of equipment, labor, or materials as a result of intense
competition may result in increased costs or the inability to obtain those resources as needed. We may not be
successful in acquiring and developing profitable properties in the face of this competition.

We also compete for human resources. Over the last few years, the need for talented people across all
disciplines in the industry has grown, while the number of talented people available has not grown at the same pace,
and in many cases, is declining due to the demographics of the industry.

The loss of key personnel could adversely affect our business.

We depend to a large extent on the efforts and continued employment of our executive management team

and other key personnel. The loss of the services of these or other key personnel could adversely affect our
business. Our drilling success and the success of other activities integral to our operations will depend, in part, on
our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for
many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced
technical personnel and professionals, our ability to compete could be harmed.

The actual quantities and present value of our proved crude oil, natural gas, and NGL reserves may be less than we
have estimated.

This report and other of our SEC filings contain estimates of our proved crude oil, natural gas, and NGL

reserves and the estimated future net revenues from those reserves. These estimates are based on various
assumptions, including assumptions required by the SEC relating to crude oil, natural gas, and NGL prices, drilling
and completion costs, gathering and transportation costs, operating expenses, capital expenditures, effects of
governmental regulation, taxes, timing of operations, and availability of funds. The process of estimating crude oil,
natural gas, and NGL reserves is complex. The process involves significant decisions and assumptions in the
evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates
are dependent on many variables, and therefore changes often occur as our knowledge of these variables evolve.
Therefore, these estimates are inherently imprecise. In addition, the reserve estimates we make for properties that
do not have a significant production history may be less reliable than estimates for properties with lengthy
production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves,
future production rates, and the timing of development expenditures.

Actual future production, prices for crude oil, natural gas, and NGLs, revenues, production taxes,

development expenditures, operating expenses, and quantities of producible crude oil, natural gas, and NGL
reserves will most likely vary from those estimated. Any significant variance of any nature could materially affect
the estimated quantities of and present value related to proved reserves disclosed by us, and the actual quantities
and present value may be significantly less than we have previously estimated. In addition, we may adjust
estimates of proved reserves to reflect production history, results of exploration, operations and development
activity, prevailing crude oil, natural gas, and NGL prices, costs to develop and operate properties, and other factors,
many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from
production on adjacent properties.

As of December 31, 2012, 43 percent, or 761.5 BCFE, of our estimated proved reserves were proved
undeveloped, and two percent, or 40.8 BCFE, were proved developed non-producing. In order to develop our
proved undeveloped reserves, as of December 31, 2012, we estimate approximately $1.6 billion of capital
expenditures would be required. Production revenues from proved developed non-producing reserves will not be
realized until sometime in the future and after some investment of capital. In order to develop our proved
developed non-producing reserves, as of December 31, 2012, we estimate capital expenditures of approximately
$30 million would be required. Although we have estimated our proved reserves and the costs associated with these
proved reserves in accordance with industry standards, estimated costs may not be accurate, development may not
occur as scheduled, and actual results may not occur as estimated.

You should not assume that the PV-10 value and standardized measure of discounted future net cash flows
included in this report represent the current market value of our estimated proved crude oil, natural gas, and NGL
reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and
cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower.
For example, values of our reserves as of December 31, 2012, were estimated using a calculated 12-month average
sales price of $2.76 per MMBtu of natural gas (NYMEX Henry Hub spot price), $94.71 per Bbl of oil (NYMEX
WTI spot price), and $45.65 per Bbl of NGL (OPIS spot price). We then adjust these base prices to reflect
appropriate basis, quality, and location differentials over that period in estimating our proved reserves. During
2012, our monthly average realized natural gas prices, excluding the effect of derivative cash settlements, were as
high as $3.79 per Mcf and as low as $2.18 per Mcf. For the same period, our monthly average realized crude oil
prices before the effect of derivative cash settlements were as high as $92.23 per Bbl and as low as $71.33 per Bbl,
and were as high as $47.08 per Bbl and as low as $27.84 per Bbl for NGLs. Many other factors will affect actual
future net cash flows, including:

•

amount and timing of actual production;

supply and demand for crude oil, natural gas, and NGLs;

curtailments or increases in consumption by oil purchasers and natural gas pipelines; and

changes in government regulations or taxes, including severance and excise taxes.

The timing of production from oil and natural gas properties and of related expenses affects the timing of
actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash
flows could be less than the estimated future net cash flows for purposes of computing the PV-10 value. In
addition, the 10 percent discount factor required by the SEC to be used to calculate the PV-10 value for reporting
purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and
other risks to which our business and the oil and natural gas industry in general are subject.

Our property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves
and other expected benefits, as well as potential liabilities.

Successful property acquisitions require an assessment of a number of factors sometimes beyond our

control. These factors include exploration potential, future crude oil, natural gas, and NGL prices, operating costs,
and potential environmental and other liabilities. These assessments are not precise and their accuracy is inherently
uncertain.

In connection with our acquisitions, we typically perform a customary review of the acquired properties

that will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully
assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well
we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be
entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we
acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and
warranties.

In addition, significant acquisitions can change the nature of our operations and business if the acquired

properties have substantially different operating and geological characteristics or are in different geographic
locations than our existing properties. To the extent acquired properties are substantially different than our existing
properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be limited.

Integrating acquired properties and businesses involves a number of other special risks, including the risk

that management may be distracted from normal business concerns by the need to integrate operations and systems
as well as retain and assimilate additional employees. Therefore, we may not be able to realize all of the anticipated
benefits of our acquisitions.

We have limited control over the activities on properties we do not operate.

Some of our properties, including a portion of our operations in the Eagle Ford shale in South Texas, are

operated by other companies and involve third-party working interest owners. As a result, we have limited ability
to influence or control the operation or future development of such properties, including the nature and timing of
drilling and operational activities, the operator’s skill and expertise, compliance with environmental, safety and
other regulations, the approval of other participants in such properties, the selection and application of suitable
technology, or the amount of capital expenditures that we will be required to fund with respect to such properties.
Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of
the capital expenditures of such projects. These limitations and our dependence on the operator and other working
interest owners for these projects could cause us to incur unexpected future costs and materially and adversely
affect our financial condition and results of operations.

We rely on third-party service providers to conduct the drilling and completion operations on properties we
operate.

Where we are the operator of a property, we rely on third-party service providers to perform necessary

drilling and completion operations. The ability of third-party service providers to perform such drilling and
completion operations will depend on those service providers’ ability to compete for and retain qualified personnel,
financial condition, economic performance, and access to capital, which in turn will depend upon the supply and
demand for oil, natural gas liquids and natural gas, prevailing economic conditions and financial, business and other
factors. The failure of a third-party service provider to adequately perform operations could delay drilling or
completion or reduce production from the property and adversely affect our financial condition and results of
operations.

Title to the properties in which we have an interest may be impaired by title defects.

We generally rely on title reports in acquiring oil and gas leasehold interests and obtain title opinions only

on significant properties that we drill. There is no assurance that we will not suffer a monetary loss from title
defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage.
Title insurance is not available for oil and gas properties. As is customary in our industry, we rely upon the
judgment of staff and independent landmen who perform the field work of examining records in the appropriate
governmental offices and title abstract facilities before attempting to acquire or place under lease a specific mineral
interest and/or undertake drilling activities. We, in some cases, perform curative work to correct deficiencies in the
marketability of the title to us. Generally, under the terms of the operating agreements affecting our properties, any
monetary loss attributable to a loss of title is to be borne by all parties to any such agreement in proportion to their
interests in such property. A material title defect can reduce the value or render a property worthless, thus adversely
affecting our financial condition, results of operations and operating cash flow if such property is of sufficient
value.

Exploration and development drilling may not result in commercially producible reserves.

Crude oil and natural gas drilling and production activities are subject to numerous risks, including the risk
that no commercially producible crude oil, natural gas, or associated liquids will be found. The cost of drilling and
completing wells is often uncertain, and crude oil, natural gas or associated liquids drilling and production activities
may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control.
These factors include:

•

unexpected drilling conditions;

title problems;

disputes with owners or holders of surface interests on or near areas where we operate;

pressure or geologic irregularities in formations;

engineering and construction delays;

equipment failures or accidents;

hurricanes or other adverse weather conditions;

compliance with environmental and other governmental requirements; and

shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture
stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.

The prevailing prices for crude oil, natural gas, and NGLs affect the cost of and the demand for drilling

rigs, completion and production equipment, and other related services. However, changes in costs may not occur
simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary
significantly from region to region at any particular time. Although land drilling rigs can be moved from one region
to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling
delays and higher drilling costs for the rigs that are available in that region. In addition, the recent economic and
financial downturn has adversely affected the financial condition of some drilling contractors, which may constrain
the availability of drilling services in some areas.

Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local,
and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays
that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods,
the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs
could have a materially adverse effect on our ability to explore on or develop our properties.

The wells we drill may not be productive, and we may not recover all or any portion of our investment in

such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a
well if crude oil, natural gas, or NGLs are present, or whether they can be produced economically. The cost of
drilling, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of
a project. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net
revenues after operating and other costs to cover drilling and completion costs. Even if sufficient amounts of crude
oil, natural gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation or
experience mechanical difficulties while drilling or completing a well, resulting in a reduction in or no production
from the well, significant expense to repair the well, or the loss and abandonment of the well.

Drilling results in our newer shale plays may be more uncertain than results in shale plays that are more

developed and have longer established production histories. For example, our experience with horizontal drilling in
the Eagle Ford shale play, as well as the industry’s drilling and production history, is more limited than in many
shale plays, such as the Barnett or Woodford shales, and we and the industry generally have less information with
respect to the ultimate recoverability of reserves and the production decline rates in these shales than other areas
with longer histories of drilling and production. Completion techniques that have proven to be successful in other
shale formations to maximize recoveries are being used in the early development of these new shales; however, we
can provide no assurance of the ultimate success of these drilling and completion techniques.

In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such

multi-year drilling inventories can be more susceptible to long-term uncertainties that could materially alter the
occurrence or timing of actual drilling. Because of these uncertainties, we do not know if the potential drilling
locations we have identified will ever be drilled, although we have the present intent to do so, or if we will be able
to produce crude oil, natural gas, or NGLs from these or any other potential drilling locations.

Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success

rate within a particular area may decline. In addition, we may not be able to obtain any options or lease rights in
potential drilling locations that we identify. Unless production is established within the spacing units covering
undeveloped acres on which our drilling locations are identified, the leases for such acreage will expire and we
would lose our right to develop the related properties. Our total net acreage expiring in the next three years
represents approximately 27 percent of our total net undeveloped acreage at December 31, 2012. Although we have
identified numerous potential drilling locations, we may not be able to economically produce crude oil, natural gas,
or NGLs from all of them and our actual drilling activities may materially differ from those presently identified,
which could adversely affect our financial condition, results of operations and operating cash flow.

Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available
horizontal drilling and completion techniques. The results of our planned exploratory and delineation drilling in
these plays are subject to drilling and completion technique risks, and drilling results may not meet our
expectations for reserves or production. As a result, we may incur material write-downs, and the value of our
undeveloped acreage could decline if drilling results are unsuccessful.

Many of our operations involve utilizing the latest drilling and completion techniques as developed by us
and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible
returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling
zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the
entire length of the well bore, and being able to run tools and recover equipment consistently through the horizontal
well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture
stimulate the planned number of stages, being able to run tools and other equipment the entire length of the well
bore during completion operations, being able to recover such tools and other equipment, and successfully cleaning
out the well bore after completion of the final fracture stimulation.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more

wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results
are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease
expirations, limited access to gathering systems and takeaway capacity, and/or prices for crude oil, natural gas, and
NGL decline, then the return on our investment for a particular project may not be as attractive as we anticipated
and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could
decline in the future.

Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on
our investments in such projects.

We inject water into formations on some of our properties to increase the production of crude oil, natural
gas, and associated liquids. We may in the future expand these efforts to more of our properties or employ other
enhanced recovery methods in our operations. The additional production and reserves, if any, attributable to the use
of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow
for the extraction of crude oil, natural gas, and associated liquids in a manner or to the extent that we anticipate, we
may not realize an acceptable return on our investments in such projects. In addition, if proposed legislation and
regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery
methods could increase substantially.

Our commodity derivative contract activities may result in financial losses or may limit the prices that we receive
for crude oil, natural gas, and NGL sales.

To mitigate a portion of the exposure to potentially adverse market changes in crude oil, natural gas, and
NGL prices and the associated impact on cash flows, the Company has entered into various derivative contracts.
The Company’s derivative contracts in place include swap and collar arrangements for crude oil, natural gas, and
NGLs. As of December 31, 2012, we were in a net accrued asset position of $38.7 million with respect to our crude
oil, natural gas, and NGL derivative activities. These activities may expose us to the risk of financial loss in certain
circumstances, including instances in which:

•

our production is less than expected;

one or more counterparties to our commodity derivative contracts default on their contractual
obligations; or

there is a widening of price differentials between delivery points for our production and the delivery
point assumed in the commodity derivative contract arrangement.

The risk of one or more counterparties defaulting on their obligations is heightened by the recent global and

domestic economic and financial downturn affecting many banks and other financial institutions, including our
counterparties and their affiliates. These circumstances may adversely affect the ability of our counterparties to
meet their obligations to us pursuant to derivative transactions, which could reduce our revenues and cash flows
from realized derivative cash settlements. As a result, our financial condition, results of operations, and cash flows
could be materially affected in an adverse way if our counterparties default on their contractual obligations under
our commodity derivative contracts.

In addition, commodity derivative contracts may limit the prices that we receive for our crude oil, natural

gas and NGL sales if crude oil, natural gas, or NGL prices rise substantially over the price established by the
commodity derivative contract.

The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial
results.

Substantially all of our accounts receivable result from crude oil, natural gas, and NGL sales or joint
interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint
interest owners may impact our overall credit risk because these entities may be similarly affected by various
economic and other conditions, including the recent global and domestic economic and financial downturn.

In addition, for the year ended December 31, 2012, we had two major customers, Regency Gas Services

LLC and Plains Marketing LP, which accounted for approximately 21 percent and 13 percent, respectively, of our
total production revenue. During 2011 and 2010, we had one major customer, Regency Gas Services LLC,
individually account for approximately 18 percent and 11 percent, respectively, of our total production revenue.
The loss of one or more of these customers could reduce competition for our products and negatively impact the
prices at which we sell such products.

We have entered into firm transportation contracts that require us to pay fixed amounts of money to our
counterparties regardless of quantities actually shipped, processed, or gathered. If we are unable to deliver the
necessary quantities of natural gas to our counterparties, our results of operations and liquidity could be adversely
affected.

As of December 31, 2012, we were contractually committed to deliver 1,515 Bcf of natural gas and 36
MMBbls of oil pursuant to contracts expiring at various dates through 2023. We may enter into additional firm
transportation agreements as our development of our shale plays, including the Eagle Ford and Haynesville shales,
expand. At the current time, we do not have enough proved developed reserves to offset these contractual
liabilities, but we intend to develop reserves that will exceed the commitments and therefore do not expect any
shortfalls. We expect our production volumes, as well as that of our competitors, to increase significantly in the
Eagle Ford shale. The use of firm transportation commitments gives us the strategic advantage of priority space in
a transportation pipeline. In the event we encounter delays in drilling and completing our wells or otherwise due to
construction, interruptions of operations, or delays in connecting new volumes to gathering systems or pipelines for
an extended period of time, the requirements to pay for quantities not delivered could have a material impact on our
results of operations and liquidity.

Future crude oil, natural gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs
of our asset carrying values.

We follow the successful efforts method of accounting for our crude oil and natural gas properties. All

property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending
the determination of whether proved reserves have been discovered. If commercial quantities of hydrocarbons are
not discovered with an exploratory well, the costs of drilling the well are expensed.

The capitalized costs of our crude oil, natural gas, and NGL properties, on a depletion pool basis, cannot

exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed
undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated
discounted future net cash flows of that depletion pool. Unproved properties are evaluated at the lower of cost or
fair market value. We incurred an impairment of proved property and impairment of unproved properties totaling
$208.9 million and $16.3 million, respectively, during 2012, $219.0 million and $7.4 million, respectively, during
2011, and $6.1 million and $2.0 million, respectively, during 2010. Significant further declines in crude oil, natural
gas, or NGL prices in the future or unsuccessful exploration efforts could cause further impairment write-downs of
capitalized costs.

We review the carrying value of our properties for indicators of impairment on a quarterly basis using the
prices in effect as of the end of each quarter. Once incurred, a write-down of oil and natural gas properties cannot
be reversed at a later date, even if crude oil, natural gas, or NGL prices increase.

Lower crude oil, natural gas, or NGL prices could limit our ability to borrow under our credit facility.

Our credit facility has a current commitment amount of $1.0 billion, subject to a borrowing base that the

lenders redetermine semi-annually based largely on the bank group’s assessment of the value of our crude oil,
natural gas, and NGL properties, which in turn is impacted by crude oil, natural gas, and NGL prices. The current
borrowing base under our credit facility is $1.55 billion. Declines in crude oil, natural gas, or NGL prices in the
future could limit our borrowing base and reduce the amount we can borrow under our credit facility. Additionally,
divestitures of properties could result in a reduction of our borrowing base.

Our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse
economic conditions, and make it more difficult for us to make payments on our debt.

As of December 31, 2012, we had $350.0 million of long-term senior unsecured debt outstanding relating

to our 6.625% Senior Notes due 2019 (the “2019 Notes”) that we issued on February 7, 2011; $350.0 million of
long-term senior unsecured debt outstanding relating to our 6.50% Senior Notes due 2021 (the “2021 Notes”) that
we issued on November 8, 2011; and $400.0 million of long-term senior unsecured debt outstanding relating to our
6.50% Senior Notes due 2023 (the “2023 Notes”) that we issued on June 29, 2012, (collectively referred to as our
“Senior Notes”); and $340.0 million of outstanding borrowings under our secured credit facility. We had three
outstanding letters of credit in the aggregate amount of $808,000, (which reduce the amount available for
borrowings under the facility on a dollar-for-dollar basis), resulting in $659.2 million of available debt capacity
under our credit facility, assuming the borrowing conditions under this facility will be met. Our long-term debt
represented 50 percent of our total book capitalization as of December 31, 2012.

Our indebtedness could have important consequences for our operations, including:

• making it more difficult for us to obtain additional financing in the future for our operations and

potential acquisitions, working capital requirements, capital expenditures, debt service, or other general
corporate requirements;

•

requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our
debt and the service of interest costs associated with our debt, rather than to productive investments;

limiting our operating flexibility due to financial and other restrictive covenants, including restrictions
on incurring additional debt, making acquisitions, and paying dividends;

•

placing us at a competitive disadvantage compared to our competitors that have less debt; and

• making us more vulnerable in the event of adverse economic or industry conditions or a downturn in

our business.

Our ability to make payments on our debt and to refinance our debt and fund planned capital expenditures

will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic,
financial, competitive, legislative, regulatory, and other factors that are beyond our control. If our business does not
generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our credit
facility or from other sources, we might not be able to service our debt or fund our other liquidity needs. If we are
unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions,
defer capital expenditures, sell equity securities, divest assets, or restructure or refinance our debt. We might not be
able to sell our equity securities, sell our assets, or restructure or refinance our debt on a timely basis or on
satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our existing
and future credit agreements, may prohibit us from pursuing any of these alternatives. Further, changes in the credit
ratings of our debt may negatively affect the cost, terms, conditions, and availability of future financing.

Our debt agreements, including the agreement governing our credit facility and the indentures governing

the 2019 Notes, 2021 Notes, and 2023 Notes, permit us to incur additional debt in the future, subject to compliance
with restrictive covenants under those agreements. In addition, entities we may acquire in the future could have
significant amounts of debt outstanding that we could be required to assume, and in some cases accelerate
repayment thereof, in connection with the acquisition, or we may incur our own significant indebtedness to
consummate an acquisition.

As discussed above, our credit facility is subject to periodic borrowing base redeterminations. We could be

forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing
base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds
and are otherwise unable to negotiate renewals of our borrowing base or arrange new financing, we may be forced
to sell significant assets.

The agreements governing our debt contain various covenants that limit our discretion in the operation of our
business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the
accelerated repayment of our debt.

Our debt agreements contain restrictive covenants that limit our ability to engage in activities that may be in

our long-term best interests. Our ability to borrow under our credit facility is subject to compliance with certain
financial covenants, including (i) maintenance of a quarterly ratio of total debt to consolidated earnings before
interest, taxes, depreciation, amortization, and exploration expense of no greater than 4.0 to 1.0, and (ii)
maintenance of an adjusted current ratio of no less than 1.0 to 1.0, each as defined in our credit facility. Our credit
facility also requires us to comply with certain financial covenants, including requirements that we maintain certain
levels of stockholders’ equity and limit our annual cash dividends to no more than $50.0 million. These restrictions
on our ability to operate our business could seriously harm our business by, among other things, limiting our ability
to take advantage of financings, mergers and acquisitions, and other corporate opportunities.

The respective indentures governing the 2019 Notes, 2021 Notes, and 2023 Notes also contain covenants

that, among other things, limit our ability and the ability of our subsidiaries to:

•

incur additional debt;

make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem,
or retire capital stock;

sell assets, including capital stock of our subsidiaries;

restrict dividends or other payments of our subsidiaries;

create liens that secure debt;

enter into transactions with affiliates; and

merge or consolidate with another company.

Our failure to comply with these covenants could result in an event of default that, if not cured or waived,

could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to
satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding
indebtedness.

We are subject to operating and environmental risks and hazards that could result in substantial losses.

Crude oil and natural gas operations are subject to many risks, including human error and accidents that

could cause personal injury, death and property damage, well blowouts, craterings, explosions, uncontrollable flows
of crude oil, natural gas and associated liquids or well fluids, migration of fracture fluids into surrounding
groundwater, spills or releases from facilities and equipment used to deliver these materials, spills or releases of
brine or other produced or flowback water, subsurface conditions that prevent us from stimulating the planned
number of stages, accessing the entirety of the wellbore with our tools during completion, or removing fracturing
materials from the wellbore to allow production to begin, fires, adverse weather such as hurricanes in the South
Texas & Gulf Coast region, freezing conditions in the Williston Basin of our Rocky Mountain region, floods,
droughts, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas such as
hydrogen sulfide, and other environmental risks and hazards. If any of these types of events occurs, we could
sustain substantial losses.

Furthermore, if we experience any of the problems with well stimulation and completion activities

referenced above, such as hydraulic fracturing, our ability to explore for and produce crude oil, natural gas, or
NGLs may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular
formations as a result of the need to shutdown, abandon and relocate drilling operations, the need to sample, test
and monitor drinking water in particular areas and to provide filtration or other drinking water supplies to users of
water supplies that may have been impacted or threatened by potential contamination from fracturing fluids, the
need to modify drill sites to ensure there are no spills or releases off-site and to investigate and/or remediate any
spills or releases that might have occurred, and suspension of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our
current and past generation, handling and disposal of materials, including solid and hazardous wastes and petroleum
hydrocarbons. We may incur joint and several, strict liability under applicable United States federal and state
environmental laws in connection with releases of petroleum hydrocarbons and other hazardous substances at, on,
under or from our leased or owned properties, some of which have been used for natural gas and oil exploration and
production activities for a number of years, often by third parties not under our control. For our non-operated
properties, we are dependent on the operator for operational and regulatory compliance, and could be subject to
liabilities in the event of non-compliance. These properties and the wastes disposed thereon or away from could be
subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are
strict liability laws without regard to fault or the legality of the original conduct, including the CERCLA or the
Superfund law, the RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under any
implementing regulations, we could be required to remove or remediate previously disposed wastes (including
wastes disposed of or released by prior owners or operators) or property contamination (including groundwater
contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or
closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners
and other third parties to file claims for personal injury or property damage allegedly caused by the release of
petroleum hydrocarbons or other wastes into the environment. As a result, we may incur substantial liabilities to
third parties or governmental entities, which could reduce or eliminate funds available for exploration,
development, or acquisitions, or cause us to incur losses.

We maintain insurance against some, but not all, of these potential risks and losses. We have significant but
limited coverage for sudden environmental damage. We do not believe that insurance coverage for the full potential
liability that could be caused by sudden environmental damage or insurance coverage for environmental damage
that occurs over time is available at a reasonable cost. In addition, pollution and environmental risks generally are
not fully insurable. Further, we may elect not to obtain other insurance coverage under circumstances where we
believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly,
we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a
significant accident or other event occurs and is not fully covered by insurance, we could suffer a material loss.

Following the severe Atlantic hurricanes in 2004, 2005, and 2008, the insurance markets suffered
significant losses. As a result, insurance coverage for wind storms has become substantially more expensive, and
future availability and costs of coverage are uncertain.

Our operations are subject to complex laws and regulations, including environmental regulations that result in
substantial costs and other risks.

Federal, state, tribal, and local authorities extensively regulate the oil and natural gas industry. Legislation
and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility
of changes that may become more stringent and, as a result, may affect, among other things, the pricing or
marketing of crude oil, natural gas and NGL production. Noncompliance with statutes and regulations and more
vigorous enforcement of such statutes and regulations by regulatory agencies may lead to substantial administrative,
civil, and criminal penalties, including the assessment of natural resource damages, the imposition of significant
investigatory and remedial obligations and may also result in the suspension or termination of our operations. The
overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and
abandon wells and related facilities and, in turn, decreases profitability.

Governmental authorities regulate various aspects of drilling for and the production of crude oil, natural

gas, and NGLs, including the permit and bonding requirements of drilling wells, the spacing of wells, the
unitization or pooling of interests in crude oil and natural gas properties, rights-of-way and easements,
environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging,
abandonment, and restoration standards, oil and gas operations, and restoration. Public interest in environmental
protection has increased in recent years, and environmental organizations have opposed, with some success, certain
projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or
impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively
affect our ability to explore or develop certain properties. Federal authorities also may require any of our ongoing
or planned operations on federal leases to be delayed, suspended, or terminated. Any such delay, suspension, or
termination could have a materially adverse effect on our operations.

Our operations are also subject to complex and constantly changing environmental laws and regulations

adopted by federal, state, tribal and local governmental authorities in jurisdictions where we are engaged in
exploration or production operations. New laws or regulations, or changes to current requirements, including the
designation of previously unprotected wildlife or plant species as threatened or endangered in areas we operate,
could result in material costs or claims with respect to properties we own or have owned. We will continue to be
subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state
and federal agencies. Under existing or future environmental laws and regulations, we could incur significant
liability, including joint and several, strict liability under federal, state, and tribal environmental laws for noise
emissions and for discharges of crude oil, natural gas, and associated liquids or other pollutants into the air, soil,
surface water, or groundwater. We could be required to spend substantial amounts on investigations, litigation, and
remediation for these emissions and discharges and other compliance issues. Any unpermitted release of petroleum
or other pollutants from our operations could result not only in cleanup costs, but also natural resources, real or
personal property and other compensatory damages and civil and criminal liability. The listing of additional
wildlife or plant species as federally endangered or threatened could result in limitations on exploration and
production activities in certain locations. Existing environmental laws or regulations, as currently interpreted or
enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect on
us.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some
of the areas where we operate.

Operations in certain of our regions, such as our Rocky Mountain and Permian regions, are adversely
affected by seasonal weather conditions and lease stipulations designed to protect various wildlife or plant species.
In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during

limited times of the year. This limits our ability to operate in those areas and can intensify competition during those
times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic
shortages. Wildlife seasonal restrictions may limit access to federal leases or across federal lands. Possible
restrictions may include seasonal restrictions in greater sage-grouse habitat during breeding and nesting seasons,
within a certain distance of active raptor nests during fledging, and in big game winter or parturition ranges during
winter or calving seasons. These constraints and the resulting shortages or high costs could delay our operations
and materially increase our operating and capital costs.

Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in
increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate

production of oil, natural gas and associated liquids from dense subsurface rock formations. We routinely apply
hydraulic fracturing techniques to many of our oil and natural gas properties, including our unconventional resource
plays in the Granite Wash of Texas and Oklahoma, the Eagle Ford shale of south Texas, and the Bakken/Three
Forks formations in North Dakota. Hydraulic fracturing involves using water, sand, and certain chemicals to
fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process
is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory
authority over certain hydraulic fracturing activities involving the use of diesel in the fluid system under SDWA and
has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In
addition, legislation has been introduced before Congress during prior sessions and is likely to be introduced during
the 113th Congress, to provide for federal regulation of hydraulic fracturing and to require disclosure of the
chemicals used in the hydraulic fracturing process. If hydraulic fracturing is regulated at the federal level, our
fracturing activities could become subject to additional permit or disclosure requirements or operational restrictions
and also to associated permitting delays, litigation risk, and potential cost increases.

Certain states that we operate in, including Pennsylvania, Texas, and Wyoming, have adopted, and other
states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste
disposal, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing
activities altogether. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad
Commission of Texas (“RCT”) and the public of certain information regarding the components and volume of water
used in the hydraulic fracturing process. In addition to state laws, local land use restrictions, such as city
ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular.
In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in
the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be
significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production
activities, and perhaps even be precluded from the drilling and/or completion of wells.

There are certain governmental reviews either underway or being proposed that focus on environmental
aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating a
review of hydraulic fracturing practices, and a committee of the United States House of Representatives has
conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are
analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing.
The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water
and groundwater, with a progress report, but no research results or findings, issued in December 2012 and a draft
report of results to be issued in 2014 for independent peer review by the Science Advisory Board. In addition, the
United States Department of Energy is conducting an investigation into practices the agency could recommend to
better protect the environment from drilling using hydraulic fracturing completion methods. Also, the United States
Department of the Interior is developing disclosure requirements or other mandates for hydraulic fracturing on
federal lands; the Department of the Interior anticipates issuing during the first quarter of 2013 a revised proposed
rule relating to hydraulic fracturing activities on federal lands.

Additionally, certain members of Congress have called upon the United States Government Accountability
Office to investigate how hydraulic fracturing might adversely affect water resources, the United States Securities
and Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the
public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic
fracturing, and the United States Energy Information Administration to provide a better understanding of that
agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties
associated with those estimates. The United States Geological Survey Offices of Energy Resources Program,
Water Resources and Natural Hazards and Environmental Health Offices have ongoing research projects on
hydraulic fracturing. These ongoing or proposed studies, depending on their course and outcomes, could spur
initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory processes.

Further, on August 16, 2012, the EPA issued final rules subjecting all oil and gas operations (production,

processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards
(“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. The EPA rules
also include NSPS standards for completions of hydraulically fractured gas wells. These standards require the use
of reduced emission completion (“REC”) techniques developed in EPA's Natural Gas STAR program along with the
pit flaring of gas not sent to the gathering line beginning in January 2015. The standards are applicable to newly
drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under
NESHAPS include maximum achievable control technology (“MACT”) standards for those glycol dehydrators and
certain storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. The
EPA stated in January 2013, however, that it intends to reconsider portions of the final rule. We are currently
evaluating the effect of these rules on our business.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition,

including litigation, to oil and gas production activities using hydraulic fracturing techniques. Disclosure of
chemicals used in the hydraulic fracturing process could make it easier for third parties opposing such activity to
pursue legal proceedings against producers and service providers based on allegations that specific chemicals used
in the fracturing process could adversely affect human health or the environment, including groundwater.
Additional legislation or regulation could also lead to operational delays or increased costs in the exploration for
and production of oil, natural gas, and associated liquids, including from the development of shale plays, or could
make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state, or local laws, or
the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the
completion of new oil and gas wells, increased compliance costs and delays, which could adversely affect our
financial position, results of operations, and cash flows. The EPA is in the process of updating chloride water
quality criteria for the protection of aquatic life under the Clean Water Act. Flowback and produced water from the
hydraulic fracturing process contains total dissolved solids, including chlorides. The EPA anticipates issuing a draft
criteria document in 2013.

On October 20, 2011, the EPA announced a schedule for development of standards for disposal of
wastewater produced from shale gas operations to publicly owned treatment works (“POTWs”). The regulations
will be developed under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. The
EPA anticipates issuing the proposed rules in 2014.

Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities
could be impaired if we are unable to acquire adequate supplies of water for our drilling operations and/or
completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with
applicable environmental rules.

The hydraulic fracturing process on which we depend to drill for commercial quantities of crude oil, natural

gas, and associated liquids requires the use and disposal of significant quantities of water.

Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our
operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and
regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or
disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with
the exploration, development, or production of natural gas.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage,

and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating
costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all
of which could have an adverse effect on our operations and financial condition.

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

During his first term, President Obama sent to Congress a legislative package that included proposed

legislation that, if enacted into law, would eliminate certain key United States federal income tax incentives
currently available to oil and natural gas exploration and production companies. These changes included, among
other proposals:

•

the repeal of the percentage depletion allowance for oil and natural gas properties;

the elimination of current deductions for intangible drilling and development costs;

the elimination of the deduction for certain domestic production activities; and

an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear when or if these or similar changes will be enacted. The passage of legislation enacting these
or similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently
available with respect to oil and natural gas exploration and development. Any such changes could have an adverse
effect on our financial position, results of operations and cash flows.

Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on
our operations and the demand for crude oil, natural gas, and NGLs.

In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other “greenhouse

gases” present an endangerment to public health and the environment because emissions of such gases are,
according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on
these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict
emissions of greenhouse gases under existing provisions of the CAA. For example, the EPA has adopted two sets
of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of
greenhouse gases from motor vehicles and the other regulates the permitting and emissions of greenhouse gases
from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the
reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States,
including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010,
as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for
emissions occurring in 2011. In the courts, several cases are pending that may increase the risk of claims being
filed against companies that have significant greenhouse gas emissions. Such cases seek to challenge air emissions
permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages
for alleged climate change impacts to the environment, people, and property. Any laws or regulations that restrict
or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and
could have an adverse effect on demand for the oil and natural gas that we produce.

In addition, the United States Congress has from time to time considered adopting legislation to reduce

emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce
emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories
and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring
major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas
processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase
is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require
us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire
emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory
programs could also increase the cost of consuming, and thereby reduce demand for, the oil, gas, and NGLs we
produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an
adverse effect on our business, financial condition, results of operations, and cash flows. Finally, it should be noted
that some scientists have predicted that increasing concentrations of greenhouse gases in the earth’s atmosphere
may produce climate changes that have significant physical effects, such as increased frequency and severity of
storms, droughts, and floods and other climatic events. If such effects were to occur, our operations could be
adversely affected. Potential adverse effects could include disruption of our production activities, including, for
example, damages to our facilities from flooding or increases in our costs of operation or reductions in the
efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such
effects. Significant physical effects of climate change could also have an indirect effect on our financing and
operations by disrupting the transportation or process related services provided by midstream companies, service
companies or suppliers with whom we have a business relationship. We may not be able to recover through
insurance some or any of the damages, losses or costs that may result from potential physical effects of climate
change.

Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use
derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our
business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which was

signed into law on July 21, 2010, establishes, among other provisions, federal oversight and regulation of the over-
the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act also establishes
margin requirements and certain transaction clearing and trade execution requirements. On October 18, 2011, the
Commodities Futures Trading Commission (the “CFTC”) approved regulations to set position limits for certain
futures and option contracts in the major energy markets, which were successfully challenged in federal district
court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives
Association and largely vacated by the court. The CFTC has filed a notice of appeal with respect to this ruling.
Under CFTC final rules promulgated under the Dodd-Frank Act, we believe our derivatives activity will qualify for
the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate
commercial risk from the mandatory swap clearing requirement. The Dodd-Frank Act may also require us to
comply with margin requirements in our derivative activities, although the application of those provisions to us is
uncertain at this time. The financial reform legislation may also require the counterparties to our derivative
instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as
the current counterparties.

The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts
(including through requirements to post collateral, which could adversely affect our available liquidity), materially
alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter,
reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less
creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations,
our results of operations may become more volatile and our cash flows may be less predictable, which could
adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in
45

part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in
derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if
a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences
could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

Our ability to sell crude oil, natural gas and NGLs, and/or receive market prices for our production, may be
adversely affected by constraints on gathering systems, processing facilities, pipelines and other transportation
systems owned or operated by others or by other interruptions.

The marketability of our crude oil, natural gas, and NGL production depends in part on the availability,

proximity, and capacity of gathering systems, processing facilities, and pipeline and other transportation systems
owned or operated by third parties. The lack of available capacity in these systems and facilities can result in the
shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lower price
realizations. Although we have some contractual control over the processing and transportation of our operated
production, material changes in these business relationships could materially affect our operations. Federal and
state regulation of crude oil, natural gas, and NGL production and transportation, tax and energy policies, changes
in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity
constraints, and general economic conditions could adversely affect our ability to produce, gather, process, and
transport crude oil, natural gas, and NGLs.

In particular, if drilling in the Eagle Ford shale, Haynesville shale, Bakken/Three Forks resource play, and

Granite Wash resource play continues to be successful, the amount of crude oil, natural gas, and NGLs being
produced by us and others could exceed the capacity of, and result in strains on, the various gathering and
transportation systems, pipelines, processing facilities, and other infrastructure available in these areas. It will be
necessary for additional infrastructure, pipelines, gathering and transportation systems and processing facilities to
be expanded, built or developed to accommodate anticipated production from these areas. Because of the current
economic climate, certain processing, pipeline, and other gathering or transportation projects that might be, or are
being, considered for these areas may not be developed timely or at all due to lack of financing or other constraints.
Capital and other constraints could also limit our ability to build or access intrastate gathering and transportation
systems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such
event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient
infrastructure development or capacity expansion and/or sell production at significantly lower prices, which would
adversely affect our results of operations and cash flows. In addition, the operations of the third parties on whom
we rely for gathering and transportation services are subject to complex and stringent laws and regulations that
require obtaining and maintaining numerous permits, approvals and certifications from various federal, state, and
local government authorities. These third parties may incur substantial costs in order to comply with existing laws
and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or
if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay
for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we
rely could have a material adverse effect on our business, financial condition and results of operations.

A portion of our production in any region may be interrupted, or shut in, from time to time for numerous

reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or
transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in
response to market conditions. If a substantial amount of our production is interrupted at the same time, it could
temporarily and adversely affect our cash flows and results of operations.

New technologies may cause our current exploration and drilling methods to become obsolete.

The oil and gas industry is subject to rapid and significant advancements in technology, including the

introduction of new products and services using new technologies. As 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, competitors may 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. One or more of the technologies that we currently use or that we may
implement in the future may become obsolete. 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. If we are unable to maintain technological advancements
consistent with industry standards, our operations and financial condition may be adversely affected.

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

As a crude oil, natural gas, and NGL producer, we face various security threats, including cybersecurity
threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the
safety of our employees; threats to the security of our facilities and infrastructure or third party facilities and
infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various
procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no
assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If
any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure,
personnel or capabilities essential to our operations and could have a material adverse effect on our reputation,
financial position, results of operations, or cash flows.

Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software,

attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in
critical systems, unauthorized release of confidential or otherwise protected information and corruption of data.
These events could damage our reputation and lead to financial losses from remedial actions, loss of business or
potential liability.

The threat of terrorism and the impact of military and other action have caused instability in world financial

markets and could lead to increased volatility in prices for crude oil, natural gas, and NGLs, all of which could
adversely affect the markets for our operations. Energy assets might be specific targets of terrorist attacks. These
developments have subjected our operations to increased risk and, depending on their occurrence and ultimate
magnitude, could have a material adverse effect on our business.

Risks Related to Our Common Stock

The price of our common stock may fluctuate significantly, which may result in losses for investors.

From January 1, 2012, to February 14, 2013, the closing daily sale price of our common stock as reported

by the New York Stock Exchange ranged from a low of $41.80 per share in August 2012 to a high of $83.35 per
share in February 2012. We expect our stock to continue to be subject to fluctuations as a result of a variety of
factors, including factors beyond our control. These factors include:

•

changes in crude oil, natural gas, or NGL prices;

variations in drilling, recompletion, and operating activity;

changes in financial estimates by securities analysts;

changes in market valuations of comparable companies;

additions or departures of key personnel;

future sales of our common stock; and

changes in the national and global economic outlook.

We may not meet the expectations of our stockholders and/or of securities analysts at some time in the

future, and our stock price could decline as a result.

Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could
prevent stockholders from receiving a takeover premium on their investment.

Our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or

preventing a change of control. These provisions, among other things, provide for non-cumulative voting in the
election of members of the Board of Directors and impose procedural requirements on stockholders who wish to
make nominations for the election of directors or propose other actions at stockholder meetings. These provisions,
alone or in combination with each other, may discourage transactions involving actual or potential changes of
control, including transactions that otherwise could involve payment of a premium over prevailing market prices to
stockholders for their common stock.

Shares eligible for future sale may cause the market price of our common stock to drop significantly, even if our
business is doing well.

The potential for sales of substantial amounts of our common stock in the public market may have a
materially adverse effect on our stock price. As of February 14, 2013, 66,153,847 shares of our common stock were
freely tradable without substantial restriction or the requirement of future registration under the Securities Act of
1933. Also as of that date, options to purchase 257,180 shares of our common stock were outstanding, all of which
were exercisable. These options are exercisable at prices ranging from $12.53 to $20.87 per share. In addition,
restricted stock units (“RSUs”) providing for the issuance of up to a total of 493,968 shares of our common stock
and 898,145 performance share units were outstanding. Performance share units are structurally the same as the
previously granted Performance Share Awards or (“PSAs”) (collectively known as “Performance Share Units” or
“PSUs”). The PSUs represent the right to receive, upon settlement of the PSUs after the completion of a three-year
performance period, a number of shares of our common stock that may be from zero to two times the number of
PSUs granted, depending on the extent to which the underlying performance criteria have been achieved and the
extent to which the PSUs have vested. As of February 14, 2013, there were 66,205,901 shares of our common stock
outstanding, which is net of 50,581 treasury shares.

We may not always pay dividends on our common stock.

Payment of future dividends remains at the discretion of our Board of Directors, and will continue to

depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of
dividends is subject to a covenant in our credit facility limiting our annual cash dividends to no more than $50.0
million, and to covenants in the indentures for our 2019 Notes, 2021 Notes, and 2023 Notes that limit our ability to
pay dividends beyond a certain amount. Our Board of Directors may determine in the future to reduce the current
semi-annual dividend rate of $0.05 per share, or discontinue the payment of dividends altogether.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

We have no unresolved comments from the SEC staff regarding our periodic or current reports under the

Securities Exchange Act of 1934.

ITEM 3.

LEGAL PROCEEDINGS

From time to time, we may be involved in litigation relating to claims arising out of our operations in the
normal course of business. As of the filing date of this report, no legal proceedings are pending against us that we
believe individually or collectively could have a materially adverse effect upon our financial condition, results of
operations or cash flows.

We were a defendant in litigation, captioned W.H. Sutton, et al. vs. St. Mary Land & Exploration Co., et al.,

wherein the plaintiffs claimed an aggregate overriding royalty interest of 7.46875 percent in production from
approximately 22,000 of our net acres in the Eagle Ford shale play in South Texas. The plaintiffs sought to quiet
title to their claimed overriding royalty interest and to recover unpaid overriding royalty interest proceeds allegedly
due. We believed that the claimed overriding royalty interest had been terminated under the governing agreements
and the applicable law, and contested the plaintiffs’ claims. Both parties filed motions for summary judgment, and
on February 8, 2011, the District Court in Webb County, Texas, issued an order granting plaintiffs’ motion for
summary judgment and denying our motion for summary judgment. On September 30, 2011, the District Court
entered final judgment for the plaintiffs and awarded then current damages of approximately $5.1 million, which
included prejudgment interest. The District Court also awarded attorneys fees and costs to the plaintiffs. We
appealed the District Court’s judgment and obtained a stay pending appeal that prevented the plaintiffs from
executing on the judgment.

On May 23, 2012, the Fourth Court of Appeals for the State of Texas delivered its opinion in this matter,

which reversed the summary judgment granted to the plaintiffs by the District Court and rendered judgment that the
plaintiffs take nothing. Accordingly, based on the judgment of the Fourth Court of Appeals, the plaintiffs are not
entitled to their claimed 7.46875 percent overriding royalty interest, nor are they entitled to the claimed damages
related to the overriding royalty interest, attorneys fees or costs. The plaintiffs petitioned the Supreme Court of
Texas for a review of the judgment of the Fourth Court of Appeals. The Supreme Court of Texas denied this
petition for review on February 15, 2013, and as a result, the decision of the Fourth Court of Appeals is dispositive
and its dismissal of the plaintiffs’ claims is final.

We also filed a declaratory judgment action in Webb County, Texas, captioned SM Energy Company vs.
W.H. Sutton, et al., seeking a judgment declaring that the lease at issue in W.H. Sutton, et al. vs. St. Mary Land &
Exploration Co., et al. had terminated with respect to the remaining 18,000 acres, based upon a failure of
continuous development, and that any overriding royalty interest claimed by the defendants has been extinguished.
On September 19, 2012, the District Court in Webb County, Texas, granted our motion for summary judgment,
concluding that the defendants’ claims for any overriding royalty interest had been extinguished. The plaintiffs filed
their notice of appeal to the Fourth Court of Appeals on November 15, 2012, but due to the numerous requests for
an extension, have not yet filed their brief. We will continue to contest this litigation.

We, and our working interest partners, filed an action against Endeavour Operating Corporation

(“Endeavour”) in Harris County, Texas, captioned SM Energy Company, et al. v. Endeavour Operating Corporation,
seeking an order requiring Endeavour to honor its obligations to consummate the purchase of certain assets located
in Pennsylvania, or in the alternative, for damages. We are required to take reasonable measures to attempt to
mitigate our potential losses, and during 2012 we initiated efforts to remarket such assets. If we are successful in
such efforts and complete a sale of these assets for less than the $110 million ($80 million of which is attributable to
our interest) Endeavour agreed to pay to us and our working interest partners, we will continue to prosecute this
action to recover any such deficiency and any amounts expended in our efforts to remarket the assets, and to obtain
any other relief to which we are entitled. As of the filing date of this report, we have no commitment from another
party to purchase these assets.

On January 27, 2011, Chieftain Royalty Company (“Chieftain”) filed a Class Action Petition against us in

the District Court of Beaver County, Oklahoma, claiming damages related to royalty valuation on all of our
Oklahoma wells. These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment,
tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of post-
production costs. We removed this lawsuit to the United States District Court for the Western District of Oklahoma
on February 22, 2011. We have responded to the petition and denied the allegations. The court has not yet ruled on
Chieftain's motion to certify the putative class, and has stayed any such ruling until the United States Court of
Appeals for the Tenth Circuit issues its ruling on class certification in two similar royalty class action lawsuits,
where the defendants have appealed such certification. The opinion from the Tenth Circuit is expected during the
summer of 2013. We believe we properly valued and paid royalty under Oklahoma law and have and will continue
to vigorously defend this case.

ITEM 4.

MINE SAFETY DISCLOSURES

These disclosures are not applicable to us.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information. Our common stock is currently traded on the New York Stock Exchange under the

ticker symbol “SM”. The following table presents the range of high and low intraday sales prices per share for the
indicated quarterly periods in 2012 and 2011, as reported by the New York Stock Exchange:

Quarter Ended
December 31, 2012
September 30, 2012
June 30, 2012
March 31, 2012

December 31, 2011
September 30, 2011
June 30, 2011
March 31, 2011

High

Low

$
$
$
$

62.09
59.39
71.81
84.40

88.50
85.55
78.55
75.00

$
$
$
$

45.25
39.44
43.12
69.40

53.45
60.52
61.37
54.59

PERFORMANCE GRAPH

The following performance graph compares the cumulative return on our common stock, for the period
beginning December 31, 2007, and ending on December 31, 2012, with the cumulative total returns of the Dow
Jones U.S. Exploration and Production Board Index, and the Standard & Poor’s 500 Stock Index.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURNS

The preceding information under the caption Performance Graph shall be deemed to be furnished, but not

filed with the Securities and Exchange Commission.

Holders. As of February 14, 2013, the number of record holders of SM Energy’s common stock was 88.

Based upon inquiry, management believes that the number of beneficial owners of our common stock is
approximately 35,200.

Dividends. We have paid cash dividends to our stockholders every year since 1940. Annual dividends of
$0.05 per share were paid in each of the years 1998 through 2004. Annual dividends of $0.10 per share were paid
in 2005 through 2012. We expect that our practice of paying dividends on our common stock will continue,

although the payment of future dividends will continue to depend on our earnings, cash flow, capital requirements,
financial condition, and other factors, including the discretion of our Board of Directors. In addition, the payment
of dividends is subject to covenants in our credit facility that limit our annual dividend payment to no more than
$50.0 million per year. We are also subject to certain covenants under our 2019 Senior Notes, our 2021 Senior
Notes, and our 2023 Senior Notes that restrict certain payments, including dividends; provided, however, the first
$6.5 million of dividends paid each year are not restricted by this covenant. Based on our current performance, we
do not anticipate that these covenants will restrict future annual dividend payments of $0.10 per share of common
stock. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $6.5 million in 2012 and $6.4
million in 2011.

Restricted Shares. We have no restricted shares outstanding as of December 31, 2012, aside from Rule 144

restrictions on shares held by insiders and shares issued to members of the Board of Directors under our Equity
Incentive Compensation Plan (“Equity Plan”).

Purchases of Equity Securities by the Issuer and Affiliated Purchasers. The following table provides

information about purchases by the Company and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under
the Exchange Act) during the indicated quarters and year ended December 31, 2012, of shares of the Company’s
common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the
Exchange Act.

ISSUER PURCHASES OF EQUITY SECURITIES

Total Number
of Shares
Purchased(1)

Average Price
Paid per Share

Total Number of
Shares Purchased
as Part of Publicly
Announced
Program

Maximum
Number of Shares
that May Yet be
Purchased Under
the Program(2)

January 1, 2012 –
March 31, 2012
April 1, 2012 -

June 30, 2012

July 1, 2012 -
September 30, 2012
October 1, 2012 -
October 31, 2012
November 1, 2012 -
November 30, 2012
December 1, 2012 -
December 31, 2012
Total October 1, 2012 -
December 31, 2012
Total

176

79.93

— $

—

456,227

47.32

— $

162

158

320
456,723

$
$

—

49.43

53.92

51.66
47.34

—

—
—

3,072,184

3,072,184
3,072,184

(1) All shares purchased in 2012 were to offset tax withholding obligations that occur upon the delivery of outstanding shares

underlying RSUs and PSUs delivered under the terms of grants under the Equity Plan.

(2) In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the

original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of
this filing, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock
on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately
negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility,
the indentures governing our Senior Notes and compliance with securities laws. Stock repurchases may be funded with
existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be
suspended or discontinued at any time. Please refer to Dividends above for a description of our dividend limitations.

ITEM 6.

SELECTED FINANCIAL DATA

The following table sets forth selected supplemental financial and operating data for us as of the dates and

periods indicated. The financial data for each of the five years presented were derived from our consolidated
financial statements. The following data should be read in conjunction with Management’s Discussion and Analysis
of Financial Condition and Results of Operations in Part II, Item 7 of this report, which includes a discussion of
factors materially affecting the comparability of the information presented, and in conjunction with our
consolidated financial statements included in this report.

Total operating revenues
Net income (loss)
Net income (loss) per share:

Basic
Diluted

Total assets at year-end
Long-term debt:

$
$

$
$
$

Line of credit
3.50% Senior Convertible
Notes, net of debt discount $
6.625% Senior Notes due
2019
6.50% Senior Notes due
2021

6.50% Senior Notes due

2023

Cash dividends declared and
paid per common share

2012

1,505.1
(54.2)

(0.83)
(0.83)
4,199.5

340.0

$
$

$
$
$

350.0

400.0

0.10

Years Ended December 31,
2011
2010
(in millions, except per share data)
1,603.3
215.4

1,092.8
196.8

$
$

2009

832.2
(99.4)

3.38
3.19
3,799.0

$
$
$

3.13
3.04
2,744.3

— $

285.1

— $

48.0

275.7

$
$
$

(1.59)
(1.59)
2,360.9

188.0

266.9

350.0

— $

2008

1,301.3
87.3

1.40
1.38
2,697.2

300.0

258.7

$
$

$
$
$

—

— $

0.10

Supplemental Selected Financial and Operations Data

Balance Sheet Data (in millions)
Total working capital (deficit)
Total stockholders’ equity

Weighted-average common shares
outstanding (in thousands)

Basic
Diluted
Reserves

Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE

Production and Operational (in millions)

Oil, gas, and NGL production revenues

Oil, gas, and NGL production expenses
DD&A
General and administrative

Production Volumes

Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE

Realized price
Oil (per Bbl)
Gas (per Mcf)
NGL (per Bbl)

Adjusted price (net of derivative cash
settlements)

Oil (per Bbl)
Gas (per Mcf)
NGL (per Bbl)
Expense per MCFE

LOE
Transportation
Production taxes
DD&A
General and administrative

Statement of Cash Flow Data (in millions)

Provided by operations
(Used in) investing
Provided by (used in) financing

2012

For the Years Ended December 31,
2009
2010
2011

2008

$
$

(201.0)
1,414.5

$
$

(42.6)
1,462.9

$
$

(227.4)
1,218.5

$
$

(87.6)
973.6

$
$

15.2
1,162.5

65,138
65,138

92.2
833.4
62.3
1,760.6

1,473.9

391.9
727.9
119.8

10.4
120.0
6.1
218.9

85.45
2.98
37.61

83.52
3.48
38.90

0.82
0.63
0.33
3.32
0.55

922.0
(1,457.3)
422.1

$
$
$

$
$
$
$
$

$
$
$

63,755
67,564

71.7
664.0
27.5
1,259.2

1,332.4

290.1
511.1
118.5

8.1
100.3
3.5
169.7

88.23
4.32
53.32

78.89
4.80
47.90

0.88
0.51
0.32
3.01
0.70

760.5
(1,264.9)
618.5

$
$
$

$
$
$
$
$

$
$
$

$
$
$
$
$

$
$
$

62,969
64,689

62,457
62,457

57.4
640.0
—
984.5

836.3

195.1
336.1
106.7

6.4
71.9
—
110.0

$
$
$

53.8
449.5
—
772.2

616.0

206.8
304.2
76.0

6.3
71.1
—
109.1

$
$
$

72.65
5.21

$
$
— $

54.40
3.82

$
$
— $

66.85
6.05

$
$
— $

56.74
5.59

$
$
— $

1.10
0.19
0.48
3.06
0.97

497.1
(361.6)
(141.1)

$
$
$
$
$

$
$
$

1.33
0.19
0.37
2.79
0.70

436.1
(304.1)
(127.5)

$
$
$
$
$

$
$
$

62,243
63,133

51.4
557.4
—
865.5

1,259.4

271.4
314.3
79.5

6.6
74.9
—
114.6

92.99
8.60
—

75.59
8.79
—

1.46
0.19
0.71
2.74
0.69

679.2
(673.8)
(42.8)

Note: 2010 and prior NGL production volumes, revenues, and prices have not been reclassified to conform to the current
presentation given the immateriality of the amounts. Please refer to additional discussion under the caption Oil, Gas, and NGL
Prices in Part II, Item 7 of this report.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

This discussion includes forward-looking statements. Please refer to Cautionary Information about

Forward-Looking Statements in Part I, Items 1 and 2 of this report for important information about these types of
statements.

Overview of the Company

General Overview

We are an independent energy company engaged in the acquisition, exploration, development, and
production of oil, gas, and NGLs in onshore North America. Our assets include leading positions in the Eagle Ford
shale and Bakken/Three Forks resource plays, as well as exposure to the Granite Wash play and emerging oil-
focused plays in the Permian Basin. We have built a portfolio of onshore properties in the contiguous United States
primarily through early entry into existing and emerging resource plays. This portfolio is comprised of properties
with established production and reserves, prospective drilling opportunities, and unconventional resource prospects.
We believe our strategy provides for stable and predictable production and reserve growth. Furthermore, by
entering these plays early, we believe we can capture larger resource potential at a lower cost.

Our principal business strategy is to focus on the early capture of resource plays in order to create and then

enhance value for our shareholders while maintaining a strong balance sheet. We strive to leverage industry-leading
exploration and leasehold acquisition teams to quickly acquire and test new resource play concepts at a reasonable
cost. Once we have identified potential value through these efforts, our goal is to develop such potential through
top-tier operational and project execution and to mitigate our risks by selectively divesting of certain assets when
deemed appropriate by us. We continually examine our portfolio for opportunities to improve the quality of our
asset base in order to optimize our returns and preserve our financial strength.

In 2012 we had the following financial and operational results:

• At year-end 2012, we had estimated proved reserves of 1,760.6 BCFE (293.4 MMBOE), of which 53

percent were liquids (oil and NGLs) and 57 percent was characterized as proved developed. We added
900.2 BCFE from our drilling program, the majority of which related to our activity in the Eagle Ford
shale in South Texas and the Bakken/Three Forks plays in North Dakota. We had negative price
revisions that decreased our estimated proved reserves by 72.7 BCFE primarily due to gas weighted
projects in our South Texas & Gulf Coast and Mid-Continent regions that do not generate positive cash
flow utilizing historical 12-month average benchmark pricing required by the SEC. The prices used in
the calculation of proved reserve estimates as of December 31, 2012, were $94.71 per Bbl, $2.76 per
MMBtu, and $45.65 per Bbl, for oil, gas, and NGLs, respectively. These prices were two percent, 33
percent, and 23 percent lower for oil, gas, and NGLs, respectively, than the prices used at year-end
2011. We had downward engineering revisions of 49.2 BCFE related primarily to Eagle Ford shale
proved undeveloped locations as well as downward engineering revisions of Wolfberry assets in our
Permian region. Additionally, we removed 42.7 BCFE of proved undeveloped reserves primarily in the
Woodford shale due to low natural gas prices and as a result of the five-year limitation on the number
of years proved undeveloped reserves may remain on the books without being developed. Please refer
to the caption Proved Undeveloped Reserves under the section Reserves included in Part I, Items 1 and
2 of this report for additional discussion. We had immaterial acquisitions of 1.6 BCFE, and we divested
of 16.9 BCFE of proved reserves during the year related to non-core assets located primarily in our
Rocky Mountain and Mid-Continent regions.

• The PV-10 value of our estimated proved reserves was $3.8 billion as of December 31, 2012, compared

with $3.5 billion as of December 31, 2011. The after tax value, represented by the standardized
measure calculation, was $3.0 billion as of December 31, 2012 compared with $2.6 billion as of
December 31, 2011. The standardized measure calculation is presented in the Supplemental Oil and
Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10
reserve value and the after tax value is shown under Reserves in Part I, Items 1 and 2 of this report.

• We had record production in 2012. Our average daily production in 2012 was 28.3 MBbl of oil, 328.0
MMcf of gas, and 16.7 MBbl of NGLs, for an average equivalent production rate of 598.2 MMCFE,
compared with 465.0 MMCFE in 2011, an increase of 29 percent year-over-year. Please refer to the
caption Production Results below for additional discussion.

• We recorded a net loss of $54.2 million, or a loss of $0.83 per diluted share, for the year ended

December 31, 2012, due to an impairment of proved properties. This compares with net income of
$215.4 million, or $3.19 per diluted share, for the year ended December 31, 2011. Please refer to the
caption Comparison of Financial Results and Trends Between 2012 and 2011 below for additional
discussion regarding the components of net income (loss) and 2012 Highlights for additional discussion
on impairment of proved properties.

• We had record cash flow provided by operating activities of $922.0 million for the year ended

December 31, 2012, compared with $760.5 million for the year ended December 31, 2011, which was
an increase of 21 percent year-over-year. Please refer to Analysis of cash flow changes between 2012
and 2011 below for additional discussion.

• Costs incurred for oil and gas producing activities for the year ended December 31, 2012, were $1.7
billion, compared with $1.6 billion for the same period in 2011. Please refer to the caption Costs
Incurred in Oil and Gas Producing Activities below for additional discussion.

• EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2012, was $1.0 billion,
compared with $886.6 million for the same period in 2011. Please refer to the caption Non-GAAP
Financial Measures below for additional discussion, including our definition of EBITDAX and
reconciliations of our GAAP net income (loss) and net cash provided by operating activities to
EBITDAX.

Reserve Replacement, Finding and Development Costs, and Growth

Like all oil and gas exploration and production companies, we face the challenge of growing proved
reserves. An exploration and production company depletes part of its asset base with each unit of oil, gas, or NGL
it produces. Our future growth will depend on our ability to organically and economically add reserves in excess of
production.

The following table provides various reserve replacement and finding and development cost metrics for the

year ended December 31, 2012:

Reserve Replacement
Percentage

Finding and Development
Cost per MCFE (1)

Including
Divestitures

Drilling, excluding revisions
Drilling, including revisions
Drilling and acquisitions, excluding revisions
Drilling and acquisitions, including revisions
Reserve Acquisitions
All-in
* N/M – Percentage or amount, as applicable, is not meaningful.
(1) Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement for discussion on how
we are being carried on 90 percent of certain drilling and completion costs.

403% $
328% $
404% $
329% $
N/M $
329% $

Excluding
Divestitures
1.74
2.13
1.74
2.13
3.59
2.29

Including
Divestitures
1.77
$
2.18
$
1.78
$
2.18
$
N/M
2.34

Excluding
Divestitures
411%
336%
412%
337%
1%
337%

The following table provides average reserve replacement and finding and development cost metrics for the

three-year period ended December 31, 2012:

Reserve Replacement
Percentage

Finding and Development
Cost per MCFE (1)

Including
Divestitures

324% $
298% $
324% $
298% $
N/M $
298% $

Excluding
Divestitures
2.15
2.31
2.15
2.31
3.52
2.45

Including
Divestitures
2.41
$
2.62
$
2.41
$
2.62
$
N/M
2.77

Excluding
Divestitures
363%
337%
363%
338%
N/M
338%

Our challenge is to grow net asset value per share, which we believe drives appreciation in our stock price
over the long term. To accomplish this, we believe it is important to organically and economically replace annual
production with new reserves. We believe annual reserve replacement percentage and finding and development
costs are important analytical measures that are widely used by investors and industry peers in evaluating and
comparing the performance of oil and gas companies. While single-year measurements have some meaning in
terms of a trend, we believe aberrations, causing both positive and negative results, will occur over short intervals
of time. The information used to calculate the above reserve replacement and finding and development cost metrics
is included in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. For
additional information about these metrics, see the reserve replacement and finding and development cost terms in
the Glossary of Oil and Gas Terms at the end of Part I, Items 1 and 2 of this report.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive

for oil, gas, and NGL production, which can fluctuate dramatically. We sell the majority of our natural gas under
contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-
the-month price regardless of the spot price on the day the gas is produced. For assets where high BTU gas is sold
57

at the wellhead, we also receive additional value for the high energy content contained in the gas stream. Our NGL
production is generally sold using contracts paying us a monthly average of the posted OPIS daily settlement prices,
adjusted for processing, transportation, and location differentials. Our oil and condensate are sold using contracts
paying us either the average of the NYMEX WTI daily settlement price or the average of alternative posted prices
for the periods in which the product is produced, adjusted for quality, transportation, and location differentials.

Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well

head. As a result, we reported realized prices for our natural gas production for periods through December 31,
2010, that were higher than industry benchmarks due to the price uplift associated with incremental value contained
in the higher BTU content of our produced gas stream. Beginning in 2011, we changed our reporting for natural
gas volumes to show natural gas and NGL production volumes consistent with title transfer for each product.
Projected rapid production growth from our NGL-rich assets associated with plant product sales contracts
necessitated a change in our reporting of production volumes. Our 2010 production volumes, revenues, and prices
have not been reclassified to conform to the current presentation given the immateriality of the NGL volumes
produced in that period.

The following table is a summary of commodity price data for the years ended December 31, 2012, 2011,

and 2010:

For the Years Ended December 31,
2011

2010

2012

Crude Oil (per Bbl):
Average NYMEX price
Realized price

Natural Gas:
Average NYMEX price (per MMBtu)
Realized price (per Mcf)

NGLs (per Bbl):
Average OPIS price
Realized price

$
$

94.10
85.45

2.75
2.98

44.91
37.61

$
$

95.05
88.23

4.00
4.32

59.47
53.32

$
$

79.51
72.65

4.37
5.21

34.61
N/A

Note: 2010 NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation
given the immateriality of NGL volumes. Please refer to additional discussion above. Average OPIS prices per barrel of NGL,
historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14%
Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not
necessarily represent the Company’s product mix for NGL production. The Company's actual product mix is reflected in actual
prices received for NGLs produced.

We expect future prices for oil, gas, and NGLs to be volatile. In addition to supply and demand

fundamentals, as a global commodity, the price of oil will likely continue to be impacted by real or perceived
geopolitical risks in oil producing regions of the world, particularly in the Middle East. The relative strength of the
U.S. dollar compared to other currencies could also affect the price of oil. The supply of NGLs in the U.S. is
expected to continue to grow in the near term as a result of the number of industry participants targeting projects
that produce these products. The pace of NGL production is growing faster than the capacity to process or consume
NGLs, which will likely negatively impact pricing in the near term. The prices of several of the specific NGL
products correlate to the price of oil and accordingly are likely to directionally follow that market. Gas prices have
been under downward pressure for several years due to market oversupply resulting from continued high levels of
natural gas production and insufficient demand for natural gas as a result of tepid economic growth, although gas
prices increased moderately in the last half of 2012. The 12-month strip prices for NYMEX WTI oil, NYMEX

Henry Hub gas, and OPIS NGLs (same product mix as discussed above) as of December 31, 2012, were $93.19 per
Bbl of oil, $3.60 per MMBtu of gas, and $41.20 per Bbl of NGLs, respectively. Comparable prices as of
February 14, 2013, were $98.38 per Bbl, $3.51 per MMBtu, and $41.03 per Bbl, respectively.

While changes in quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for

comparison within our industry, the prices we receive are affected by quality, energy content, location, and
transportation differentials for these products. Consistent with all prior periods reported, our realized prices shown
in the table above do not include the impact of cash settlements from derivative contracts.

Derivative Activity

We use financial derivative instruments as part of our financial risk management program. We have a
financial risk management policy governing our use of derivatives. The amount of our production covered by
derivatives is driven by the amount of debt on our balance sheet and the level of capital commitments and long-term
obligations we have in place. With our current derivative contracts, we believe we have established a base cash
flow stream for our future operations and have partially reduced our exposure to volatility in commodity prices. We
utilize swaps as well as costless collars for a portion of our derivatives since collars allow us to participate in some
of the upward movements in oil, gas, and NGL prices while also setting a price floor for a portion of our
production. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional
information regarding our oil, gas, and NGL derivatives, and the caption, Summary of Oil, Gas, and NGL
Derivative Contracts in Place, below.

The following table presents a reconciliation from our realized price to our adjusted price for the

commodities indicated, including the effects of derivative cash settlements, for 2012, 2011, and 2010:

Crude Oil (per Bbl):
Realized price
Less the effects of derivative cash settlements
Adjusted price, including the effects of derivative cash settlements

Natural Gas (per Mcf):
Realized price
Add the effects of derivative cash settlements
Adjusted price, including the effects of derivative cash settlements

Natural Gas Liquids (per Bbl):
Realized price
Add (less) the effects of derivative cash settlements
Adjusted price, including the effects of derivative cash settlements

For the Years Ended December 31,
2010
2011
2012

85.45 $
(1.93)
83.52 $

88.23
(9.34)
78.89

2.98 $
0.50
3.48 $

4.32
0.48
4.80

37.61 $
1.29
38.90 $

53.32
(5.42)
47.90

72.65
(5.80)
66.85

5.21
0.84
6.05

—
—
—

Note: 2010 NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation
given the immateriality of the volumes. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices
above.

The Dodd-Frank Act included provisions requiring over-the-counter derivative transactions to be executed
through an exchange or centrally cleared. On July 10, 2012, the CFTC and the SEC adopted final joint rules under
Title VII of the Dodd-Frank Act, which define certain terms and determine what types of transactions will be
subject to heightened scrutiny under the Dodd-Frank Act swap rules. The issuance of these final rules also triggers
compliance dates for a number of other final Dodd-Frank Act rules, including new rules proposed by the CFTC
governing margin requirements for uncleared swaps entered into by non-bank swap entities, and new rules proposed
59

by U.S. banking regulators regarding margin requirements for uncleared swaps entered into by bank swap entities.
The ultimate effect on our business of these new rules and any additional regulations is currently uncertain. Under
CFTC rules we believe our derivative activity will qualify for the non-financial, commercial end-user exception,
which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing
requirement. However, we are not certain whether the provisions of the final rules and regulations will exempt us
from the requirements to post margin in connection with commodity price risk management activities. Final rules
and regulations on major provisions of the legislation, such as new margin requirements, are to be established
through regulatory rulemaking. Although we cannot predict the ultimate outcome of these rulemakings, new rules
and regulations in this area may result in increased costs and cash collateral requirements for the types of derivative
instruments we use to manage our financial risks related to volatility in oil, gas, and NGL commodity prices.

2012 Highlights

Operational Activities. We operated between 15 and 18 drilling rigs company-wide for most of 2012. The
primary focus of our operated drilling activity this year was oil and NGL-rich gas projects. We also participated in
non-operated drilling activity primarily in oil and NGL-rich plays.

In our Eagle Ford shale program in South Texas, we operated six rigs throughout most of 2012 until
releasing one of our operated rigs at the end of the third quarter due to increased drilling rig efficiencies. We
focused our drilling in areas with higher BTU gas content and condensate yields. We believe we have secured most
of the requisite services, such as gas pipeline takeaway capacity and drilling and completion services, to support our
current development plans. We will continue to explore additional arrangements to facilitate the continued growth
of our operated program. Please refer to Note 6 – Commitments and Contingencies under Part II, Item 8 of this
report and Delivery Commitments and Core Operational Areas under Part I, Items 1 and 2 of this report for
additional discussion concerning these agreements.

In our non-operated Eagle Ford program, the operator had nine drilling rigs and one spudder rig running

throughout 2012. We expect the majority of our non-operated Eagle Ford drilling and completion costs to be
funded by Mitsui over approximately the next two years under the terms of our previously announced Acquisition
and Development Agreement.

We started 2012 operating three drilling rigs in our Bakken/Three Forks program in the North Dakota

portion of the Williston Basin and increased to four drilling rigs in the third quarter, focusing on our Gooseneck,
Raven, and Bear Den prospects. In the southern portion of our Rocky Mountain region, we operated one rig testing
various formations in the Powder River Basin of Wyoming as part of our exploration program.

Effective January 1, 2012, we combined our ArkLaTex region into our Mid-Continent region, based in

Tulsa, Oklahoma, for operational and reporting purposes. Throughout 2012, we operated three drilling rigs in our
Granite Wash program in western Oklahoma and the Texas Panhandle, focusing primarily on the Marmaton washes
due to their higher oil and NGL content. Essentially all of our acreage position in this play is held by production.
We completed our operated Haynesville shale program early in the year after achieving held by production status on
substantially all of our acreage.

In our Permian region, we began the year with one operated rig and increased to four during the third
quarter of 2012, with two of the rigs testing the Mississippian limestone formation on our properties in the northeast
Midland Basin where we have approximately 65,500 net acres. A third rig focused on the Bone Spring formation
on our properties in New Mexico. Finally, the fourth rig operated in the Midland Basin, focusing on testing the
Leonard shale. We added approximately 38,000 net acres to our Permian Basin Texas acreage position in 2012.

Production Results. The table below provides a regional breakdown of our 2012 production:

South
Texas &
Gulf
Coast

Rocky
Mountain

Mid-
Continent

Permian

Total (1)

Production:
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE (1)
Avg. Daily Equivalents
(MMCFE/d)
Relative percentage
(1) Totals may not sum or recalculate due to rounding.

3.2
59.1
5.7
112.7

307.9
51%

5.4
4.4
—
36.9

100.9
17%

0.4
53.4
0.4
58.1

158.6
27%

1.3
3.2
—
11.3

30.8
5%

10.4
120.0
6.1
218.9

598.2
100%

We had record production in 2012, which was primarily driven by the development of our operated and
non-operated Eagle Ford shale programs in our South Texas & Gulf Coast region. Please refer to Comparison of
Financial Results and Trends between 2012 and 2011 below for additional discussion on production.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition,

exploration and development activities, whether capitalized or expensed, are summarized as follows:

For the Year Ended
December 31, 2012
(in millions)

Development costs
Exploration costs
Acquisitions

Proved properties
Unproved properties

Total, including asset retirement obligation

1,346.2
220.9

5.8
115.0
1,687.9

The majority of costs incurred for oil and gas producing activities during 2012 related to the development

of our Eagle Ford shale and Bakken/Three Forks programs. Please refer to Overview of Liquidity and Capital
Resources below for additional discussion on how we expect to fund our capital program in 2013.

Impairment of Proved Properties. We recorded impairment of proved properties expense of $208.9 million
for the year ended December 31, 2012, related to the write-down of our Wolfberry assets in our Permian region due
to downward engineering revisions, as well as write-downs of our Haynesville shale assets due to low natural gas
prices.

Divestiture Activity and Unsuccessful Sale of Properties. During 2012, we divested of various non-strategic
properties located in our Rocky Mountain and Mid-Continent regions for $57.4 million in total divestiture proceeds.
Additionally in 2012, we reclassified assets located in both regions that were previously classified as held for sale to
assets held and used, as these assets were no longer being actively marketed, which resulted in a $33.9 million non-
cash loss. Please refer to Note 3 - Divestitures and Assets Held for Sale in Part II, Item 8 of this report for
additional discussion.

Equity Compensation. During 2012, we granted 379,332 RSUs and 314,853 PSUs pursuant to our long-

term equity compensation program. Additionally, we issued 929,375 shares of our common stock to settle PSU and
RSU awards granted in previous years. Please refer to Note 7 - Compensation Plans in Part II, Item 8 of this report
for additional discussion.

3.50% Senior Convertible Notes. In April 2012, we called for the redemption of our outstanding 3.50%

Senior Convertible Notes, which triggered the conversion feature of these notes. We settled the principal amount of
all converted 3.50% Senior Convertible Notes in cash with the excess value settled in shares of common stock, and
settled all redeemed notes in cash. Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for
additional discussion.

2023 Notes. In June 2012, we issued $400.0 million in aggregate principal amount of 6.50% Senior Notes.
The notes were issued at par and mature on January 1, 2023. We received net proceeds of $392.1 million from this
issuance, which we used to pay down outstanding borrowings under our credit facility. Please refer to Note 5 -
Long-term Debt in Part II, Item 8 of this report for additional discussion.

Marketing of Properties. During the second quarter of 2012, we began to re-market our Marcellus shale
assets located in Pennsylvania. Please refer to Note 3 - Divestitures and Assets Held for Sale in Part II, Item 8 of
this report, as well as Legal Proceedings in Part I, Item 3 of this report for additional discussion.

Credit Facility. In the third quarter of 2012, the borrowing base under our credit facility was increased by
our lenders to $1.55 billion from $1.4 billion. Please refer to Overview of Liquidity and Capital Resources below
for additional discussion.

Outlook for 2013

We enter 2013 with a capital program of approximately $1.5 billion, of which approximately $1.2 billion

will be focused on drilling and completion activities. We expect that approximately 90 percent of our drilling
budget will be spent on our operated Eagle Ford shale, Bakken/Three Forks and operated Permian programs.

In 2013, we plan to invest approximately $650 million of drilling and completion capital in our operated

Eagle Ford shale play. Throughout 2013, we plan to operate five drilling rigs supported by two frac spreads, all of
which will be primarily focused on pad drilling in the northern portion of our acreage position where there is a
higher liquid contribution to our production mix. In 2013, our firm contracted wet gas takeaway capacity will
increase with the addition of incremental capacity on existing pipelines and the addition of a third pipeline with firm
transportation capacity contracted to begin in the third quarter. During 2013, we plan to continue to refine our
development program and well designs to optimize well performance and capital efficiency.

In our non-operated Eagle Ford shale program, the operator is currently operating nine drilling rigs and one

spudder rig. Based on the operator’s stated plans, our expectation is that the number of rigs will decrease to eight
drilling rigs and one spudder rig during the year. Mitsui will carry the majority of our non-operated drilling activity
through 2013, so we expect to deploy minimal drilling and completion capital in this program. Costs associated
with items such as infrastructure are not carried by Mitsui, and we will be responsible for our proportionate share of
those costs.

We plan to deploy $290 million of our capital budget in our Bakken/Three Forks program in the Williston
Basin in 2013. Currently, we are operating four drilling rigs in this program and plan to operate an average of 3.5
drilling rigs throughout the year. Our plan with these rigs is to continue infill drilling in our three focus areas and
leverage efficiencies through pad drilling.

In our Permian program, we plan to deploy approximately $170 million of drilling and completion capital.

Our program will focus two drilling rigs in our Mississippian limestone play as we continue to delineate our
position of approximately 65,500 net acres. During the year, we will also continue to run an exploratory program in
the Midland Basin testing various shale formations.

The remaining $90 million of our drilling and completion capital planned for this year will be deployed in

our operated Granite Wash program and various other operated and non-operated programs. Our Granite Wash
program will have one to two operated rigs, while the remainder of the activity will be in our exploration plays,
including on our Powder River Basin acreage.

Please refer to Overview of Liquidity and Capital Resources for additional discussion regarding how we

intend to fund our 2013 capital program.

Financial Results of Operations and Additional Comparative Data

The table below provides information regarding selected production and financial information for the

quarter ended December 31, 2012, and the immediately preceding three quarters. Additional details of per MCFE
costs are presented later in this section.

December 31,
2012

For the Three Months Ended
June 30,
September 30,
2012
2012

March 31,
2012

Production (BCFE)
Oil, gas, and NGL production revenue
Realized hedge gain
Gain (loss) on divestiture activity
Lease operating expense
Transportation costs
Production taxes
DD&A
Exploration
Impairment of proved properties
Abandonment and impairment of unproved
properties
General and administrative
Change in Net Profits Plan liability
Unrealized and realized derivative (gain) loss
Net income (loss)

$
$
$
$
$
$
$
$
$

$
$
$
$
$

50.7
362.6
1.7
1.5
39.4
28.6
19.1
169.6
18.6
—

0.1
28.1
3.9
2.2
26.3

(in millions, except for production data)
60.7
424.7
1.5
4.2
48.0
43.0
20.2
204.3
24.2
170.4

57.0
$
373.9
$
0.5
(8.5) $
$
46.5
$
37.0
$
18.9
$
192.4
$
25.4
— $

50.6
$
312.6
0.2
$
(24.2) $
$
46.1
$
30.3
$
14.7
$
161.6
$
22.0
$
38.5

$
$
$
$
$
$
$
$
$

$
5.0
$
28.4
(11.6) $
(15.6) $
(67.1) $

$
0.4
$
32.2
$
0.8
55.9
$
(38.3) $

$
10.7
$
31.1
(22.1) $
(98.1) $
$
24.9

Selected Performance Metrics:

December 31,
2012

For the Three Months Ended
September 30,
2012

June 30,
2012

March 31,
2012

Average net daily production equivalent
(MMCFE per day)
Lease operating expense (per MCFE)
Transportation costs (per MCFE)
Production taxes as a percent of oil, gas, and
NGL production revenue
Depletion, depreciation and amortization and
asset retirement obligation liability accretion
(per MCFE)
General and administrative (per MCFE)

$
$

659.6
0.79
0.71

4.8%

3.37
0.47

$
$

619.6
0.82
0.65

5.1%

3.38
0.56

$
$

555.7
0.91
0.60

4.7%

3.20
0.62

$
$

557.0
0.78
0.56

5.3%

3.35
0.56

A year-to-year overview of selected production and financial information, including trends:

As of and for the Years Ended
December 31,
2011

2010

2012

Amount Change
Between

Percent Change
Between

2012/2011

2011/2010

2012/2011

2011/2010

1.7
28.5
3.5
59.7

4.7
78.0
9.6
163.6

250.9
59.0
186.2
496.1

28.3
65.2
1.5
95.0

Net production volumes (1)
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
BCFE
Average net daily production (1)
Oil (MBbl per day)
Gas (MMcf per day)
NGLs (MBbl per day)
Equivalent (MMCFE per day)

Oil, gas, and NGL production revenues
(in millions)
Oil production revenue
Gas production revenue
NGL production revenue
Total

10.4
120.0
6.1
218.9

28.3
328.0
16.7
598.2

8.1
100.3
3.5
169.7

22.1
274.8
9.6
465.0

6.4
71.9
—
110.0

17.4
196.9
—
301.4

2.3
19.7
2.6
49.2

6.2
53.1
7.1
133.2

$ 886.2
$ 357.7
$ 230.0
$1,473.9

$ 712.8
$ 433.4
$ 186.2
$1,332.4

$ 461.9
$ 374.4
$
$ 836.3

$
$
— $
$

$
173.4
(75.7) $
$
43.8
$
141.5

$ 180.1
$ 138.9
$
72.9
$ 391.9

Oil, gas, and NGL production expense
(in millions)
Lease operating expenses
Transportation costs
Production taxes
Total
Realized price
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Per MCFE
Per MCFE data
Production costs:
Lease operating expense
Transportation costs
Production taxes
General and administrative
Depletion, depreciation and
amortization and asset retirement
$
obligation liability accretion
Derivative cash settlement (gain) loss(2) $ (0.22) $

$ 85.45
$
2.98
$ 37.61
6.73
$

0.82
0.63
0.33
0.55

$
$
$
$

3.32

$ 149.8
86.4
$
$
53.9
$ 290.1

$ 121.5
21.2
$
$
52.4
$ 195.1

$
$
$
$

30.3
52.5
19.0
101.8

$
$
$
$

$ 88.23
$
4.32
$ 53.32
7.85
$

$ 72.65
$
5.21
$
$

$
$
— $
$

7.60

(2.78) $
(1.34) $
(15.71) $
(1.12) $

15.58
(0.89)
53.32
0.25

0.88
0.51
0.32
0.70

$
$
$
$

1.10
0.19
0.48
0.97

$
$
$
$

(0.06) $
$
0.12
0.01
$
(0.15) $

(0.22)
0.32
(0.16)
(0.27)

28 %
20 %
75 %
29 %

28 %
19 %
75 %
29 %

24 %
(17)%
24 %
11 %

20 %
61 %
35 %
35 %

(3)%
(31)%
(29)%
(14)%

(7)%
24 %
3 %
(21)%

27 %
40 %
N/A
54 %

54 %
16 %
N/A
59 %

23 %
308 %
3 %
49 %

21 %
(17)%
N/A
3 %

(20)%
168 %
(33)%
(28)%

3.01

0.27

$
$
3.06
$ (0.22) $

0.31
$
(0.49) $

(0.05)
0.49

10 %

(181)%

(2)%

(223)%

Earnings per share information
Basic net income (loss) per common
share

$ (0.83) $

3.38

Diluted net income (loss) per common
share

$ (0.83) $

3.19

3.13

3.04

(4.21) $

0.25

(125)%

(4.02) $

0.15

(126)%

Basic weighted-average common
shares outstanding (in thousands)

Diluted weighted-average common
shares outstanding (in thousands)

65,138

63,755

62,969

1,383

786

65,138

67,564

64,689

(2,426)

2,875

2 %

(4)%

8 %

5 %

1 %

4 %

(1) Amount and percentage changes may not recalculate due to rounding.
(2) Derivative cash settlements are included within the realized hedge gain (loss) and unrealized and realized derivative (gain)
loss line items in the accompanying statements of operations.

We present per MCFE information because we use this information to evaluate our performance relative to
our peers and to identify and measure trends we believe may require analysis. Average daily production for the year
ended December 31, 2012, increased 29 percent compared to the same period in 2011, driven by the development of
our Eagle Ford shale program and a substantial increase in production from our Bakken/Three Forks program.

Changes in production volumes, revenues, and costs reflect the highly volatile nature of our industry. Our

realized price on a per MCFE basis for the year ended December 31, 2012, decreased 14 percent compared with the
same period in 2011. The decrease in realized price is due to an overall decline in commodity prices, most
significantly gas and NGL prices, during 2012.

LOE on a per MCFE basis for the year ended December 31, 2012, decreased seven percent compared with
the same period in 2011. Absolute dollars for LOE in all regions increased in 2012, however production increased
at a faster rate thereby reducing LOE on a per MCFE basis. Additionally, the 2011 divestiture of certain of our non-
strategic Mid-Continent region properties, which had meaningfully higher per unit operating costs, reduced our
LOE on a per MCFE basis for the year ended December 31, 2012. LOE in our South Texas & Gulf Coast region
decreased in the second half of 2012 due to cost saving initiatives in the region. Based upon the current level of
industry activity, we believe that LOE on a per MCFE basis will remain stable throughout 2013.

Transportation costs on a per MCFE basis for the year ended December 31, 2012, increased 24 percent
compared to the same period in 2011. This is a result of increased production in our Eagle Ford shale program,
where our transportation arrangements have higher per unit costs compared with our other regions. We anticipate
transportation costs will continue to increase on a per MCFE basis as our Eagle Ford shale program becomes a
larger portion of our total production.

Production taxes on a per MCFE basis for the year ended December 31, 2012, increased three percent
compared with the same period in 2011. In the second quarter of 2011, we were notified that we qualified for
severance tax incentive rebate programs for wells meeting specific criteria in certain areas of Texas. A sizable
incentive tax rebate was recorded in the second quarter of 2011, significantly decreasing the per MCFE rate for the
year ended December 31, 2011. We expect our future operated wells drilled in these areas to qualify for incentive
tax rebate programs. We generally expect production taxes to trend with oil, gas, and NGL revenues.

General and administrative expense on a per MCFE basis for the year ended December 31, 2012, decreased

21 percent compared with the same period in 2011, as production increased at a faster rate than our general and
administrative expense. A portion of our general and administrative expense is linked to our profitability and cash
flow, which are driven in large part by the realized commodity prices we receive for our production. The Net
Profits Plan and a portion of our short-term incentive compensation program correlate with net cash flows and
therefore are subject to variability.

DD&A expense, for the year ended December 31, 2012, increased 10 percent, on a per MCFE basis,

compared with the same period in 2011. Our DD&A rate increased as a result of the transfer of a portion of our
non-operated working interest to Mitsui, which reduced our reserve base but had no impact on the carrying value of
our assets. As we utilize our carry with Mitsui, we expect our DD&A rate to improve as we add reserves without
incurring capital costs. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning
Agreement in Part II, Item 8 of this report for additional discussion on the Mitsui transaction. Our DD&A rate can

fluctuate as a result of impairments, divestitures, and changes in the mix of our production and the underlying
proved reserve volumes. Additionally, the accounting treatment for assets that are classified as held for sale can
also impact our DD&A rate since these properties are no longer depleted.

Please refer to Comparison of Financial Results and Trends between 2012 and 2011 for additional

discussion on oil, gas, and NGL production expense, DD&A, and general and administrative expense.

Please refer to the section Earnings per Share in Note 1 - Summary of Significant Accounting Policies in
Part II, Item 8 of this report for additional discussion on the types of shares included in our basic and diluted net
income (loss) per common share calculations. During the second quarter of 2012, all of our outstanding 3.50%
Senior Convertible Notes were redeemed or net share settled following conversion. The shares issued upon
conversion are reflected in our basic weighted-average common shares outstanding calculations for the year ended
December 31, 2012. We recorded a net loss for the year ended December 31, 2012. Consequently, our in-the-
money stock options, unvested RSUs, and contingent PSUs were anti-dilutive for the year resulting in a decrease in
the diluted weighted-average common shares outstanding when compared with the year ended December 31, 2011.
Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for additional discussion on our 3.50%
Senior Convertible Notes.

Comparison of Financial Results and Trends between 2012 and 2011

Oil, gas, and NGL production revenue. The following table presents the regional changes in our production

and oil, gas, and NGL revenues and costs between the years ended December 31, 2012, and 2011:

South Texas & Gulf Coast
Rocky Mountain
Mid-Continent
Permian
Total

Average Net
Daily Production
Added (Lost)
(MMCFE/d)

Oil, Gas &
NGL Revenue
Added (Lost)
(in millions)

Production Costs
Increase
(in millions)

116.8
27.7
(10.6)
(0.7)
133.2

137.0
113.1
(92.1)
(16.5)
141.5

68.9
26.1
2.3
4.5
101.8

The largest regional production increase occurred in the South Texas & Gulf Coast region as a result of

drilling activity in our Eagle Ford shale program. Production in our Eagle Ford shale program continues to increase
and we expect it to do so for the next several years. We also saw an increase in production in our Rocky Mountain
region as a result of strong production performance from wells drilled in our Bakken/Three Forks program in late
2011 and throughout 2012.

The following table summarizes the realized prices we received in 2012 and 2011, before the effects of

derivative cash settlements:

Realized oil price ($/Bbl)
Realized gas price ($/Mcf)
Realized NGL price ($/Bbl)
Realized equivalent price ($/MCFE)

For the Years Ended December 31,

2012

2011

85.45
2.98
37.61
6.73

$
$
$
$

88.23
4.32
53.32
7.85

$
$
$
$

A 29 percent increase in production on an equivalent basis combined with a 14 percent decrease in realized
price per MCFE resulted in an 11 percent increase in revenue between the two periods. Based on current levels of
activity, we expect production volumes to increase annually for the next several years. We also expect our realized
prices to trend with commodity prices.

Realized hedge gain (loss). We recorded a net realized hedge gain of $3.9 million for the year ended

December 31, 2012, compared with a net realized hedge loss of $20.7 million for the same period in 2011. These
amounts are comprised of realized cash settlements on commodity derivative contracts that were designated as cash
flow hedges and were previously recorded in accumulated other comprehensive income (loss) (“AOCIL”). Our
realized oil, gas, and NGL hedge gains and losses are a function of commodity prices at the time of settlement
compared with the respective derivative contract prices.

Gain (loss) on divestiture activity. We recorded a net loss on divestiture activity of $27.0 million for the

year ended December 31, 2012, compared with a net gain of $220.7 million for the comparable period of 2011. The
net loss on divestiture activity for the year ended December 31, 2012, is due to a loss on unsuccessful property sale
efforts and the write-down of certain assets held for sale to their fair value. This loss was offset partially by a net
gain on completed divestitures. The net gain for the year ended December 31, 2011, relates to the divestitures of oil
and gas properties located in our South Texas & Gulf Coast, Rocky Mountain, and Mid-Continent regions. We will
continue to evaluate our portfolio to determine whether there are non-strategic properties we could divest. Please
refer to Divestiture Activity and Unsuccessful Sale of Properties above and Note 3 - Assets Held for Sale in Part II,
Item 8 of this report for additional discussion.

Marketed gas system revenue and expense. Marketed gas system revenue decreased to $52.8 million for
the year ended December 31, 2012, compared with $69.9 million for the comparable period of 2011, as a result of
lower production in the Mid-Continent region and declining gas prices. Concurrent with the decrease in marketed
gas system revenue, marketed gas system expense decreased to $47.6 million for the year ended December 31,
2012, from $64.2 million for the comparable period of 2011. There was no significant change in our net margin.
We expect that marketed gas system revenue and expense will continue to correlate with increases and decreases in
production and our realized gas price.

Oil, gas, and NGL production expense. Total production costs increased $101.8 million, or 35 percent, to

$391.9 million for the year ended December 31, 2012, compared with $290.1 million in 2011, primarily due to a 29
percent increase in net production volumes on an equivalent basis. Please refer to our caption A year-to-year
overview of selected production and financial information, including trends above for discussion of production
costs on a per MCFE basis.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense

increased 42 percent to $727.9 million in 2012 compared with $511.1 million in 2011 due to an increase in our
depreciable asset base as a result of continued development of our Eagle Ford and Bakken/Three Forks assets and
the associated growth of our production. Please refer to our caption A year-to-year overview of selected production
and financial information, including trends above for discussion of DD&A expense on a per MCFE basis.

Exploration. The components of exploration expense are summarized as follows:

For the Years Ended December 31,

2012

2011

Summary of Exploration Expense
Geological and geophysical expenses
Exploratory dry hole
Overhead and other expenses
Total

(in millions)
13.6
20.9
55.7
90.2

7.3
0.3
45.9
53.5

Exploration expense for 2012 increased 69 percent compared with the same period in 2011 as a result of

wells categorized as exploratory being classified as dry during the year, as well as an increase in exploration
overhead and geological and geophysical expenses (“G&G”) due to an increase in our exploration efforts. An
exploratory project resulting in non-commercial quantities of oil, gas, or NGLs is deemed an exploratory dry hole
and impacts the amount of exploration expense we record.

Impairment of proved properties. We recorded impairment of proved properties expense of $208.9 million

for the year ended December 31, 2012. The impairments were a result of write-downs of our Wolfberry assets in
our Permian region due to downward engineering revisions, as well as write-downs of our Haynesville shale assets
due to low natural gas prices. We recorded impairment of proved properties expense of $219.0 million for the
comparable period in 2011 related to legacy assets located in our Mid-Continent region as a result of depressed
natural gas prices.

Abandonment and impairment of unproved properties. We recorded abandonment and impairment of

unproved properties expense of $16.3 million for the year ended December 31, 2012, the majority of which related
to acreage we no longer intend to develop in our Rocky Mountain and Mid-Continent regions. We recorded $7.4
million of abandonment and impairment of unproved properties expense for the comparable period in 2011,
primarily associated with lease expirations in our Mid-Continent region. We expect abandonment and impairment
of unproved properties to more likely occur in periods of low commodity prices, which negatively impact operating
cash flows available for exploration and development, as well as anticipated economic performance.

General and administrative. General and administrative expense increased slightly to $119.8 million for

the year ended December 31, 2012, compared with $118.5 million for the same period in 2011. The change is due
to an increase in employee headcount in 2012, which resulted in an increase to base compensation, benefits, and
general corporate office expenses incurred. These were mostly offset by an increase in COPAS overhead
reimbursement as a result of an increase in operated well count, as well as an overall decrease in accruals for cash
bonus that reflect less success at reaching performance metrics when compared with the prior year. Please refer to
our caption A year-to-year overview of selected production and financial information, including trends above for
discussion of general and administrative costs on a per MCFE basis.

Change in Net Profits Plan liability. This non-cash expense generally relates to the change in the estimated

value of the associated liability between the reporting periods. For 2012, we recorded a non-cash benefit of $28.9
million compared to a non-cash benefit of $25.5 million in 2011. The change in our liability is subject to estimation
and may change dramatically from period to period based on assumptions used for production rates, reserve
quantities, commodity pricing, discount rates, and production costs. Payments made to participants as a result of
divestitures and ongoing operations will also impact our liability. Please refer to Note 11 - Fair Value
Measurements in Part II, Item 8 of this report for the impact a direct payment made to cash-out several pools had on
our change in Net Profits Plan liability in 2011.

Unrealized and realized derivative (gain) loss. We recognized an unrealized and realized derivative gain of

$55.6 million in 2012 compared to a gain of $37.1 million for the same period in 2011. Declining commodity
prices in both periods resulted in favorable derivative positions and settlements. These amounts include the change
in fair value of commodity derivative contracts and realized cash settlement gains or losses on derivatives for which
unrealized changes in fair value were not previously recorded in AOCIL. Please refer to Note 10 - Derivative
Financial Instruments in Part II, Item 8 of this report for additional discussion.

Other operating expense. Other operating expense was $7.0 million in 2012 compared with $17.6 million
in 2011. The decrease is a result of commissions and legal costs incurred in 2011 associated with our Acquisition
and Development Agreement with Mitsui, as well as legal costs incurred related to the arbitration proceedings
involving Anadarko E&P Company, LP during the second half of 2011. Please refer to Note 12 - Acquisition and
Development Agreement and Carry and Earning Agreement, in Part II, Item 8 of this report for additional
discussion of our Acquisition and Development Agreement.

Income tax benefit (expense). We recorded an income tax benefit of $29.3 million for 2012 compared to an

expense of $123.6 million for 2011, resulting in effective tax rates of 35.0 percent and 36.5 percent, respectively.
The net decrease in the rate reflects differing effects between years of the individual components of our tax rate.
Comparable valuation allowance amounts recorded on state net operating losses and charitable contributions in each
of the two years had the effect of increasing the 2011 rate of expense while decreasing the 2012 benefit rate. The
impacts from these two items were mostly offset by the effect from recognized research and development credit
benefits. Other 2012 net decreases in the effective rate resulted from changes in the mix of the highest marginal
state tax rates, the differing effects from percentage depletion and other permanent differences. The current income
tax expense in 2012 was $370,000 compared with the income tax benefit of $204,000 in 2011 which included a
federal carryback amount.

In January 2013 federal legislation was passed extending the R&D credit to our 2012 and 2013 tax years.

Since the legislation was not passed as of December 31, 2012, our 2012 income tax benefit does not reflect an
impact for 2012 credit amounts. As of the filing date of this report we have not prepared a study for 2012 while we
await the outcome of an on-going audit for R&D credits claimed for our 2007 through 2010 tax years. We are
uncertain of when we may complete a study or the impact calculated 2012 and 2013 R&D tax credits would have
on our income tax expense and tax rates for 2013. Even with a R&D credit, we expect our tax rate to be higher in
2013.

Comparison of Financial Results between 2011 and 2010

Oil, gas and NGL production revenue. Average daily production for the year ended December 31, 2011,

increased 54 percent to 465.0 MMCFE, compared with 301.4 MMCFE for the same period in 2010. The following
table presents the regional changes in our production and oil, gas, and NGL revenues and costs between the two
years. Effective January 1, 2012, we combined our ArkLaTex region into our Mid-Continent region, based in Tulsa,
Oklahoma, for operational and reporting purposes. Prior period presentation has been conformed to reflect this
change.

South Texas & Gulf Coast
Rocky Mountain
Mid-Continent
Permian
Total

Average Net Daily
Production Added
(Lost)
(MMCFE/d)

Oil and Gas Revenue
Added (Lost)
(in millions)

Production Costs
Increase (Decrease)
(in millions)

129.0
4.9
38.4
(8.7)
163.6

348.9
96.1
63.3
(12.2)
496.1

79.0
12.2
4.1
(0.3)
95.0

The largest regional production increase occurred in the South Texas & Gulf Coast region as a result of
production from drilling activity in our Eagle Ford shale program. We also saw an increase in production in our
Mid-Continent region as a result of strong production performance from wells drilled in our Haynesville shale
program in late 2010 and early 2011.

The following table summarizes the average realized prices we received in 2011 and 2010, before the

effects of derivative cash settlements:

For the Years Ended December 31,

2011

2010

Realized oil price ($/Bbl)
$
Realized gas price ($/Mcf)
$
Realized NGL price ($/Bbl)
$
$
Realized equivalent price ($/MCFE)
Note: Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head.
Beginning in the first quarter of 2011, we changed our reporting for natural gas volumes to separately show natural gas and
NGL production volumes, revenues, and pricing consistent with title transfer for each product.

72.65
5.21
—
7.60

88.23
4.32
53.32
7.85

$
$
$
$

The three percent increase in average realized prices per MCFE coupled with a 54 percent increase in

production volumes between periods resulted in a meaningful increase in revenue.

Realized hedge gain (loss). We recorded a net realized hedge loss of $20.7 million for the year ended

December 31, 2011, compared with a net realized hedge gain of $23.5 million for the same period in 2010. The
realized net loss in 2011 is comprised of realized cash settlements on commodity contracts that were previously
recorded in AOCL, whereas the realized net gain in 2010 is comprised of realized cash settlements on all
commodity derivative contracts.

Gain (loss) on divestiture activity. We recorded a gain on divestiture activity of $220.7 million, which was

net of the $27.5 million write-down related to our Marcellus shale assets, for the year ended December 31, 2011,
compared with a gain of $155.3 million for the comparable period of 2010. The 2011 gain related to the
divestitures of oil and gas properties located in our South Texas & Gulf Coast, Rocky Mountain, and Mid-Continent
regions. The 2010 gain related to the divestitures of oil and gas properties located in our Rocky Mountain and
Permian regions.

Marketed gas system revenue and expense. Marketed gas system revenue was $69.9 million for the year
ended December 31, 2011, which was relatively flat compared to $70.1 million for the year ended December 31,
2010. Concurrent with the decrease in marketed gas system revenue, marketed gas system expense decreased to
$64.2 million for the year ended December 31, 2011, from $66.7 million for the comparable period of 2010.

Oil and gas production expense. Total production costs increased $95.0 million, or 49 percent, to $290.1

million for the year ended December 31, 2011, compared with $195.1 million in 2010 due primarily to a 54 percent
increase in equivalent production volumes in 2011. Total oil, gas, and NGL production costs per MCFE decreased
$0.06 to $1.71 for the year ended December 31, 2011, compared with $1.77 in 2010, due to a decrease in recurring
LOE resulting from the sale of non-strategic properties with higher per unit LOE costs, as well as a decrease in
production taxes per MCFE due to severance tax incentives in our South Texas & Gulf Coast and Mid-Continent
regions. These decreases were offset slightly by an increase in transportation costs per MCFE, which was primarily
a result of increased production in our Eagle Ford shale program where our transportation agreements have higher
per unit transportation costs due to the lack of infrastructure in the emerging play.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense

increased 52 percent to $511.1 million for the year ended December 31, 2011, compared with $336.1 million in
2010. The increase in overall DD&A expense was due to increased production. DD&A expense per MCFE
decreased two percent to $3.01 for the year ended December 31, 2011, compared to $3.06 in 2010 due to an
increase in our reserve base and production volumes, while our property balances remained relatively constant
between the two periods.

Exploration. The components of exploration expense are summarized as follows:

For the Years Ended December 31,

2011

2010

Summary of Exploration Expense
Geological and geophysical expenses
Exploratory dry hole
Overhead and other expenses
Total

(in millions)
7.3
0.3
45.9
53.5

21.5
0.3
42.1
63.9

Exploration expense in 2011 decreased 16 percent compared to the same period in 2010 due to a reduction
in geological and geophysical expense, as a result of a decrease in our exploration efforts in 2011. The increase in
exploration overhead costs related to equity incentive compensation expense as discussed under General and
administrative below.

Impairment of proved properties. We recorded $219.0 million of impairment of proved properties expense
in 2011, compared to $6.1 million in 2010. The impairment in 2011 related to assets located in our Mid-Continent
region that were impacted by significantly lower natural gas prices in the second half of 2011.

Abandonment and impairment of unproved properties. We recorded abandonment and impairment of

unproved properties expense of $7.4 million for the year ended December 31, 2011, associated with lease
expirations in our Mid-Continent region. We recorded $2.0 million of abandonment and impairment of unproved
properties expense for the comparable period in 2010, associated with lease expirations in our Rocky Mountain and
Mid-Continent regions.

General and administrative. General and administrative expense increased 11 percent to $118.5 million for

the year ended December 31, 2011, compared with $106.7 million for the same period in 2010. The change was
due to an increase in base and equity incentive compensation and accruals for cash bonuses, as well as an increase
in corporate office expenses as a result of an increase in employee headcount between the two periods. General and
administrative expense per MCFE decreased $0.27 to $0.70 per MCFE for the year ended December 31, 2011,
compared to $0.97 in 2010, mostly due to our production increasing at a faster rate than our general and
administrative expense.

Change in Net Profits Plan liability. For 2011, the change in the Net Profits Plan liability, a non-cash item,
was a $25.5 million benefit compared to a $34.4 million benefit in 2010. This non-cash charge or benefit is directly
related to the change in the estimated value of the associated liability between the reporting periods. Please refer to
Note 11 - Fair Value Measurements in Part II, Item 8 of this report for the impact a direct payment made to cash-out
several pools had on our change in Net Profits Plan liability in 2011.

Unrealized and realized derivative (gain) loss. We recognized an unrealized and realized derivative gain of

$37.1 million in 2011 compared to a loss of $8.9 million for the same period in 2010. The 2011 amount includes
gains resulting from unrealized changes in fair value on commodity derivative contracts of $62.8 million and
realized cash settlement losses on derivatives for which unrealized changes in fair value were not previously
recorded in other comprehensive loss of $25.7 million. The 2010 activity is comprised solely of the ineffective
portion of derivatives designated as cash flow hedges.

Other operating expense. Other operating expense was $17.6 million in 2011 compared with $3.0 million

in 2010. The increase was a result of commission and legal costs associated with our Acquisition and Development
Agreement with Mitsui, as well as legal costs related to the arbitration proceedings against Anadarko E&P
Company, LP during the second half of 2011.

Income tax benefit (expense). Income tax expense totaled $123.6 million for 2011 compared to tax

expense of $118.1 million for 2010, resulting in effective tax rates of 36.5 percent and 37.5 percent, respectively.
The effective rate change from 2010 primarily reflected changes in the mix of the highest marginal state tax rates, a
multi-year research and experimentation credit claim, an adjustment for anticipated utilization of charitable
contributions carryovers, and differing effects of other permanent differences including percentage depletion. The
current income tax benefit in 2011 was $204,000 compared with current income tax expense of $3.5 million in
2010. These amounts were three percent of the total income tax expense for 2010 and were not material for 2011.

Overview of Liquidity and Capital Resources

We believe we have sufficient liquidity and capital resources to execute our business plan for the
foreseeable future. We continue to manage the duration and level of our drilling and completion services
commitments in order to provide us with some flexibility to reduce activity and capital expenditures in periods of
prolonged commodity price decline.

Sources of cash

We currently expect our 2013 capital program to be partially funded by cash flows from operations, with an

anticipated shortfall to be funded by borrowings under our credit facility. Although we anticipate that cash flow
from operations and borrowing capacity under our credit facility will be sufficient to fund our expected 2013 capital
program, we may also elect to access the capital markets, depending on prevailing market conditions. The
divestiture of certain oil and gas properties is also a potential source of funding and we will continue to evaluate our
portfolio to identify potential divestiture candidates.

Our primary sources of liquidity are the cash flows provided by our operating activities, borrowings under

our credit facility, proceeds received from divestitures of properties, and other financing alternatives, including
accessing capital markets. From time to time, we may enter into carrying cost funding and sharing arrangements
with third parties for particular exploration and/or development programs. All of our sources of liquidity can be
impacted by the general condition of the broader economy and by fluctuations in commodity prices, operating costs,
and volumes produced, all of which affect us and our industry. We have no control over the market prices for oil,
gas, or NGLs, although we are able to influence the amount of our realized revenues from our oil, gas, and NGL
sales through the use of derivative contracts as part of our commodity price risk management program. The
borrowing base under our credit facility could be reduced as a result of lower commodity prices, divestitures of
producing properties, or newly issued debt. See “Credit Facility” below for a discussion of our most recent
borrowing base redetermination. Historically, decreases in commodity prices have limited our industry’s access to
capital markets.

In the second quarter of 2012, we issued $400.0 million in aggregate principal amount of 6.50% Senior

Notes due 2023. Additionally, some of the proceeds from our 2021 Notes issued in the fourth quarter of 2011 were
available for use in 2012. In late 2011, we consummated our Acquisition and Development Agreement with Mitsui
pursuant to which Mitsui funds, or carries, 90 percent of certain drilling and completion costs attributable to our
remaining interest in our non-operated Eagle Ford shale acreage until $680.0 million has been expended on our
behalf. Of the original $680.0 million carry amount, $277.5 million had been spent as of December 31, 2012. The
remaining carry is expected to be realized over approximately the next two years. Please refer to Note 12 -
Acquisition and Development Agreement and Carry and Earning Agreement in Part II, Item 8 of this report for
additional discussion.

Proposals to fund the federal government budget continue to include eliminating or reducing current tax
deductions for intangible drilling costs, the domestic production activities deduction, and percentage depletion.
Legislation modifying or eliminating these deductions would have the immediate effect of reducing operating cash
flows thereby reducing funding available for our exploration and development capital programs and those of our
peers in the industry. If enacted, these funding reductions could have a significant adverse effect on drilling in the
United States for a number of years.

Credit facility

In May 2011, we entered into our Fourth Amended and Restated Credit Agreement, providing a $2.5 billion

senior secured revolving credit facility with a scheduled maturity date of May 27, 2016. In the third quarter of
2012, our borrowing base under the credit facility was increased to $1.55 billion from $1.4 billion. Our borrowing
base is subject to regular semi-annual redeterminations by our lenders and the next scheduled re-determination date
is April 1, 2013. As of the filing date of this report, our lenders have committed to a current aggregate commitment
amount of $1.0 billion under the credit agreement. We believe the current commitment amount is sufficient to meet
our anticipated liquidity and operating needs. Through the filing date of this report, we have experienced no issues
utilizing our credit facility. No individual bank participating in our credit facility represents more than 10 percent
of the lending commitments under the credit facility.

The following table presents the outstanding balance, total amount of letters of credit, and available
borrowing capacity under our credit facility as of February 14, 2013, December 31, 2012, and December 31, 2011.

As of February 14, 2013 As of December 31, 2012 As of December 31, 2011
(in millions)

340.0 $
Credit facility balance
Letters of credit (1)
0.8 $
Available borrowing capacity
659.2 $
(1) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.

407.5 $
0.8 $
591.7 $

$
$
$

—
0.6
999.4

Our daily weighted-average credit facility debt balance was approximately $171.8 million and $10.7

million for the years ended December 31, 2012, and 2011, respectively. Borrowings under our credit facility are
secured by mortgages on substantially all of our proved oil and gas properties.

Weighted-average interest rates

Our weighted-average interest rates in the current and prior year include accrued interest payments, cash

fees paid on the unused portion of the credit facility’s aggregate commitment amount, letter of credit fees,
amortization of the debt discount related to our 3.50% Senior Convertible Notes through April 2, 2012, and
amortization of deferred financing costs. Our weighted-average borrowing rate is calculated using only our accrued
interest and fee payments.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates

for the years ended December 31, 2012, 2011, and 2010.

Weighted-average interest rate
Weighted-average borrowing rate

For the Years Ended December 31,
2011

2010

2012

8.5%
5.2%

8.3%
2.8%

6.4%
5.5%

The decrease in our weighted-average interest rate from 2011 is a result of our Senior Notes being
outstanding for all or a part of the year ended December 31, 2012, with rates below the 2011 average interest rate,
as well as a higher average balance on our revolving credit facility, which provides a lower interest rate than all our
fixed debt instruments and which reduces the fee paid on the unused portion of our aggregate commitment.

Our weighted-average borrowing rate for the year ended December 31, 2012, was impacted by the three

tranches of high yield unsecured debt we have issued since February 2011, as well as the redemption and settlement
of our 3.50% Senior Convertible Notes that occurred in the second quarter of 2012. Each tranche of high yield
unsecured debt has a coupon rate that is higher than the coupon rate on the 3.50% Senior Convertible Notes, and is
also higher than the average borrowing rate on the credit facility incurred during 2011. This had the effect of
increasing our average borrowing rate since high yield unsecured debt replaced lower cost secured bank debt and
our 3.50% Senior Convertible Notes.

We are subject to customary covenants under our credit facility, including limitations on dividend payments
and requirements to maintain certain financial ratios, which include debt to EBITDAX, as defined under the caption
Non-GAAP Financial Measures below, of less than 4.0 to 1.0 and an adjusted current ratio, as defined by our credit
agreement, of no less than 1.0. As of December 31, 2012, our debt to EBITDAX ratio and adjusted current ratio, as
defined by our credit agreement, were 1.40 and 1.81, respectively. As of the filing date of this report, we are in
compliance with all financial and non-financial covenants under our credit facility.

Uses of cash

We use cash for the acquisition, exploration, and development of oil and gas properties and for the payment
of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest.
Expenditures for the exploration and development of oil and gas properties are the primary use of our capital
resources. During 2012, we spent $1.5 billion for exploration and development capital expenditures, and leasehold
acquisition. These amounts differ from the cost incurred amounts, which are accrual-based and include asset
retirement obligation, G&G, and exploration overhead amounts.

The amount and allocation of future capital expenditures will depend upon a number of factors, including

the number and size of available acquisition and drilling opportunities, our cash flow from operating, investing, and
financing activities, and our ability to assimilate acquisitions and execute our drilling program. In addition, the
impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, and the timing and results
of our operated and non-operated development and exploratory activities may lead to changes in funding
requirements for future development. We regularly review our capital expenditure budget to assess changes in
current and projected cash flows, potential acquisition and divestiture activities, debt requirements, and other
factors.

We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or

through exchanges for other securities. Such repurchases or exchanges may be made in open market transactions,
privately negotiated transactions, or otherwise. Any such repurchases or exchanges will depend on prevailing
market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other
factors. The amounts involved in any such transaction may be material.

As of the filing date of this report, subject to the approval of our Board of Directors, we could repurchase

up to 3,072,184 shares of our common stock under our stock repurchase program. Shares may be repurchased from
time to time in open market transactions or privately negotiated transactions, subject to market conditions and other
factors, including certain provisions of our credit facility and the indentures governing our Senior Notes,
compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of
Directors reviews this program as part of the allocation of our capital. During 2012, we did not repurchase any
shares of our common stock, and we currently do not plan to repurchase any outstanding shares.

During 2012, we paid $6.5 million in dividends to our stockholders, which constitutes a dividend of $0.10
per share. Our intention is to continue to make dividend payments for the foreseeable future, subject to our future
earnings, our financial condition, credit facility and other covenants, and other factors which could arise. Payment
of future dividends remains at the discretion of our Board of Directors. Additionally, during the second quarter of
2012 we paid $287.5 million to settle our 3.50% Senior Convertible Notes.

The following table presents changes in cash flows between the years ended December 31, 2012, 2011, and

2010, for our operating, investing, and financing activities. The analysis following the table should be read in
conjunction with our statements of cash flows in Part II, Item 8 of this report.

For the Years Ended
December 31,
2011

2010

2012

Amount of Changes
Between

2012/2011

2011/2010

Percent of Change
Between
2012/2011 2011/2010

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

(in millions)

922.0 $

760.5 $

497.1 $

161.5 $

263.4

21 %

53 %

$ (1,457.3) $ (1,264.9) $

(361.6) $

(192.4) $

(903.3)

15 %

250 %

422.1 $

618.5 $

(141.1) $

(196.4) $

759.6

(32)%

(538)%

Analysis of cash flow changes between 2012 and 2011

Operating activities. Cash received from oil, gas, and NGL production revenues, including derivative cash

settlements, increased $256.5 million, or 21 percent, to $1.5 billion for the year ended December 31, 2012,
compared with the same period in 2011. This increase was due to an increase in production volumes and favorable
derivative settlements resulting from declining commodity prices throughout the year. Cash paid for lease operating
expenses in 2012 increased $28.4 million compared with 2011 due to increased production and higher service costs
caused by increased demand for those services. Cash paid for interest during 2012 increased $29.2 million
compared with the same period in 2011 due to interest payments on our Senior Notes, as well as an increase in
interest payments under our credit facility arising from an increase in our weighted-average borrowings for the year.

Investing activities. Capital expenditures in 2012 decreased $125.3 million, or eight percent, compared
with the same period in 2011. This decrease was a result of being carried for substantially all of our drilling and
completion costs in our outside operated Eagle Ford program. Net proceeds from the sale of oil and gas properties
decreased $309.1 million between the two periods due to a decrease in divestiture activity in 2012.

Financing activities. During 2012, we paid $287.5 million to settle our 3.50% Senior Convertible Notes.

We received $392.1 million of net proceeds from the issuance of our 2023 Notes in 2012, compared with $684.2
million of proceeds from the issuance of our 2019 Notes and 2021 Notes in 2011. We had net borrowings under our
credit facility of $340.0 million during 2012, compared with net repayments of $48.0 million made during 2011.

Analysis of cash flow changes between 2011 and 2010

Operating activities. Cash received from oil, gas, and NGL production revenues, including derivative cash
settlements, increased $409.4 million to $1.2 billion for the year ended December 31, 2011. The increase was due
to an increase in production volumes. Cash paid for lease operating expenses in 2011 increased $26.5 million
compared with 2010. We received $4.0 million in income tax refunds in 2011 compared to $25.6 million received
during 2010.

Investing activities. Cash used for investing activities was $1.3 billion for the year ended December 31,
2011, compared with $361.6 million for the same period in 2010. Cash spent on capital expenditures increased
$964.8 million, or 144 percent, to $1.6 billion. This increase in capital and exploration activities was financed
mainly by higher cash flows available from operating activities, divestiture proceeds, and proceeds from the
issuance of our 2019 Notes and 2021 Notes. Proceeds received from divestitures increased $53.0 million to $364.5
million for the year ended December 31, 2011, due to an increase in the size of the divestiture packages.

Financing activities. Net repayments to our credit facility decreased $92.0 million for the year ended

December 31, 2011, compared to 2010 as our strong cash position throughout 2011 resulted in decreased
borrowings. After deducting aggregate fees of $15.8 million, we received aggregate net proceeds of $684.2 million
due to the issuance of our 2019 Notes and 2021 Notes during 2011. We spent $8.7 million on debt issuance costs
for our amended credit facility during the year ended December 31, 2011.

Interest Rate Risk

We are exposed to market risk due to the floating interest rate on our revolving credit facility. Our credit

agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit
facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes affect the
credit facility’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion
of the credit facility that has a floating interest rate, interest rate changes will not affect the fair market value but
will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of
interest we pay on our fixed-rate Senior Notes, but can impact fair market values. As of December 31, 2012, our
fixed-rate debt outstanding totaled $1.1 billion. As of December 31, 2012, we had $340.0 million of floating-rate
debt outstanding. The carrying amount of our floating-rate debt at December 31, 2012, approximates its fair value.
Assuming a constant floating-rate debt level of $340.0 million, the before-tax cash flow impact resulting from a 100
basis point change in our interest rate would be $3.4 million over a 12-month time period.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production heavily impacts our revenue, overall profitability,
access to capital and future rate of growth. Oil, gas, and NGLs are subject to wide fluctuations in response to relatively
minor changes in supply and demand. Historically, the markets for oil, gas, and NGLs have been volatile, and these
markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous
factors beyond our control. Based on our 2012 production, a 10 percent decrease in our average realized price received
for oil, gas, and NGLs would have reduced our oil, gas, and NGL production revenues by $88.6 million, $35.8 million,
and $23.0 million, respectively.

The fair values of our commodity derivative contracts are largely determined by estimates of the forward
curves of the relevant price indices. At December 31, 2012, a 10 percent increase and 10 percent decrease in the
forward curves associated with our commodity derivative instruments would have changed our net asset positions
by the following amounts:

Gain/(loss):
Gas derivatives
Oil derivatives
NGL derivatives

10% Increase 10% Decrease
(in thousands)

$
$
$

(66.9)
(29.0)
(5.4)

$
$
$

61.9
29.0
5.4

We enter into commodity derivative contracts in order to reduce the impact of fluctuations in commodity

prices. Please refer to Note 10 – Derivative Financial Instruments of Part II, Item 8 of this report for additional
information about our oil, gas, and NGL derivative contracts, and additional information below under the caption
Summary of Oil, Gas, and NGL Derivative Contracts in Place.

Summary of Oil, Gas, and NGL Derivative Contracts in Place

Our oil, gas, and NGL derivative contracts include costless swaps and costless collar arrangements. All

contracts are entered into for other-than-trading purposes. Please refer to Note 10 – Derivative Financial
Instruments in Part II, Item 8 of this report for additional information regarding accounting for our derivative
transactions.

As of December 31, 2012, our commodity derivative contracts through the third quarter of 2015 totaled

10.1 million Bbls of oil, 80.7 million MMBtu of gas, and 1.2 million Bbls of NGLs. As of February 14, 2013, the
Company had commodity derivative contracts in place through the fourth quarter of 2015 for a total of 14.5 million
Bbls of oil, 114.8 million MMBtu of gas, and 2.0 million Bbls of NGLs.

In a typical commodity swap agreement, if the agreed-upon published third-party index price is lower than

the swap fixed price, we receive the difference between the index price and the agreed upon swap fixed price. If the
index price is higher than the swap fixed price, we pay the difference. For collar agreements, we receive the
difference between an agreed upon index and the floor price if the index price is below the floor price. We pay the
difference between the agreed upon contracted ceiling price and the index price if the index price is above the
contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and
ceiling prices.

The following tables summarize the approximate volumes, average contract prices, and fair value of

contracts we had in place as of December 31, 2012:

Oil contracts

Oil Swaps:

Contract Period

First quarter 2013
Second quarter 2013
Third quarter 2013
Fourth quarter 2013
2014
2015
All oil swaps

NYMEX WTI
Volumes
(Bbls)

Weighted-
Average
Contract
Price
(per Bbl)

Fair Value at
December 31, 2012
(Liability)
(in millions)

514,000
534,000
300,000
265,000
1,256,000
355,000
3,224,000

$
$
$
$
$
$

89.87
88.99
91.47
91.22
90.92
88.40

(1.3)
(2.4)
(0.7)
(0.5)
(1.7)
(0.7)
(7.3)

Oil Collars:

Contract Period

First quarter 2013
Second quarter 2013
Third quarter 2013
Fourth quarter 2013
2014
2015
All oil collars

Natural Gas Contracts

Natural Gas Swaps:

Contract Period

First quarter 2013
Second quarter 2013
Third quarter 2013
Fourth quarter 2013
2014
2015
All natural gas swaps*

NYMEX WTI
Volumes
(Bbls)

Weighted-
Average
Floor
Price
(per Bbl)

Weighted-
Average
Ceiling
Price
(per Bbl)

Fair Value at
December 31, 2012
Asset (Liability)
(in millions)

755,000
620,000
765,000
727,000
2,174,000
1,814,000
6,855,000

$
$
$
$
$
$

79.87
76.65
74.89
81.02
83.71
85.00

$
$
$
$
$
$

107.36
109.08
107.98
116.09
107.93
95.51

0.1
0.2
(0.3)
1.8
5.2
(0.1)
6.9

Volumes
(MMBtu)

8,611,000
7,205,000
6,114,000
5,593,000
23,309,000
17,469,000
68,301,000

$
$
$
$
$
$

Weighted-
Average
Contract
Price
(per MMBtu)

Fair Value at
December 31, 2012
Asset (Liability)
(in millions)

4.34
3.99
4.19
4.38
4.14
4.02

9.2
4.5
4.2
3.9
4.4
(1.2)
25.0

*Natural gas swaps are comprised of IF El Paso Permian (2%), IF HSC (56%), IF NGPL TXOK (4%), IF PEPL
(16%), IF Reliant N/S (17%), and IF TETCO STX (5%).

Natural Gas Collars:

Contract Period

First quarter 2013
Second quarter 2013
Third quarter 2013
Fourth quarter 2013
2014
All natural gas collars*

Weighted-
Average
Floor
Price
(per MMBtu)

Weighted-
Average
Ceiling
Price
(per MMBtu)

Fair Value at
December 31, 2012
Asset
(in millions)

4.39
4.39
4.39
4.39
4.38

$
$
$
$
$

5.46
5.32
5.31
5.31
5.36

1.5
2.0
1.7
1.4
4.0
10.6

Volumes
(MMBtu)

1,330,000
1,910,000
1,770,000
1,640,000
5,734,000
12,384,000

$
$
$
$
$

*Natural gas collars are comprised of IF HSC (18%), IF NGPL TXOK (18%), IF Reliant N/S (29%), and IF
TETCO STX (35%).

NGL Contracts

NGL Swaps:

Contract Period

First quarter 2013
Second quarter 2013
Third quarter 2013
Fourth quarter 2013
All NGL swaps*

Volumes
(Bbls)

436,000
371,000
222,000
206,000
1,235,000

$
$
$
$

Weighted-
Average
Contract
Price
(per Bbl)

Fair Value at
December 31, 2012
Asset
(in millions)

46.21
42.74
50.45
50.27

1.3
1.3
0.5
0.4
3.5

*NGL swaps are comprised of OPIS Mont. Belvieu Purity Ethane (37%), OPIS Mont. Belvieu LDH Propane
(25%), OPIS Mont. Belvieu NON-LDH Isobutane (2%), OPIS Mont. Belvieu NON-LDH Normal Butane (16%),
and OPIS Mont. Belvieu NON-LDH Natural Gasoline (20%).

Commodity Derivative Contracts Entered into After December 31, 2012

The following tables summarize all commodity derivative contracts entered between January 1, 2013, and

February 14, 2013:

Oil contracts

Oil Swaps:

Contract Period

First quarter 2013
Second quarter 2013
Third quarter 2013
Fourth quarter 2013
2014
All oil swaps

Oil Collars:

Contract Period

2014
2015
All oil collars

NYMEX WTI
Volumes
(Bbls)

Weighted-
Average
Contract
Price
(per Bbl)

220,000
559,000
458,000
392,000
344,000
1,973,000

$
$
$
$
$

98.25
98.25
97.50
95.85
95.85

NYMEX WTI
Volumes
(Bbls)

847,000
1,552,000
2,399,000

$
$

Weighted-
Average
Floor
Price
(per Bbl)

Weighted-
Average
Ceiling
Price
(per Bbl)

85.00
85.00

$
$

99.10
92.79

Natural Gas Contracts

Natural Gas Swaps:

Contract Period

Third quarter 2013
Fourth quarter 2013
2014
All natural gas swaps*

Weighted-
Average
Contract
Price
(per MMBtu)

3.57
3.57
3.90

Volumes
(MMBtu)

3,542,000
2,925,000
13,208,000
19,675,000

$
$
$

*Natural gas swaps are comprised of IF El Paso Permian (4%), IF HSC (77%), IF NGPL TXOK (3%), IF NNG
Ventura (6%), IF PEPL (10%).

Natural Gas Collars:

Contract Period

2015
All natural gas collars*

NYMEX WTI
Volumes
(MMBtu)

14,480,000
14,480,000

Weighted-
Average
Floor
Price
(per MMBtu)

Weighted-
Average
Ceiling
Price
(per MMBtu)

3.96

4.30

*Natural gas collars are comprised of IF El Paso Permian (4%), IF HSC (72%), IF NNG Ventura (7%), IF PEPL
(10%), IF Reliant N/S (7%).

NGL Contracts

NGL Swaps:

Contract Period

First quarter 2013
Second quarter 2013
Third quarter 2013
Fourth quarter 2013
2014
All NGL swaps*

Weighted-
Average
Contract
Price
(per Bbl)

75.37
74.36
74.25
74.20
75.87

Volumes
(Bbls)

60,000
181,000
153,000
136,000
208,000
738,000

$
$
$
$
$

*NGL swaps are comprised of OPIS Mont. Belvieu NON-LDH Isobutane (38%), OPIS Mont. Belvieu NON-LDH
Natural Gasoline (34%), and OPIS Mont. Belvieu NON-LDH Normal Butane (28%).

Schedule of Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2012, for the periods specified

(in millions):

Contractual Obligations
Long-term debt (1)
Interest payments (2)
Delivery commitments (3)
Operating leases and contracts (3)
Derivative liability (4)
Net Profits Plan (5)
Asset retirement obligations (6)
Other (7)
Total

Total

Less than
1 year

1-3 years

— $

1,440.0
624.3
858.7
153.9
15.8
77.5
120.5
23.2
3,313.9

77.9
53.2
74.6
9.0
16.6
35.8
2.3
269.4

155.8
170.7
40.8
6.8
28.9
7.1
20.5
430.6

3-5 years
340.0
146.3
193.0
11.0
—
22.5
4.7
0.1
717.6

More than
5 years

1,100.0
244.3
441.8
27.5
—
9.5
72.9
0.3
1,896.3

(1) Long-term debt consists of our Senior Notes and the outstanding balance under our long-term revolving credit
facility, and assumes no principal repayment until the due dates of the instruments. The actual payments under
our revolving credit facility may vary significantly.

(2) Interest payments on our Senior Notes are estimated assuming no principal repayment until the due dates of the
instruments. Interest payments on our credit facility have been estimated using a rate of 1.75 percent and
assume no principal repayment until the May 27, 2016, due date.

(3) Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional

discussion regarding our operating leases, contracts, and gathering, processing, and transportation through-put
commitments.

(4) Amount shown represents only the liability portion of the marked-to-market value of our commodity

derivatives based on future market prices at December 31, 2012, and excludes estimated oil, gas, and NGL
commodity derivative receipts. This amount varies from the liability amounts presented on the accompanying
balance sheets, as those amounts are presented at fair value, which considers time value, volatility, and the risk
of non-performance for us and for our counterparties. The ultimate settlement amounts under our derivative
contracts are unknown, however, as they are subject to continuing market risk and commodity price
volatility. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for
additional discussion regarding our derivative contracts.

(5) Amount shown represents undiscounted forecasted payments for the Net Profits Plan for the next six years.

Payments are expected to gradually decrease for the years beyond what are shown in this table and are not
included due to these payments being highly variable, as outlined below. The amount recorded on the
accompanying balance sheets reflects all future Net Profits Plan payments and the impact of discounting, and
therefore differs from the amounts disclosed in this table. The variability in the amount of payments will be a
direct reflection of commodity prices, production rates, capital expenditures, and operating costs in future
periods. Predicting the timing and amounts of payments associated with this liability is contingent upon
estimates of appropriate discount factors, adjusting for risk and time value, and upon a number of factors we
cannot control. Please refer to Note 7 – Compensation Plans and Note 11 - Fair Value Measurements in Part II,
Item 8 of this report for additional discussion regarding our Net Profits Plan liability.

(6) Amount shown represents estimated future discounted abandonment costs. These obligations are recorded as

liabilities on our December 31, 2012, accompanying balance sheets. The ultimate settlement of these
obligations is unknown and can be impacted by federal and state regulations, as well as economic factors and
therefore the actual timing of abandonment costs may vary significantly. Please refer to Note 9 – Asset
Retirement Obligations in Part II, Item 8 of this report for additional discussion regarding our asset retirement
obligations.

(7) The majority of the amount shown represents the remaining funded portion of our estimated pension liability of
$20.0 million, although we recognize that we cannot accurately determine the timing of future payments, as
well as insignificant amounts related to uncertain tax positions and our cash settlement balancing payable. We
are expected to make contributions to the Pension Plan in 2013 of $373,000. We made contributions of $5.4
million and $5.3 million in 2012 and 2011, respectively, toward our pension liability.

In addition to the amounts in the above table, we entered into a three-year capital project commencing in

2011 for the development of infrastructure in our non-operated Eagle Ford shale play. Pursuant to the terms of the
agreement for the construction, ownership and operation of the assets, we are required to pay our portion of the
costs. Based on current estimates, we do not expect costs to exceed approximately $67 million over the remaining
term of the agreement.

Off-balance Sheet Arrangements

As part of our ongoing business, we have not participated in transactions that generate relationships with
unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special
purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements
or other contractually narrow or limited purposes. As of December 31, 2012, we have not been involved in any
unconsolidated special purpose entity transactions.

We evaluate our transactions to determine if any variable interest entities exist. If it is determined that we

are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial
statements.

Critical Accounting Policies and Estimates

Our discussion of financial condition and results of operations is based upon the information reported in our

consolidated financial statements. The preparation of these consolidated financial statements in conformity with
accounting principles generally accepted in the United States (“GAAP”) requires us to make assumptions and
estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of
contingent assets and liabilities as of the date of our financial statements. We base our assumptions and estimates
on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual
results may differ from the estimates we calculate due to changes in circumstances, global economics and politics,
and general business conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary
of Significant Accounting Policies in Part II, Item 8 of this report. We have outlined below those policies identified
as being critical to the understanding of our business and results of operations and that require the application of
significant management judgment.

Oil and gas reserve quantities. Our estimated reserve quantities and future net cash flows are critical to the

understanding of the value of our business. They are used in comparative financial ratios and are the basis for
significant accounting estimates in our financial statements, including the calculations of depletion and impairment
of proved oil and gas properties and the estimate of our Net Profits Plan liability. Future cash inflows and future
production and development costs are determined by applying prices and costs, including transportation, quality
differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves
remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an
appropriate discount rate. For example, the standardized measure calculations require a 10 percent discount rate to

be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped
locations are more imprecise than those of established producing oil and gas properties, we make a considerable
effort in estimating our reserves, including using independent reserve engineering consultants. We expect that
periodic reserve estimates will change in the future as additional information becomes available and as commodity
prices and operating and capital costs change. We evaluate and estimate our proved reserves at June 30 and
December 31 of each year. For purposes of depletion and impairment, reserve quantities are adjusted in accordance
with GAAP for the impact of additions and dispositions. Changes in depletion or impairment calculations caused
by changes in reserve quantities or net cash flows are recorded in the period the reserve estimates change. Please
refer to Supplemental Oil and Gas Information in Part II, Item 8 of this report.

The following table presents information about reserve changes from period to period due to items we do

not control, such as price, and from changes due to production history and well performance. These changes do not
require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop
other estimated proved reserves.

For the Years Ended December 31,
2010
2011
BCFE
BCFE
Change
Change

2012
BCFE
Change

Revisions resulting from price changes
Revisions resulting from performance (1)
Total
(1) Performance revisions include the removal of proved undeveloped reserves that are no longer in our development plan

(72.7)
(92.0)
(164.7)

42.6
(17.9)
24.7

(25.3)
36.8
11.5

within five years. 2011 includes the impact of our conversion to three stream production reporting.

As previously noted, commodity prices are volatile, and estimates of reserves are inherently imprecise.

Consequently, we expect to continue experiencing these types of changes. Please refer to additional reserves
discussion under Overview of the Company.

The following table reflects the estimated BCFE change and percentage change to our total reported reserve

volumes from the described hypothetical changes:

2012

For the Years Ended December 31,
2011

2010

BCFE
Change

Percentage
Change

BCFE
Change

Percentage
Change

BCFE
Change

Percentage
Change

A 10% decrease in SEC

pricing

A 10% decrease in proved
undeveloped reserves

(67.4)

(76.1)

(4)%

(22.2)

(41.5)

(2)%

(3)%

(13.9)

(29.7)

(1)%

(3)%

The table above solely reflects the impact of a 10 percent change in SEC pricing or decrease in proved
undeveloped reserves and does not include additional impacts to our proved reserves that may result from our
internal intent to drill hurdles. Additional reserve information can be found in the reserve table and discussion
included in Items 1 and 2 of Part I of this report, and in Supplemental Oil and Gas Disclosures of Part II, Item 8 of
this report.

Successful efforts method of accounting. GAAP provides for two alternative methods for the oil and gas
industry to use in accounting for oil and gas producing activities. These two methods are generally known in our
industry as the full cost method and the successful efforts method. Both methods are widely used. The methods are
different enough that in many circumstances the same set of facts will provide materially different financial

statement results within a given year. We have chosen the successful efforts method of accounting for our oil and
gas producing activities. A more detailed description is included in Note 1 - Summary of Significant Accounting
Policies of Part II, Item 8 of this report.

Revenue recognition. Our revenue recognition policy is significant because revenue is a key component of

our results of operations and our forward-looking statements contained in our analysis of liquidity and capital
resources. We derive our revenue primarily from the sale of produced oil, gas, and NGLs. We report revenue as the
gross amounts we receive before taking into account production taxes and transportation costs, which are reported
as separate expenses. Revenue is recorded in the month our production is delivered to the purchaser, but payment is
generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is
determined that title to the product has transferred to a purchaser. At the end of each month, we make estimates of
the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our
properties, their historical performance, NYMEX and local spot market prices, and other factors as the basis for
these estimates. Variances between our estimates and the actual amounts received are recorded in the month
payment is received. A 10 percent change in our year end revenue accrual would have impacted net income before
tax by approximately $16 million in 2012.

Change in Net Profits Plan Liability. We record the estimated liability of future payments for our Net

Profits Plan. The estimated liability is calculated based on a number of assumptions, including estimates of proved
reserves, estimated future capital, present value discount factors, pricing assumptions, and overall market
conditions. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for additional
discussion.

Asset retirement obligations. We are required to recognize an estimated liability for future costs associated

with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical
experience in abandoning oil and gas wells projected into the future based on our current understanding of federal
and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our
properties, assume what future inflation rates apply to external estimates, and determine what credit-adjusted risk-
free discount rate to use. The impact to the accompanying statements of operations from these estimates is reflected
in our depreciation, depletion, and amortization calculations and occurs over the remaining life of our respective oil
and gas properties. Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of this report for
additional discussion.

Impairment of oil and gas properties. Our proved oil and gas properties are recorded at cost. We evaluate

our proved properties for impairment when events or changes in circumstances indicate that a decline in the
recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and
gas properties and compare these undiscounted cash flows to the carrying amount of the oil and gas properties to
determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future
cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to
determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future
production estimates, estimated future capital expenditures, and discount rates.

Unproved oil and gas properties are assessed periodically for impairment on a lease-by-lease basis based on
the remaining lease terms, drilling results, commodity price outlook, and future capital allocations. An impairment
allowance is provided on unproven property when we determine that the property will not be developed or the
carrying value will not be realized. Please refer to Impairment of Proved and Unproved Properties in Note 1 -
Summary of Significant Accounting Policies in Part II, Item 8 of this report for impairment results.

Derivatives and Hedging. We periodically enter into commodity derivative contracts to manage our
exposure to oil, gas and NGL price volatility. The accounting treatment for the change in fair value of a derivative
instrument is dependent upon whether or not a derivative instrument is designated as a cash flow hedge. Effective
January 1, 2011, we elected to de-designate all of our commodity derivatives that had previously been designated as
cash flow hedges as of December 31, 2010, and have elected to discontinue hedge accounting prospectively.

Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is
effective, in accumulated other comprehensive loss until the hedged item is recognized in earnings. Changes in the
fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no
effect on the statement of income because changes in fair value of the derivative offsets changes in the fair value of
the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a
fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings. Hedge effectiveness is
assessed at least quarterly based on total changes in the derivative’s fair value and any ineffective portion of the
derivative instrument’s change in fair value is recognized immediately in earnings. The estimated fair value of our
derivative instruments requires substantial judgment. These values are based upon, among other things, whether or
not the forecasted hedged transaction will occur, option pricing models, futures prices, volatility, time to maturity
and credit risk. The values we report in our financial statements change as these estimates are revised to reflect
actual results, changes in market conditions or other factors, many of which are beyond our control.

Income taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or

liability and its carrying amount in our financial statements. This difference will result in taxable income or
deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively.
Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is
more likely than not. Additionally, our federal and state income tax returns are generally not filed before the
consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at
the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss
carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts
we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in
our estimates of asset recovery and liability settlement could have an impact on our results of operations. A one
percent increase and decrease in our effective tax rate would have changed our calculated income tax benefit by
approximately $832,000 and $839,000, respectively, for the year ended December 31, 2012.

Accounting Matters

Please refer to the section entitled Recently Issued Accounting Standards under Note 1 – Summary of

Significant Accounting Policies for additional information on the recent adoption of new authoritative accounting
guidance in Part II, Item 8 of this report.

Environmental

We believe we are in substantial compliance with environmental laws and regulations and do not currently

anticipate that material future expenditures will be required under the existing regulatory framework. However,
environmental laws and regulations are subject to frequent changes, and we are unable to predict the impact that
compliance with future laws or regulations, such as those currently being considered as discussed below, may have
on future capital expenditures, liquidity, and results of operations.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate

production of hydrocarbons, particularly natural gas, from tight formations. For additional information about
hydraulic fracturing and related environmental matters, see Risk Factors – Risks Related to Our Business –
Proposed federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in
increased costs and additional operating restrictions or delays.

Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane, and

other ‘‘greenhouse gases’’ present an endangerment to public health and the environment because emissions of such
gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.
Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of
greenhouse gases under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating
greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from
motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary
sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas
emissions from specified large greenhouse gas emission sources in the United States, including petroleum
refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain
onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in
2011.

In addition, the United States Congress has from time to time considered adopting legislation to reduce

emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce
emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories
and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring
major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas
processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase
is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

In terms of opportunities, the regulation of greenhouse gas emissions and the introduction of alternative

incentives, such as enhanced oil recovery, carbon sequestration and low carbon fuel standards, could benefit us in a
variety of ways. For example, although climate change legislation could reduce the overall demand for the oil and
natural gas that we produce, the relative demand for natural gas may increase because the burning of natural gas
produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if
renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants may
provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel
standards, natural gas may become a more attractive transportation fuel. Approximately 55 and 59 percent of our
production on an MCFE basis in 2012 and 2011, respectively, was natural gas. Market-based incentives for the
capture and storage of carbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could
also benefit us through the potential to obtain greenhouse gas emission allowances or offsets from or government
incentives for the sequestration of carbon dioxide.

Non-GAAP Financial Measures

EBITDAX represents income (loss) before interest expense, interest income, income taxes, depreciation,
depletion, amortization and accretion, exploration expense, property impairments, non-cash stock compensation
expense, unrealized derivative gains and losses, change in the Net Profits Plan liability, and gains and losses on
divestitures. EBITDAX excludes certain items that we believe affect the comparability of operating results and can
exclude items that are generally one-time or whose timing and/or amount cannot be reasonably estimated.
EBITDAX is a non-GAAP measure that is presented because we believe that it provides useful additional

information to investors, as a performance measure, for analysis of our ability to internally generate funds for
exploration, development, acquisitions, and to service debt. We are also subject to a financial covenant under our
credit facility based on our debt to EBITDAX ratio. In addition, EBITDAX is widely used by professional research
analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas
exploration and production industry, and many investors use the published research of industry research analysts in
making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income
(loss), income (loss) from operations, net cash provided by (used in) operating activities, profitability, or liquidity
measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income (loss)
and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of
other companies. The following table provides reconciliations of our net income (loss) and net cash provided by
operating activities to EBITDAX for the periods presented:

Net income (loss) (GAAP)
Interest expense
Interest income
Income tax (benefit) expense
Depletion, depreciation, amortization, and asset retirement
obligation liability accretion
Exploration
Impairment of proved properties
Abandonment and impairment of unproved properties
Stock-based compensation expense
Unrealized derivative (gain) loss
Change in Net Profits Plan liability
(Gain) loss on divestiture activity
EBITDAX (Non-GAAP)
Interest expense
Interest income
Income tax benefit (expense)
Exploration
Exploratory dry hole expense
Amortization of debt discount and deferred financing costs
Deferred income taxes
Plugging and abandonment
Other
Changes in current assets and liabilities
Net cash provided by operating activities (GAAP)

For the Years Ended December 31,
2010
2011
2012
(in thousands)

(54,249) $
63,720
(220)
(29,268)

215,416 $
45,849
(466)
123,585

727,877
81,809
208,923
16,342
30,185
(11,366)
(28,904)
27,018
1,031,867
(63,720)
220
29,268
(81,809)
20,861
6,769
(29,638)
(2,856)
527
10,480
921,969 $

511,103
46,776
219,037
7,367
26,824
(62,757)
(25,477)
(220,676)
886,581
(45,849)
466
(123,585)
(46,776)
277
18,299
123,789
(5,849)
(6,027)
(40,794)
760,532 $

196,837
24,196
(321)
118,059

336,141
56,184
6,127
1,986
26,743
8,899
(34,441)
(155,277)
585,133
(24,196)
321
(118,059)
(56,184)
289
13,464
114,517
(8,314)
(3,993)
(5,881)
497,097

Note: Stock-based compensation expense is a component of exploration expense and general and administrative expense on
the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary
from the amount shown on the accompanying statements of operations for the component of stock-based compensation
expense recorded to exploration.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item is provided under the captions Commodity Price Risk and Interest
Rate Risk and Summary of Oil, Gas, and NGL Derivative Contracts in Place in Item 7 above and is incorporated
herein by reference.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
SM Energy Company and Subsidiaries
Denver, Colorado

We have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries (the
“Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations,
comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended
December 31, 2012. These financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position
of SM Energy Company and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and
their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting
principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the Company’s internal control over financial reporting as of December 31, 2012, based on the
criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission, and our report dated February 21, 2013, expressed an unqualified
opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
February 21, 2013

SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share amounts)

December 31,

2012

2011

ASSETS

Current assets:

Cash and cash equivalents
Accounts receivable (note 2)
Refundable income taxes
Prepaid expenses and other
Derivative asset
Deferred income taxes
Total current assets

Property and equipment (successful efforts method), at cost:

Land
Proved oil and gas properties
Less - accumulated depletion, depreciation, and amortization
Unproved oil and gas properties
Wells in progress
Materials inventory, at lower of cost or market
Oil and gas properties held for sale net of accumulated depletion, depreciation and
amortization of $20,676 in 2012 and $10,714 in 2011

Other property and equipment, net of accumulated depreciation of $22,442 in 2012 and
$23,985 in 2011

Total property and equipment, net

Other noncurrent assets:

Derivative asset
Restricted cash
Other noncurrent assets

Total other noncurrent assets

Total Assets

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts payable and accrued expenses (note 2)
Derivative liability
Other current liabilities

Total current liabilities

Noncurrent liabilities:

Long-term credit facility
3.50% Senior Convertible Notes, net of unamortized discount of $2,431 in 2011
6.625% Senior Notes due 2019
6.50% Senior Notes due 2021
6.50% Senior Notes due 2023
Asset retirement obligation
Asset retirement obligation associated with oil and gas properties held for sale
Net Profits Plan liability
Deferred income taxes
Derivative liability
Other noncurrent liabilities

Total noncurrent liabilities

Commitments and contingencies (note 6)

Stockholders' equity:

Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 66,245,816 shares
in 2012 and 64,145,482 shares in 2011; outstanding, net of treasury shares: 66,195,235
shares in 2012 and 64,064,415 shares in 2011

Additional paid-in capital
Treasury stock, at cost: 50,581 shares in 2012 and 81,067 shares in 2011
Retained earnings
Accumulated other comprehensive loss

Total stockholders' equity

Total Liabilities and Stockholders' Equity

5,926
254,805
3,364
30,017
37,873
8,579
340,564

1,845
5,401,684
(2,376,170)
175,287
273,928
13,444

33,620

153,559

3,677,197

16,466
86,773
78,529
181,768
4,199,529

525,627
8,999
6,920
541,546

340,000
—
350,000
350,000
400,000
112,912
1,393
78,827
537,383
6,645
66,357
2,243,517

662

233,642
(1,221)
1,190,397
(9,014)
1,414,466
4,199,529

119,194
210,368
5,581
68,026
55,813
4,222
463,204

1,548
4,378,987
(1,766,445)
120,966
273,428
16,537

246

71,369

3,096,636

31,062
124,703
83,375
239,140
3,798,980

456,999
42,806
6,000
505,805

—
285,069
350,000
350,000
—
87,167
1,277
107,731
568,263
12,875
67,853
1,830,235

641

216,966
(1,544)
1,251,157
(4,280)
1,462,940
3,798,980

The accompanying notes are an integral part of these consolidated financial statements.
90

SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)

Operating revenues and other income:

Oil, gas, and NGL production revenue

Realized hedge gain (loss)

Gain (loss) on divestiture activity

Marketed gas system revenue

Other operating revenue

For the Years
Ended December 31,
2011

2012

2010

1,473,868

3,866
(27,018)
52,808

1,578

1,332,392
(20,707)
220,676

69,898

1,059

836,288

23,465

155,277

70,110

7,694

Total operating revenues and other income

1,505,102

1,603,318

1,092,834

Operating expenses:

Oil, gas, and NGL production expense

391,872

290,111

195,075

Depletion, depreciation, amortization, and asset retirement
obligation liability accretion

Exploration

Impairment of proved properties

Abandonment and impairment of unproved properties

General and administrative

Change in Net Profits Plan liability

Unrealized and realized derivative (gain) loss

Marketed gas system expense

Other operating expense

Total operating expenses

Income (loss) from operations

Nonoperating income (expense):

Interest income

Interest expense

Income (loss) before income taxes

Income tax benefit (expense)
Net income (loss)

Basic weighted-average common shares outstanding
Diluted weighted-average common shares outstanding
Basic net income (loss) per common share
Diluted net income (loss) per common share

727,877

90,248

208,923

16,342

119,815
(28,904)
(55,630)
47,583

6,993

511,103

53,537

219,037

7,367

118,526
(25,477)
(37,086)
64,249

17,567

1,525,119
(20,017)

1,218,934

384,384

220
(63,720)
(83,517)
29,268
(54,249) $
65,138
65,138

(0.83) $
(0.83) $

466
(45,849)
339,001
(123,585)
215,416

63,755
67,564
3.38
3.19

$
$

336,141

63,860

6,127

1,986

106,663
(34,441)
8,899

66,726

3,027

754,063

338,771

321
(24,196)
314,896
(118,059)
196,837

62,969
64,689
3.13
3.04

The accompanying notes are an integral part of these consolidated financial statements.

SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)

Net income (loss)
Other comprehensive income (loss), net of tax:
Change in derivative instrument fair value
Reclassification to earnings
Pension liability adjustment
Total other comprehensive income (loss), net of tax
Total comprehensive income (loss)

For the Years
Ended December 31,
2011

2012

2010

(54,249)

215,416

196,837

—
(2,264)
(2,470)
(4,734)
(58,983)

—
12,997
(1,795)
11,202
226,618

16,811
6,641
(980)
22,472
219,309

The accompanying notes are an integral part of these consolidated financial statements.

SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands, except share amounts)

Common Stock

Amount

Additional
Paid-in
Capital

Treasury Stock

Amount

Retained
Earnings

Accumulated
Other
Comprehensive
Loss

Total
Stockholders’
Equity

Balances, January 1, 2010

62,899,122

629

$ 160,516

(126,893) $ (1,204) $ 851,583

(37,954) $

Net income

Other comprehensive income

Cash dividends, $ 0.10 per share

Issuance of common stock under
Employee Stock Purchase Plan
Issuance of common stock upon
vesting of RSUs, net of shares used
for tax withholdings, including
income tax cost of RSUs

Issuance of common stock upon
stock option exercises, including
income tax benefit

—

52,948

113,103

346,377

—

1,669

(2,094)

5,621

—

196,837

—

(6,297)

—

Stock-based compensation expense
Balances, December 31, 2010

1,250
63,412,800

—
634

25,962
$ 191,674

24,258
(102,635) $

781
—
(423) $ 1,042,123

Net income

Other comprehensive income

Cash dividends, $ 0.10 per share

Issuance of common stock under
Employee Stock Purchase Plan
Issuance of common stock upon
vesting of RSUs and settlement of
PSUs, net of shares used for tax
withholdings

Issuance of common stock upon
stock option exercises

—

41,358

278,773

412,551

Stock-based compensation expense
Balances, December 31, 2011

—
64,145,482

Net loss

Other comprehensive loss

Cash dividends, $ 0.10 per share

Issuance of common stock under
Employee Stock Purchase Plan
Issuance of common stock upon
vesting of RSUs and settlement of
PSUs, net of shares used for tax
withholdings

Issuance of common stock upon
stock option exercises
Conversion of 3.50% Senior
Convertible Notes to common
stock, including income tax benefit
of conversion
Stock-based compensation expense
Balances, December 31, 2012

—

66,485

929,375

240,368

864,106

—
66,245,816

—

—
641

—

2,300

(9,976)

5,023

—

215,416

—

(6,382)

—

27,945
$ 216,966

21,568
—
(1,121)
(81,067) $ (1,544) $ 1,251,157

—
(4,280) $

26,824
1,462,940

—

2,775

(21,631)

3,038

2,632

—

(54,249)

—

(6,511)

—

(4,734)

—

(54,249)

(4,734)

(6,511)

2,776

(21,622)

3,040

2,641

—
662

29,862
$ 233,642

—
323
30,486
(50,581) $ (1,221) $ 1,190,397

—
(9,014) $

30,185
1,414,466

—

22,472

—

—
(15,482) $

—

11,202

—

973,570

196,837

22,472

(6,297)

1,670

(2,093)

5,624

26,743
1,218,526

215,416

11,202

(6,382)

2,300

(9,973)

5,027

The accompanying notes are an integral part of these consolidated financial statements.

SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

Cash flows from operating activities:

Net income (loss)

Adjustments to reconcile net income (loss) to net cash provided by operating
activities:

(Gain) loss on divestiture activity

Depletion, depreciation, amortization, and asset retirement obligation liability
accretion
Exploratory dry hole expense

Impairment of proved properties

Abandonment and impairment of unproved properties

Stock-based compensation expense

Change in Net Profits Plan liability

Unrealized derivative (gain) loss

Amortization of debt discount and deferred financing costs

Deferred income taxes

Plugging and abandonment

Other

Changes in current assets and liabilities:

Accounts receivable

Refundable income taxes

Prepaid expenses and other

Accounts payable and accrued expenses

Excess income tax benefit from the exercise of stock awards

Net cash provided by operating activities

Cash flows from investing activities:

Net proceeds from sale of oil and gas properties

Capital expenditures

Acquisition of oil and gas properties

Other

Net cash used in investing activities

Cash flows from financing activities:

Proceeds from credit facility

Repayment of credit facility

Debt issuance costs related to credit facility

Net proceeds from 6.625% Senior Notes due 2019

Net proceeds from 6.50% Senior Notes due 2021

Net proceeds from 6.50% Senior Notes due 2023

Repayment of 3.50% Senior Convertible Notes

Proceeds from sale of common stock

Dividends paid

Net share settlement from issuance of stock awards

Excess income tax benefit from the exercise of stock awards

Other

Net cash provided by (used in) financing activities

Net change in cash and cash equivalents

Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period

For the Years Ended
December 31,

2012

2011

2010

(54,249) $

215,416

196,837

27,018

727,877

20,861

208,923

16,342

30,185

(28,904)

(11,366)

6,769

(29,638)

(2,856)

527

(21,389)

2,217

(1,484)

31,136

—
921,969

55,375

(1,507,828)

(5,773)

893
(1,457,333)

1,609,000

(1,269,000)

—

392,138

(287,500)

5,816

(6,511)

(21,622)

—

(225)
422,096

(113,268)

119,194
5,926

(220,676)

511,103

277

219,037

7,367

26,824

(25,477)

(62,757)

18,299

123,789

(5,849)

(6,027)

(41,998)

2,901

16,376

(18,073)

—
760,532

364,522

(1,633,093)

—

3,661
(1,264,910)

322,000

(370,000)

(8,719)

341,122

343,120

—

7,327

(6,382)

(9,973)

—

—
618,495

114,117

5,077
119,194

(155,277)

336,141

289

6,127

1,986

26,743

(34,441)

8,899

13,464

114,517

(8,314)

(3,993)

(47,153)

24,291

(35,363)

53,198

(854)
497,097

311,504

(668,288)

(664)

(4,125)
(361,573)

571,559

(711,559)

—

6,440

(6,297)

(2,093)

854

—
(141,096)

(5,572)

10,649
5,077

The accompanying notes are an integral part of these consolidated financial statements.

SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

Supplemental schedule of additional cash flow information and non-cash investing and financing activities:

Cash paid for interest, net of capitalized interest

Net cash refunded for income taxes

For the Years Ended
December 31,

2012

2011

2010

(in thousands)

(51,328) $

(22,133) $

(13,340)

1,389

4,046

25,578

At December 31, 2012, 2011, and 2010, $262.8 million, $214.8 million, and $238.5 million, respectively, are included

as additions to oil and gas properties and accounts payable and accrued expenses. These oil and gas property additions are
reflected in cash used in investing activities in the periods that the payables are settled.

SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies

Description of Operations

SM Energy is an independent energy company engaged in the acquisition, exploration, development, and
production of oil, gas, and NGLs in onshore North America, with a current focus on oil and liquids-rich resource
plays.

Basis of Presentation

The accompanying consolidated financial statements include the accounts of the Company and its wholly-

owned subsidiaries and have been prepared in accordance with GAAP and the instructions to Form 10-K and
regulation S-X. Subsidiaries that the Company does not control are accounted for using the equity or cost methods
as appropriate. Equity method investments are included in other noncurrent assets in the accompanying
consolidated balance sheets (“accompanying balance sheets”). Intercompany accounts and transactions have been
eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated
subsequent events after the balance sheet date of December 31, 2012, through the filing date of this report.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with GAAP requires management to make estimates
and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of
contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and
gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization (“DD&A”),
impairment of proved properties, asset retirement obligations, and the Net Profits Interest Bonus Plan (“Net Profits
Plan”) liability, each of which represents a significant component of the accompanying consolidated financial
statements.

Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to
be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term
nature of these instruments.

Restricted Cash

The Company’s restricted cash balance represents cash payments received from Mitsui that are
contractually restricted to be used solely for development operations pursuant to the Company’s Acquisition and
Development Agreement with Mitsui and accordingly are classified as non-current assets. Please refer to Note 12-
Acquisition and Development Agreement and Carry and Earning Agreement for additional information.

Accounts Receivable

The Company’s accounts receivables consist mainly of receivables from oil, gas, and NGL purchasers and

from joint interest owners on properties the Company operates. For receivables from joint interest owners, the
Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest
billings. Generally, the Company’s oil and gas receivables are collected within two months, and the Company has
had minimal bad debts.

Although diversified among many companies, collectability is dependent upon the financial wherewithal of
each individual company and is influenced by the general economic conditions of the industry. Receivables are not
collateralized. As of December 31, 2012, and 2011, the Company had no allowance for doubtful accounts recorded.

Concentration of Credit Risk and Major Customers

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion
of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties
is subject to continuous review. During 2012, we had two major customers, Regency Gas Services LLC and Plains
Marketing LP, which accounted for approximately 21 percent and 13 percent, respectively, of our total production
revenue. During 2011 and 2010, we had one major customer, Regency Gas Services LLC, individually account for
approximately 18 percent and 11 percent, respectively, of our total production revenue.

The Company currently uses 10 separate counterparties for its oil, gas, and NGL commodity derivatives, all

of which are participating lenders in the Company’s credit facility. Two of our counterparties were downgraded
during 2012, but all maintain investment grade ratings. Nine counterparties carry corporate credit ratings at or
exceeding A- and Baa2 by Standard & Poor’s and Moody’s, respectively. The remaining counterparty fell to BBB-
and Baa2, respectively. In response, the Company requires cash collateral to be posted when its portfolio of trades
with that counterparty is in an overall asset position.

The Company has accounts in the following locations with a national bank: Denver, Colorado; Shreveport,
Louisiana; Houston, Texas; Midland, Texas; and Billings, Montana. The Company has accounts with a local bank
in Tulsa, Oklahoma. The Company’s policy is to invest in highly-rated instruments and to limit the amount of
credit exposure at each individual institution.

Oil and Gas Producing Activities

The Company accounts for its oil and gas exploration and development costs using the successful efforts

method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending
further evaluation of whether economically recoverable reserves have been found. If economically recoverable
reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts
method of accounting requires management’s judgment to determine the proper designation of wells as either
development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes.
Once a well is drilled, the determination that economic proved reserves have been discovered may take
considerable time and judgment. Exploratory dry hole costs are included in cash flows from investing activities as
part of capital expenditures within the accompanying consolidated statements of cash flows (“accompanying
statements of cash flows”). The costs of development wells are capitalized whether those wells are successful or
unsuccessful.

DD&A of capitalized costs related to proved oil and gas properties is calculated on a pool-by-pool basis

using the units-of-production method based upon proved reserves. The computation of DD&A takes into
consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging
equipment. As of December 31, 2012, and 2011, the Company’s estimated salvage value was $64.4 million and
$64.1 million, respectively.

Materials Inventory

The Company’s materials inventory is primarily comprised of tubular goods to be used in future drilling

operations. Materials inventory is valued at the lower of cost or market and totaled $13.4 million and $16.5 million
at December 31, 2012, and 2011, respectively. There were no materials inventory write-downs for the years ended
December 31, 2012, 2011, or 2010.

Assets Held for Sale

Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are
separately presented on the accompanying balance sheets at the lower of net book value or fair value less the cost to
sell. The asset retirement obligation liabilities related to such properties have been reclassified to asset retirement
obligations associated with oil and gas properties held for sale in the accompanying balance sheets. For additional
discussion on assets held for sale, please refer to Note 3 – Divestitures and Assets Held for Sale.

Other Property and Equipment

Other property and equipment such as facilities, office furniture and equipment, buildings, and computer

hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the
useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is
calculated using either the straight-line method over the estimated useful lives of the assets, which range from three
to thirty years, or the unit of output method where appropriate. When other property and equipment is sold or
retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Intangible Assets

As of December 31, 2012, and 2011, the Company had $10.8 million and $7.1 million, respectively, of

intangible assets consisting of acquired water rights, which are included as other noncurrent assets in the
accompanying balance sheets. All indefinite lived intangible assets are evaluated for impairment if such indicators
arise and at least annually.

Cash Settlement Balancing

The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized on

all gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the
property. An asset or liability is recognized to the extent that there is an imbalance in excess of the remaining gas
reserves on the underlying properties. As of December 31, 2012, and 2011, the Company has recorded a receivable
of $1.7 million and $1.9 million, respectively, and a liability of $1.3 million and $1.1 million, respectively, which is
included as other noncurrent assets and other noncurrent liabilities in the accompanying balance sheets.

Derivative Financial Instruments

The Company seeks to manage or reduce commodity price risk on production by entering into derivative

contracts. The Company seeks to minimize its basis risk and indexes its oil derivative contracts to NYMEX prices,
its NGL derivative contracts to OPIS prices, and the majority of its gas derivative contracts to various regional
index prices associated with pipelines in proximity to the Company’s areas of gas production. For additional
discussion on derivatives, please see Note 10 – Derivative Financial Instruments.

Net Profits Plan

The Company records the estimated fair value of expected future payments made under the Net Profits Plan
as a noncurrent liability in the accompanying balance sheets. The underlying assumptions used in the calculation of
the estimated liability include estimates of production, proved reserves, recurring and workover lease operating
expense, transportation, production and ad valorem tax rates, present value discount factors, pricing assumptions,
and overall market conditions. The estimates used in calculating the long-term liability are adjusted from period-to-
period based on the most current information attributable to the underlying assumptions. Changes in the estimated
liability of future payments associated with the Net Profits Plan are recorded as increases or decreases to expense in
the current period as a separate line item in the accompanying consolidated statements of operations
(“accompanying statements of operations”), as these changes are considered changes in estimates.

The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash

compensation related to periodic operations are recognized as compensation expense and are included within
general and administrative expense and exploration expense in the accompanying statements of operations. The
corresponding current liability is included in accounts payable and accrued expenses in the accompanying balance
sheets. This treatment provides for a consistent matching of cash expense with net cash flows from the oil and gas
properties in each respective pool of the Net Profits Plan. For additional discussion, please refer to the heading Net
Profits Plan in Note 7 – Compensation Plans and Note 11 – Fair Value Measurements.

Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil
and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the
carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase
in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company
depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the
accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas
properties. For additional discussion, please refer to Note 9 – Asset Retirement Obligations.

Revenue Recognition

The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. The Company

reports revenue as the gross amount received before taking into account production taxes and transportation costs,
which are reported separately as expenses and are included in oil, gas, and NGL production expense in the
accompanying statements of operations. Revenue is recorded in the month the Company’s production is delivered
to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No
revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of
each month, the Company estimates the amount of production delivered to the purchaser and the price the Company
will receive. The Company uses its knowledge of its properties, their historical performance, NYMEX, OPIS, and
local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates.

Impairment of Proved and Unproved Properties

Proved oil and gas property costs are evaluated for impairment and reduced to fair value, which is based on

expected future discounted cash flows, when there is an indication that the carrying costs may not be recoverable.
Expected future cash flows are calculated on all developed proved reserves and risk adjusted proved undeveloped,
probable, and possible reserves using a discount rate and price forecasts selected by the Company’s management.
The discount rate is a rate that management believes is representative of current market conditions. The prices for
oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years,
after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using
OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal
price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. An impairment is
recorded on unproved property when the Company determines that either the property will not be developed or the
carrying value is not realizable.

The Company recorded $208.9 million, $219.0 million, and $6.1 million, of proved property impairments

for the years ended December 31, 2012, 2011, and 2010, respectively. The impairments in 2012 were a result of the
Company’s write-down of Wolfberry assets in its Permian region due to negative engineering revisions and the
Company’s Haynesville shale assets as a result of low natural gas prices. The impairments in 2011 were related to
the Company’s James Lime, Cotton Valley, and Haynesville shale assets as a result of significantly lower natural
gas prices at the end of 2011.

For the years ended December 31, 2012, 2011, and 2010, the Company recorded expense related to the

abandonment and impairment of unproved properties of $16.3 million, $7.4 million, and $2.0 million, respectively.
The Company’s abandonment and impairment of unproved properties in 2012 related to acreage that the Company
no longer intends to develop in the Rocky Mountain region.

Sales of Proved and Unproved Properties

The partial sale of proved properties within an existing field is accounted for as normal retirement and no
gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-
production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a
recovery of cost. A gain or loss on divestiture activity is recognized in the accompanying statements of operations
for all other sales of proved properties.

The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty

exists as to the ultimate recovery of the cost applicable to the interest retained. A gain on divestiture activity is
recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A gain or loss
on divestiture activity is recognized in the accompanying statements of operations for all other sales of unproved
property. For additional discussion, please refer to Note 3 – Divestitures and Assets Held for Sale.

Stock-Based Compensation

At December 31, 2012, the Company had stock-based employee compensation plans that included RSUs,

PSUs, restricted stock awards, and stock options issued to employees and non-employee directors, as more fully
described in Note 7 - Compensation Plans. The Company records expense associated with the fair value of stock-
based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair
value of these awards determined at the time of grant.

Income Taxes

The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized
based on the tax effects of temporary differences between the carrying amounts on the financial statements and the
tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in
taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or
settled, respectively. The Company records deferred tax assets and associated valuation allowances, when
appropriate, to reflect amounts more likely than not to be realized based upon Company analysis.

Earnings per Share

Basic net income (loss) per common share is calculated by dividing net income or loss available to common

stockholders by the basic weighted-average common shares outstanding for the respective period. The earnings
per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.

Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the
diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities.
Potentially dilutive securities for this calculation consist of in-the-money outstanding stock options, unvested RSUs,
contingent PSUs, and shares into which the 3.50% Senior Convertible Notes were convertible. When there is a loss
from continuing operations, as was the case for the year ended December 31, 2012, all potentially dilutive shares
are anti-dilutive and are consequently excluded from the calculation of earnings per share.

PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year

performance period, a number of shares of the Company’s common stock that may range from zero to two times the
number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on
the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that

100

date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please
refer to Note 7 – Compensation Plans under the heading Performance Share Units Under the Equity Incentive
Compensation Plan.

The Company called for redemption of its 3.50% Senior Convertible Notes on April 2, 2012, after which
the majority of the holders of the outstanding 3.50% Senior Convertible Notes elected to convert their notes. The
Company issued 864,106 common shares upon conversion, and these shares were included in the calculation of
basic weighted-average common shares outstanding for the year ended December 31, 2012. Please refer to Note 5 -
Long-term Debt for additional discussion. Prior to calling the 3.50% Senior Convertible Notes for redemption, the
Company’s notes had a net-share settlement right giving the Company the option to irrevocably elect, by notice to
the trustee under the indenture for the notes, to settle the Company’s obligation, in the event that holders of the
notes elected to convert all or a portion of their notes, by delivering cash in an amount equal to each $1,000
principal amount of notes surrendered for conversion and, if applicable, at the Company’s option, shares of
common stock or cash, or any combination of common stock and cash, for the amount of conversion value in
excess of the principal amount. Prior to the settlement of the Company’s 3.50% Senior Convertible Notes,
potentially dilutive shares associated with the conversion feature were accounted for using the treasury stock
method when shares of the Company’s common stock traded at an average closing price that exceeded the $54.42
conversion price. Shares of the Company’s common stock traded at an average closing price exceeding the
conversion price and were included on an adjusted weighted basis for the portion of the year ended December 31,
2012, for which they were outstanding. Shares of the Company’s common stock traded at an average closing price
exceeding the $54.42 conversion price for the twelve-month period ended December 31, 2011, making the 3.50%
Senior Convertible Notes dilutive for that period. Shares of the Company's common stock did not trade at an
average closing price exceeding the $54.42 conversion price for the year ended December 31, 2010. Therefore, the
3.50% Senior Convertible Notes were not dilutive and did not impact the diluted earnings per share calculation for
the year ended December 31, 2010.

The treasury stock method is used to measure the dilutive impact of in-the-money stock options, unvested

RSUs, contingent PSUs, and 3.50% Senior Convertible Notes.

The following table details the weighted-average dilutive and anti-dilutive securities related to stock

options, RSUs, PSUs, and the 3.50% Senior Convertible Notes for the years presented:

Dilutive
Anti-dilutive

2012

For the Years Ended December 31,
2011
(in thousands)
3,809
—

—
2,102

2010

1,720
—

101

The following table sets forth the calculations of basic and diluted earnings per share:

Net income (loss)
Basic weighted-average common shares outstanding

Add: dilutive effect of stock options, unvested RSUs,
and contingent PSUs
Add: dilutive effect of 3.50% Senior Convertible Notes

Diluted weighted-average common shares outstanding
Basic net income (loss) per common share
Diluted net income (loss) per common share

$
$

Comprehensive Income (Loss)

For the Years Ended December 31,
2012
2010
2011
(in thousands, except per share amounts)

(54,249) $
65,138

215,416
63,755

196,837
62,969

—
—
65,138

(0.83) $
(0.83) $

2,592
1,217
67,564
3.38
3.19

$
$

1,720
—
64,689
3.13
3.04

Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss).

Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are
reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss)
is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss).

102

The changes in the balances of components comprising other comprehensive income (loss) are presented in

the following table:

Change in
Derivative
Instrument Fair
Value

Derivative
Reclassification
to Earnings
(in thousands)

Pension Liability
Adjustments

26,904
(10,093)
16,811

— $
—
— $

10,608
(3,967)
6,641

20,707
(7,710)
12,997

(3,865)
1,601
(2,264)

(1,570)
590
(980)

(2,779)
984
(1,795)

(3,909)
1,439
(2,470)

For the year ended December 31, 2010

Before tax income (loss)
Tax benefit (expense)
Income (loss), net of tax

For the year ended December 31, 2011

Before tax income (loss)
Tax benefit (expense)
Income (loss), net of tax

For the year ended December 31, 2012

Before tax (loss)
Tax benefit
(Loss), net of tax

Fair Value of Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts receivable, and

accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these
instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a
floating rate that approximates a current market rate. The Company had $340.0 million of outstanding loans under
its credit facility as of December 31, 2012. The Company had no borrowings outstanding under its credit facility as
of December 31, 2011. The Company’s 3.50% Senior Convertible Notes, 2019 Notes, 2021 Notes, and 2023 Notes,
are recorded at cost, and the fair values are disclosed in Note 11 - Fair Value Measurements. The Company has
derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop
estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would
realize upon the sale or refinancing of such instruments.

Industry Segment and Geographic Information

The Company operates exclusively in the exploration and production segment of the oil and gas industry
and all of the Company’s operations are conducted entirely in the United States. The Company reports as a single
industry segment. The Company’s gas marketing function provides mostly internal services and acts as the first
purchaser of natural gas and natural gas liquids produced by the Company in certain cases. The Company considers
its marketing function as ancillary to its oil and gas producing activities. The amount of income these operations
generate from marketing gas produced by third parties is not material to the Company’s results of operations, and
segmentation of such activity would not provide a better understanding of the Company’s performance. However,
gross revenue and expense related to marketing activities for gas produced by third parties are presented in the
marketed gas system revenue and marketed gas system expense line items in the accompanying statements of
operations.

103

Off-Balance Sheet Arrangements

The Company has not participated in transactions that generate relationships with unconsolidated entities or

financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”),
which would have been established for the purpose of facilitating off-balance sheet arrangements or other
contractually narrow or limited purposes. The Company has not been involved in any unconsolidated SPE
transactions.

The Company evaluates its transactions to determine if any variable interest entities exist. If it is
determined that SM Energy is the primary beneficiary of a variable interest entity, that entity is consolidated into
SM Energy.

Recently Issued Accounting Standards

On January 1, 2012, the Company adopted new fair value measurement authoritative accounting guidance

issued by the FASB, that clarifies the application of fair value measurement and disclosure requirements and
changes particular principles and requirements for measuring fair value. For each class of assets and liabilities not
measured at fair value in the Company’s financial statements but for which fair value is disclosed, this guidance
requires the Company to disclose the nature, characteristics, and risks of the asset or liability and the level of the
fair value hierarchy within which the fair value measurement is categorized. Please refer to Note 11 - Fair Value
Measurements in which the changes to the Company’s financial statements resulting from the new authoritative
guidance are presented.

On January 1, 2012, the Company adopted new authoritative accounting guidance issued by the FASB
stating an entity that reports items of other comprehensive income has the option to present the components of
comprehensive income in either one continuous financial statement or two consecutive financial statements,
including reclassification adjustments. The adoption of this statement did not have a material impact on the
Company. The Company has elected to present a separate statement of comprehensive income, including the
individual components, titled Consolidated Statements of Comprehensive Income (Loss), as part of these financial
statements. Additionally, the Company has elected to present the reclassification adjustments under the heading
Comprehensive Income (Loss), above.

On September 30, 2012, the Company elected to early adopt new authoritative accounting guidance issued

by the FASB, which provided that an entity that tests indefinite-lived intangible assets for impairment has the option
to assess qualitative factors to determine whether it is more likely than not that an asset is impaired as a basis for
determining whether a quantitative test is necessary. The adoption of this statement did not have a material impact
on the Company’s financial statements.

There are no new significant accounting standards applicable to the Company that have been issued but not

yet adopted by the Company as of December 31, 2012.

104

Note 2 – Accounts Receivable and Accounts Payable and Accrued Expenses

Accounts receivable are comprised of the following:

As of December 31,

2012

2011

(in thousands)

Accrued oil, gas, and NGL production revenue
Amounts due from joint interest owners
Receivable due from Mitsui
State severance tax refunds
Other
Total accounts receivable

160,568
42,740
19,931
17,237
14,329
254,805

149,384
30,784
—
14,979
15,221
210,368

Accounts payable and accrued expenses are comprised of the following:

As of December 31,

2012

2011

(in thousands)

Accrued drilling costs
Revenue and severance tax payable
Accrued lease operating expense
Accrued property taxes
Joint owner advances
Accrued compensation
Accrued interest
Other
Total accounts payable and accrued expenses

243,611
65,494
28,037
9,478
69,639
35,607
25,027
48,734
525,627

189,749
61,613
25,197
6,994
79,138
43,056
14,646
36,606
456,999

Note 3 – Divestitures and Assets Held for Sale

During 2012, the Company divested of various non-strategic properties located in its Rocky Mountain and
Mid-Continent regions for a total of $57.4 million in total divestiture proceeds, before marketing costs, Net Profits
Plan payments, and legal fees (referred throughout this report as “divestiture proceeds”). The estimated net gain on
these divestitures is $6.9 million. The final sales prices related to these divestitures are subject to normal post-
closing adjustments and are expected to be finalized during the first half of 2013. See discussion below regarding
the loss on unsuccessful sale of properties, which is included in gain (loss) on divestiture activity in the
accompanying statements of operations.

2011 Divestiture Activity

• Eagle Ford Shale Divestiture. In August 2011, the Company divested of certain operated Eagle Ford shale
assets located in its South Texas & Gulf Coast region. This divestiture was comprised of the Company’s
entire operated acreage in LaSalle County, Texas, as well as an immaterial adjacent block of its operated
acreage in Dimmit County, Texas. Total divestiture proceeds were $230.7 million. The final gain on this
divestiture was $193.8 million. Please refer to Note 12 - Acquisition and Development Agreement and
Carry and Earning Agreement for information on additional Eagle Ford activity in 2011.

• Mid-Continent Divestiture. In June 2011, the Company divested of certain non-strategic assets located in its
Mid-Continent region. Total divestiture proceeds were $35.8 million. The final gain on this divestiture was
$28.5 million.

105

• Rocky Mountain Divestiture. In January 2011, the Company divested of certain non-strategic assets located

in its Rocky Mountain region. Total divestiture proceeds were $45.5 million. The final gain on this
divestiture was $27.2 million.

2010 Divestiture Activity

• Permian Divestiture. In December 2010, the Company completed the divestiture of certain non-strategic
assets located in its Permian region. Total divestiture proceeds were $54.7 million. The final gain on this
divestiture was $18.4 million.

•

Sequel Divestiture. In March 2010, the Company completed the divestiture of certain non-strategic assets
located in its Rocky Mountain region. Total divestiture proceeds were $129.1 million. The final gain on
this divestiture was $53.1 million. A portion of the transaction was structured to qualify as a like-kind
exchange under Section 1031 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue
Code”).

• Legacy Divestiture. In February 2010, the Company completed the divestiture of certain non-strategic

assets located in its Rocky Mountain region. Total divestiture proceeds were $125.3 million. The final gain
on this divestiture was $66.7 million. A portion of the transaction was structured to qualify as a like-kind
exchange under Section 1031 of the Internal Revenue Code.

Assets Held for Sale

Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is

reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets
are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any
excess of carrying value over fair value less costs to sell. Subsequent changes to the estimated fair value less the
cost to sell will impact the measurement of assets held for sale for which fair value less costs to sell is determined to
be less than the carrying value of the assets.

As of December 31, 2012, the accompanying balance sheets present $33.6 million of assets held for sale,

net of accumulated depletion, depreciation, and amortization expense. A corresponding asset retirement obligation
liability of $1.4 million is separately presented. The assets held for sale include the Company’s Marcellus shale
assets located in Pennsylvania and certain assets located in the Company’s Rocky Mountain region, all of which are
recorded at the lesser of their carrying values or their respective fair value less estimated costs to sell. Write-downs
to fair value less estimated costs to sell are reflected in the gain (loss) on divestiture activity line item in the
accompanying statements of operations.

During 2012, the Company reclassified a portion of the assets previously held for sale to assets held and

used, as the assets were no longer being actively marketed. The assets were measured at the lower of the carrying
value of the assets before being classified as held for sale, adjusted for any DD&A that would have been recognized
had the assets been continuously held and used, or the fair value of the assets at the date they no longer met the
criteria as held for sale. As a result of this measurement, the Company recognized $1.7 million of DD&A expense
and a $33.9 million loss on unsuccessful sale of properties, which is included in gain (loss) on divestiture activity in
the accompanying statements of operations.

Subsequent to December 31, 2012, the Company divested of a portion of its properties located in its Rocky
Mountain region that were classified as held for sale at year end. Total divestiture proceeds were $9.2 million. The
estimated gain on this divestiture is $2.5 million and is expected to be finalized during the first half of 2013.

The Company determined that neither these planned nor executed asset sales qualify for discontinued

operations accounting under financial statement presentation authoritative guidance.

106

Note 4 – Income Taxes

The provision for income taxes consists of the following:

2012

For the Years Ended December 31,
2011
(in thousands)

2010

Current portion of income tax benefit (expense)

Federal
State

Deferred portion of income tax benefit (expense)
Total income tax benefit (expense)
Effective tax rate

—
(370)
29,638
29,268

35.0%

1,757
(1,553)
(123,789)
(123,585)
36.5%

(2,903)
(639)
(114,517)
(118,059)

37.5%

The Company reduces its income tax payable to reflect employee stock option exercises. In 2010, the

excess income tax benefit to the Company associated with stock awards was $854,000. There was no excess
income tax benefit associated with stock awards in 2012 or 2011.

The components of the net deferred income tax liabilities are as follows:

Deferred tax liabilities:

Oil and gas properties
Unrealized derivative asset
Other

Total deferred tax liabilities
Deferred tax assets:

Federal and state tax net operating loss carryovers
Net Profits Plan liability
Stock compensation
Pension liability
Federal and state tax credit carryovers
Other long-term liabilities

Total deferred tax assets
Valuation allowance
Net deferred tax assets
Total net deferred tax liabilities

Less: current deferred income tax liabilities
Add: current deferred income tax assets

Non-current net deferred tax liabilities
Current federal income tax refundable
Current state income tax refundable
Current state income tax payable

As of December 31,

2012

2011

(in thousands)

$
$
$
$

678,624
15,942
6,443
701,009

113,522
29,233
18,026
6,849
5,271
4,619
177,520
(5,315)
172,205
528,804
(5,442)
14,021
$
537,383
$
2,511
853
$
— $

639,485
13,274
4,129
656,888

23,651
40,148
17,728
5,902
4,301
4,908
96,638
(3,791)
92,847
564,041
(3,307)
7,529
568,263
5,581
—
774

At December 31, 2012, the Company estimated its federal net operating loss carryforward at $376.6

million, which includes unrecognized excess income tax benefits associated with stock awards of $93.4 million.
The federal net operating loss carryforward begins to expire in 2031. The Company has estimated state net

107

operating loss carryforwards of $361.2 million that expire between 2013 and 2032. The Company has claimed
federal research and development (“R&D”) credit carryforwards of $5.0 million that expire between 2028 and 2031
and other state tax credits of $252,000 that expire between 2013 and 2022. The Company’s valuation allowance
relates to charitable contribution carryfowards, state net operating loss carryforwards, state tax credits, and state and
federal income tax benefit amounts, which the Company anticipates will expire before they can be utilized.
Permanent items included in the calculation of income tax for certain states are anticipated to impact the Company’s
ability to deduct operating losses and realize federal income tax deduction benefits in those states, and the Company
adjusts its valuation allowances accordingly. The change in the valuation allowance from 2011 to 2012, indicated
below, primarily reflects a change in the Company’s position regarding anticipated utilization of charitable
contribution carryforward amounts and cumulative net operating losses attributed to Oklahoma.

Federal income tax expense differs from the amount that would be provided by applying the statutory
United States federal income tax rate to income before income taxes primarily due to the effect of state income
taxes, R&D credits, percentage depletion, changes in valuation allowances, and other permanent differences, as
follows:

Federal statutory tax benefit (expense)
(Increase) decrease in tax resulting from:

State tax benefit (expense) (net of federal
benefit)
Research and development credit
Change in valuation allowance
Statutory depletion
Other

Income tax benefit (expense)

2012

For the Years Ended December 31,
2011
(in thousands)
(118,652)
$

29,231

2010

(110,214)

992
970
(1,524)
210
(611)
29,268

(6,458)
4,516
(1,627)
341
(1,705)
(123,585)

(7,750)
—
1,039
266
(1,400)
(118,059)

Acquisitions, divestitures, drilling activity, and basis differentials impacting the prices received for oil, gas,
and NGLs affect apportionment of taxable income to the states where the Company owns oil and gas properties. As
its apportionment factors change, the Company’s blended state income tax rate changes. This change, when applied
to the Company’s total temporary differences, impacts the total income tax reported in the current year and is
reflected in state taxes in the table above. Items affecting state apportionment factors are evaluated at the beginning
of each year, after completion of the prior year income tax return, and when significant acquisition, divestiture or
changes in drilling activity occurs during the year.

The Company and its subsidiaries file income tax returns in the United States federal jurisdiction and in

various states. With certain exceptions, the Company is no longer subject to United States federal or state income
tax examinations by these tax authorities for years before 2008. In the third quarter of 2011, the Company
completed a multi-year R&D credit study and filed amended federal returns to claim a credit for all open years.
Federal tax law allowing for the calculation of an R&D credit for 2012 was not enacted until after December 31,
therefore, no 2012 research activities are reflected in the table above.

In the first quarter of 2011, the Company received a $5.5 million refund from its 2006 tax year as a result of

a net operating loss carryback claim from the 2008 tax year. In the fourth quarter of 2010, the Internal Revenue
Service initiated an audit of the Company for the 2009 tax year. The audit was concluded in the second quarter of
2011 with a nominal decrease to the Company’s total 2005 refund claim of $25.0 million. A quick refund claim of
$22.9 million from 2005 was received in the third quarter of 2010. The balance was received in the fourth quarter
of 2011. The Internal Revenue Service initiated an audit in the first quarter of 2012 for the 2007 and 2010 tax years.
This audit was still ongoing at year-end.

108

The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The

entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized.
Interest expense in the accompanying statements of operations includes a negligible amount associated with income
taxes. In 2011, the Company also recorded a negligible amount of penalty expense associated with income taxes as
a general and administrative expense. There were no penalties for 2012 and 2010.

The total amount recorded for unrecognized tax benefits is presented below:

For the Years Ended December 31,

2012

2011

2010

(in thousands)

Beginning balance
Additions based on tax positions related to current year
Additions for tax positions of prior years
Reductions for lapse of statute of limitations
Ending balance

1,961
—
317
—
2,278

807
1,172
183
(201)
1,961

884
—
244
(321)
807

Note 5 – Long-term Debt

Revolving Credit Facility

The Company executed a Fourth Amended and Restated Credit Agreement on May 27, 2011. This
amended revolving credit facility replaced the Company’s previous facility. The Company incurred $8.7 million of
deferred financing costs in association with the amended credit facility. Borrowings under the facility are secured
by substantially all of the Company’s proved oil and gas properties. The credit facility has a maximum loan amount
of $2.5 billion, current aggregate lender commitments of $1.0 billion, and a maturity date of May 27, 2016. The
borrowing base is subject to regular semi-annual redeterminations by the Company’s lenders. The borrowing base
redetermination process considers the value of the Company’s oil and gas properties. On August 31, 2012, the
lending group redetermined the Company's reserve-backed borrowing base under the credit facility at an amount of
$1.55 billion, an increase from $1.4 billion. The next scheduled re-determination date is April 1, 2013.

The Company must comply with certain financial and non-financial covenants under the terms of its credit

facility agreement, including the limitation of the Company’s dividends to no more than $50.0 million per
year. The Company was in compliance with all financial covenants under the credit facility as of December 31,
2012, and through the filing date of this report.

Interest and commitment fees are accrued based on the borrowing base utilization grid below. Eurodollar

loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table
below, and Alternate Base Rate (“ABR”) and swingline loans accrue interest at Prime plus the applicable margin
from the utilization table below. Commitment fees are accrued on the unused portion of the aggregate commitment
amount and are included in interest expense in the accompanying statements of operations.

Borrowing Base Utilization Grid

Borrowing Base Utilization Percentage
Eurodollar Loans
ABR Loans or Swingline Loans
Commitment Fee Rate

<25%

1.500%
0.500%
0.375%

1.750%
0.750%
0.375%

2.000%
1.000%
0.500%

2.250%
1.250%
0.500%

2.500%
1.500%
0.500%

109

As of February 14, 2013 As of December 31, 2012 As of December 31, 2011
(in millions)

$
Credit facility balance
Letters of credit (1)
$
Available borrowing capacity $
(1) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.

407.5 $
0.8 $
591.7 $

340.0 $
0.8 $
659.2 $

—
0.6
999.4

3.50% Senior Convertible Notes Due 2027

On April 2, 2012, the Company called for redemption all of its outstanding 3.50% Senior Convertible Notes

due 2027 (the “3.50% Senior Convertible Notes”). The call for redemption resulted in holders of $281.3 million
aggregate principal amount electing to convert their notes. The Company settled the principal amount of all
converted 3.50% Senior Convertible Notes in cash and settled the excess conversion value by issuing 864,106
shares of its common stock. The Company redeemed the remaining $6.2 million of aggregate principal amount of
notes that were not converted on the redemption date at par plus accrued interest in cash. The Company used funds
borrowed under its credit facility to pay the cash portion of the settlement.

2023 Notes

On June 29, 2012, the Company issued $400.0 million in aggregate principal amount of 6.50% Senior

Notes due 2023. The 2023 Notes were issued at par and mature on January 1, 2023. The Company received net
proceeds of $392.1 million after deducting fees of $7.9 million, which are being amortized as deferred financing
costs over the life of the 2023 Notes. The net proceeds were used to reduce the Company’s outstanding credit
facility balance.

Prior to July 1, 2015, the Company may redeem, on one or more occasions, up to 35 percent of the
aggregate principal amount of the 2023 Notes with the net cash proceeds of certain equity offerings at a redemption
price of 106.5% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem
the 2023 Notes, in whole or in part, at any time prior to July 1, 2017, at a redemption price equal to 100 percent of
the principal amount of the 2023 Notes to be redeemed, plus a specified make-whole premium and accrued and
unpaid interest to the applicable redemption date.

On or after July 1, 2017, the Company may also redeem all or, from time to time, a portion of the 2023

Notes at the redemption prices set forth below, during the twelve-month period beginning on July 1 of each
applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest:

2017
2018
2019
2020 and thereafter

103.250%
102.167%
101.083%
100.000%

The 2023 Notes are unsecured senior obligations and rank equal in right of payment with all of the
Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future
subordinated debt. There are no subsidiary guarantors of the 2023 Notes. The Company is subject to certain
covenants under the indenture governing the 2023 Notes that limit the Company’s ability to incur additional
indebtedness, issue preferred stock, and make restricted payments, including dividends. However, the first $6.5
million of dividends paid each year are not restricted by this covenant. The Company was in compliance with all
covenants under its 2023 Notes as of December 31, 2012, and through the filing date of this report.

110

Additionally, on June 29, 2012, the Company entered into a registration rights agreement that provides

holders of the 2023 Notes certain registration rights under the Securities Act of 1933, as amended (the “Securities
Act”). The Company satisfied its obligations to exchange its outstanding $400.0 million 2023 Notes for notes
registered under the Securities Act on October 30, 2012.

2021 Notes

On November 8, 2011, the Company issued $350.0 million in aggregate principal amount of 6.50% Senior

Notes due 2021. The 2021 Notes were issued at par and mature on November 15, 2021. The Company received
net proceeds of $343.1 million after deducting fees of $6.9 million, which are being amortized as deferred financing
costs over the life of the 2021 Notes. The net proceeds were used for general corporate purposes and to reduce the
Company’s outstanding credit facility balance.

Prior to November 15, 2014, the Company may redeem up to 35 percent of the aggregate principal amount
of the 2021 Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.5% of the
principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2021 Notes, in
whole or in part, at any time prior to November 15, 2016, at a redemption price equal to 100% of the principal
amount, plus a specified make-whole premium and accrued and unpaid interest.

The Company may also redeem all or, from time to time, a portion of the 2021 Notes on or after

November 15, 2016, at the prices set forth below, during the twelve-month period beginning on November 15 of the
applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest:

2016
2017
2018
2019 and thereafter

103.250%
102.167%
101.083%
100.000%

The 2021 Notes are unsecured senior obligations and rank equal in right of payment with all of the

Company’s existing and any future unsecured senior debt and are senior in right of payment to any future
subordinated debt. There are no subsidiary guarantors of the 2021 Notes. The Company is subject to certain
covenants under the indenture governing the 2021 Notes that limit incurring additional indebtedness, issuing
preferred stock, and making restricted payments, including dividends. The first $6.5 million of dividends paid each
year are not restricted by this covenant. The Company was in compliance with all covenants under its 2021 Notes
as of December 31, 2012 and through the filing date of this report.

Additionally, on November 8, 2011, the Company entered into a registration rights agreement that provides

holders of the 2021 Notes certain registration rights for the 2021 Notes under the Securities Act. The Company
satisfied its obligations to exchange its outstanding $350.0 million of its 2021 Notes for notes registered under the
Securities Act on March 7, 2012.

2019 Notes

On February 7, 2011, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior
Notes due 2019. The 2019 Notes were issued at par and mature on February 15, 2019. The Company received net
proceeds of $341.1 million after deducting fees of $8.9 million, which are being amortized as deferred financing
costs over the life of the 2019 Notes. The net proceeds were used to repay borrowings under the Company’s
previous credit facility, to fund the Company’s ongoing capital expenditure program, and for general corporate
purposes.

111

Prior to February 15, 2014, the Company may redeem up to 35 percent of the aggregate principal amount of
the 2019 Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of the
principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2019 Notes, in
whole or in part, at any time prior to February 15, 2015, at a redemption price equal to 100% of the principal
amount, plus a specified make-whole premium and accrued and unpaid interest.

The Company may also redeem all or, from time to time, a portion of the 2019 Notes on or after
February 15, 2015, at the prices set forth below, during the twelve-month period beginning on February 15 of the
applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest:

2015
2016
2017 and thereafter

103.313%
101.656%
100.000%

The 2019 Notes are unsecured senior obligations and rank equal in right of payment with all of the

Company’s existing and any future unsecured senior debt and are senior in right of payment to any future
subordinated debt. There are no subsidiary guarantors of the 2019 Notes. The Company is subject to certain
covenants under the indenture governing the 2019 Notes that limit incurring additional indebtedness, issuing
preferred stock, and making restricted payments, including dividends. The first $6.5 million of dividends paid each
year are not restricted by this covenant. The Company was in compliance with all covenants under its 2019 Notes
as of December 31, 2012 and through the filing date of this report.

Additionally, on February 7, 2011, the Company entered into a registration rights agreement that provides

holders of the 2019 Notes certain registration rights for the 2019 Notes under the Securities Act. The Company
satisfied its obligations to exchange its outstanding $350.0 million of its 2019 Notes for notes registered under the
Securities Act on January 11, 2012.

Capitalized Interest

Capitalized interest costs for the Company for the years ended December 31, 2012, 2011, and 2010, were

$12.1 million, $10.8 million, and $4.3 million, respectively.

Note 6 – Commitments and Contingencies

Commitments

The Company has entered into various agreements, which include drilling rig contracts of $91.4 million,

gathering, transportation, and processing through-put commitments of $858.7 million, office leases, including
maintenance, of $55.3 million, and other miscellaneous contracts and leases of $7.2 million. The annual minimum
payments for the next five years and total minimum lease payments thereafter are presented below:

Years Ending December 31,

(in thousands)

2013
2014
2015
2016
2017
Thereafter
Total

127,753
111,674
99,854
102,540
101,456
469,348
1,012,625

112

The Company has gathering, processing, and transportation through-put commitments with various parties

that require delivery of a fixed determinable quantity of product. The aggregate minimum commitment to deliver is
1,515 Bcf of natural gas and 36 MMBbls of oil. These contracts expire at various dates through 2023, and the total
amount of the commitment is approximately $858.7 million. The Company will be required to make periodic
deficiency payments for any shortfalls in delivering the minimum volume commitments. As of the filing date of
this report, the Company does not expect to incur any material shortfalls.

The Company leases office space under various operating leases with terms extending as far as May 31,

2024. Rent expense for 2012, 2011, and 2010 was $5.4 million, $3.7 million, and $2.7 million, respectively. The
Company also leases office equipment under various operating leases.

In addition to the amounts in the above table, the Company entered into a capital project commencing in

2011 for the development of midstream infrastructure in the Company’s non-operated Eagle Ford shale play.
Pursuant to the terms of the agreement for the construction, ownership and operation of these assets, the Company
is required to pay its portion of the costs for the next two years. Based on current estimates, the Company does not
expect its costs to exceed $67 million during this time.

Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company

accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion
of management, the results of such pending litigation and claims will not have a material effect on the results of
operations, the financial position, or the cash flows of the Company.

The Company was a defendant in litigation wherein the plaintiffs claimed an aggregate overriding royalty
interest of 7.46875 percent in production from approximately 22,000 of the Company’s net acres in the Eagle Ford
shale play in South Texas. The plaintiffs sought to quiet title to their claimed overriding royalty interest and to recover
unpaid overriding royalty interest proceeds allegedly due. The Company believes that the claimed overriding royalty
interest has been terminated under the governing agreements and the applicable law, and has contested the plaintiffs’
claims. Both parties filed motions for summary judgment, and on February 8, 2011, the District Court in Webb County,
Texas, issued an order granting plaintiffs’ motion for summary judgment and denying the Company’s motion for
summary judgment. On September 30, 2011, the District Court entered final judgment for the plaintiffs and awarded
then current damages of approximately $5.1 million, which included prejudgment interest. The District Court also
awarded attorneys’ fees and costs to the plaintiffs. The Company appealed the District Court’s judgment and obtained
a stay pending appeal that prevented the plaintiffs from executing on the judgment.

On May 23, 2012, the Fourth Court of Appeals for the State of Texas delivered its opinion in this case,

which reversed the summary judgment granted to the plaintiffs by the District Court and rendered judgment that the
plaintiffs take nothing. Accordingly, based on the judgment of the Fourth Court of Appeals, the plaintiffs are not
entitled to their claimed aggregate 7.46875 percent overriding royalty interest, nor are they entitled to the claimed
damages related to the overriding royalty interest, attorneys fees or costs. The plaintiffs filed a petition with the
Supreme Court of Texas requesting a review of the Fourth Court of Appeals judgment. The Supreme Court of
Texas denied this petition for review on February 15, 2013. As a result, the decision of the Fourth Court of Appeals
is dispositive and its dismissal of the plaintiffs’ claims is final.

113

On January 27, 2011, Chieftain filed a Class Action Petition against the Company in the District Court of

Beaver County, Oklahoma, claiming damages related to royalty valuation on all of the Company's Oklahoma wells.
These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of
contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. The
Company removed this lawsuit to the United States District Court for the Western District of Oklahoma on
February 22, 2011. The Company has responded to the petition and denied the allegations. The court has not yet
ruled on Chieftain's motion to certify the putative class, and has stayed any such ruling until the United States Court
of Appeals for the Tenth Circuit issues its ruling on class certification in two similar royalty class action lawsuits,
where the defendants have appealed such certification. The opinion from the Tenth Circuit is expected during the
summer of 2013.

This case involves complex legal issues and uncertainties; a potentially large class of plaintiffs, and a large

number of related producing properties, lease agreements and wells; and an alleged class period commencing in
1988 and spanning the entire producing life of the wells. Because the proceedings are in the early stages, with
substantive discovery yet to be conducted, the Company is unable to estimate what impact, if any, the action will
have on its financial condition, results of operations or cash flows. The Company is still evaluating the claims, but
believes that it has properly valued and paid royalty under Oklahoma law and has and will continue to vigorously
defend this case.

Note 7 – Compensation Plans

Cash Bonus Plan

The Company has a cash bonus plan based on a performance measurement framework whereby selected

eligible employee participants may be awarded an annual cash bonus. The plan document provides that no
participant may receive an annual bonus under the plan of more than 200 percent of his or her base salary. As the
plan is currently administered, any awards under the plan are based on Company and regional performance and are
then further refined by individual performance. The Company accrues cash bonus expense based upon the
Company’s current year performance. Included in general and administrative and exploration expense in the
accompanying statements of operations are $16.3 million, $23.9 million, and $21.6 million of cash bonus expense
related to the specific performance years ended December 31, 2012, 2011, and 2010, respectively.

Equity Plan

There are several components to the Company's Equity Plan that are described in this section. Various

types of equity awards have been granted by the Company in different periods.

As of December 31, 2012, 1.4 million shares of common stock remained available for grant under the

Equity Plan. The issuance of a direct share benefit such as a share of common stock, a restricted share, a RSU, or a
PSU counts as 1.43 shares against the number of shares available to be granted under the Equity Plan. Each PSU
has the potential to count as 2.86 shares against the number of shares available to be granted under the Equity Plan
based on the final performance multiplier. Stock option grants count as one share for each instrument granted
against the number of shares available to be granted under the Equity Plan. Stock options were issued out of the St.
Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive
Stock Option Plan, both predecessors to the Equity Plan.

114

Performance Share Units Under the Equity Incentive Compensation Plan

The Company grants PSUs to eligible employees as a part of its equity incentive compensation program.
The PSU factor is based on the Company’s performance after completion of a three-year performance period. The
performance criteria for the PSUs are based on a combination of the Company’s annualized Total Shareholder
Return (“TSR”) for the performance period and the relative measure of the Company’s TSR compared with the
annualized TSR of an index comprised of certain peer companies for the performance period. PSUs are recognized
as general and administrative and exploration expense over the vesting period of the award.

The fair value of PSUs was measured at the grant date with a stochastic process method using the
Geometric Brownian Motion Model (“GBM Model”). A stochastic process is a mathematically defined equation
that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by
iterating the equations multiple times, different results will be obtained for those iterations. In the case of the
Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers
will take over the three-year performance period. By using a stochastic simulation, the Company can create
multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences
regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or
probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an
appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this
simulation include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S.
Treasury yield curve rates with maturities consistent with a three year vesting period, as well as the volatilities and
dividend yields for each of the Company’s peers.

Total expense recorded for PSUs was $18.2 million, $19.7 million, and $17.7 million for the years ended

December 31, 2012, 2011, and 2010, respectively. As of December 31, 2012, there was $19.6 million of total
unrecognized expense related to PSUs, which is being amortized through 2015.

A summary of the status and activity of PSUs is presented in the following table:

2012

For the Years Ended December 31,
2011

2010

Weighted-
Average
Grant-
Date Fair
Value

PSUs

Weighted-
Average
Grant-
Date Fair
Value

PSUs

Non-vested at
beginning of year(1)
Granted(1)
Vested(1)
Forfeited(1)
Non-vested at end of
year(1)
(1) The number of awards assumes a one multiplier. The final number of shares of common stock issued may vary depending on the ending

$
1,069,090
387,651
$
(210,801) $
(135,274) $

1,110,666
266,282
(364,172)
(126,882)

885,894
314,853
(493,679)
(37,760)

$ 39.48
$ 91.45
$ 35.74
$ 33.32

$ 57.52
$ 51.98
$ 44.72
$ 65.35

32.52
52.35
31.18
34.28

1,110,666

$ 57.52

$ 63.91

669,308

885,894

39.48

three-year performance multiplier, which ranges from zero to two.

The fair value of the PSUs granted in 2012, 2011, and 2010 was $16.4 million, $24.3 million, and $20.3
million for the 2012, 2011, and 2010 grants, respectively. The PSUs granted in 2012 will vest 1/3 on each of the
first three anniversary dates of their issuance. PSUs granted prior to 2012 vest 1/7th, 2/7ths, and 4/7ths on the first
three anniversary dates of their issuances.

The total fair value of PSUs that vested during the years ended December 31, 2012, 2011, and 2010 was

$22.1 million, $13.0 million, and $6.6 million, respectively.

115

During the year ended December 31, 2012, the Company settled 609,714 PSUs that were granted in 2009,

and which had earned a two-times multiplier, by issuing a net 812,562 shares of the Company’s common stock in
accordance with the terms of the PSU awards. The Company and the majority of grant participants mutually agreed
to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document
and award agreements. As a result, the remaining 406,866 shares were withheld to satisfy income and payroll tax
withholding obligations that occurred upon delivery of the shares underlying those PSUs for 2012.

During the year ended December 31, 2011, the Company settled PSUs that were granted in 2008, which

earned a 0.8 times multiplier, by issuing a net 206,468 shares of the Company’s common stock in accordance with
the terms of the PSU awards. The Company and the majority of grant participants mutually agreed to net share
settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award
agreements. As a result, 98,955 shares were withheld to satisfy income and payroll tax withholding obligations that
occurred upon delivery of the shares underlying those PSUs for 2011.

Restricted Stock Units Under the Equity Incentive Compensation Plan

The Company grants RSUs to eligible employees as a part of its equity incentive compensation program.

Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of
Directors and are set forth in the award agreements. Each RSU represents a right for one share of the Company’s
common stock to be delivered upon settlement of the award at the end of a specified period. RSUs are recognized
as general and administrative and exploration expense over the vesting period of the award.

The total expense associated with RSUs for the years ended December 31, 2012, 2011, and 2010, was $9.8

million, $5.3 million, and $7.7 million, respectively. As of December 31, 2012, there was $14.4 million of total
unrecognized expense related to unvested RSU awards, which is being amortized through 2015. The Company
records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the
date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the day of
grant.

A summary of the status and activity of non-vested RSUs is presented below:

2012

For the Years Ended December 31,
2011

2010

Non-vested at beginning

of year

Granted
Vested
Forfeited

Non-vested at end of

year

RSUs

308,877
379,332
(166,672)
(25,293)

496,244

$
$
$
$

Weighted-
Average
Grant-
Date
Fair Value

44.33
49.47
32.72
51.06

RSUs

333,359
98,952
(105,820)
(17,614)

Weighted-
Average
Grant-
Date
Fair Value

31.16
72.69
30.61
36.80

$
$
$
$

RSUs

407,123
128,865
(160,398)
(42,231)

Weighted-
Average
Grant-
Date
Fair Value

$
$
$
$

34.67
40.31
46.30
35.43

31.16

51.81

308,877

44.33

333,359

The fair value of RSUs granted in 2012, 2011, and 2010 was $18.8 million, $7.2 million, and $5.2 million,

respectively. The RSUs granted in 2012 will vest 1/3 on each of the first three anniversary dates of the award.
RSUs granted prior to 2012 vest 1/7th, 2/7ths, and 4/7ths on the first three anniversary dates of their issuances.

The total fair value of RSUs that vested during the years ended December 31, 2012, 2011, and 2010, was

$5.4 million, $3.2 million, and $7.4 million, respectively.

116

During the years ended December 31, 2012, 2011, and 2010, the Company settled 166,670, 105,820, and

160,381 RSUs, respectively. The Company and the majority of grant participants mutually agreed to net share
settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award
agreements. As a result, the Company issued net shares of common stock of 116,813, 72,305, and 113,103 for
2012, 2011, and 2010, respectively. The remaining 49,857, 33,515, and 47,278 shares were withheld to satisfy
income and payroll tax withholding obligations that occurred upon the delivery of the shares underlying those
RSUs for 2012, 2011, and 2010, respectively.

Stock Option Grants Under the Equity Incentive Compensation Plan

The Company has previously granted stock options under the St. Mary Land & Exploration Company Stock

Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan. The last issuance of
stock options occurred on December 31, 2004. Stock options to purchase shares of the Company’s common stock
had been granted to eligible employees and members of the Board of Directors. All options granted under the
option plans were granted at exercise prices equal to the respective closing market price of the Company’s
underlying common stock on the grant dates. All stock options granted under the option plans are exercisable for a
period of up to ten years from the date of grant. As of December 31, 2012, there was no unrecognized
compensation expense related to stock option awards.

A summary of activity associated with the Company’s Stock Option Plans during the last three years is

presented in the following table:

For the year ended December 31, 2010

Outstanding, start of year
Exercised
Forfeited
Outstanding, end of year
Vested and exercisable at end of year

For the year ended December 31, 2011

Outstanding, start of year
Exercised
Forfeited
Outstanding, end of year
Vested and exercisable at end of year

For the year ended December 31, 2012

Outstanding, start of year
Exercised
Forfeited
Outstanding, end of year
Vested and exercisable at end of year

Weighted -
Average
Exercise
Price

Aggregate
Intrinsic
Value

13.31
13.77
16.66
13.11
13.11

13.11
12.19
—
13.86
13.86

13.86
12.65
—
14.95
14.95

$ 11,281,865

$ 42,192,057
$ 42,192,057

$ 24,359,240

$ 30,109,110
$ 30,109,110

$ 11,842,575

$
$

9,983,177
9,983,177

1,274,920
(346,377)
(7,778)
920,765
920,765

$
$
$
$
$

920,765
(412,551)

508,214
508,214

508,214
(240,368)

267,846
267,846

$
$
— $
$
$

117

A summary of additional information related to options outstanding as of December 31, 2012, follows:

Options Outstanding and Exercisable

Number
Of Options
Outstanding
and
Exercisable

33,805
28,053
17,142
35,893
104,093
48,860
267,846

Weighted-
Average
Remaining
Contractual
Life
0.25 years
0.75 years
0.81 years
0.50 years
1 year
2 years

Exercise
Price(1)

12.53
12.66
13.39
13.65
14.25
20.87

$
$
$
$
$
$
Total

(1) Exercise price is equal to the weighted average exercise price.

The fair value of options was measured at the date of grant using the Black-Scholes-Merton option-pricing

model.

Cash flows resulting from excess tax benefits are classified as part of cash flows from financing activities.

Excess tax benefits are realized tax benefits from tax deductions for vested RSUs, settled PSUs, and exercised
options in excess of the deferred tax asset attributable to stock compensation costs for such equity awards. The
Company recorded $854,000 of excess tax benefits for the year ended December 31, 2010, as cash inflows from
financing activities. The Company recorded no excess tax benefits for the years ended December 31, 2012, and
December 31, 2011. Cash received from exercises under all share-based payment arrangements for the years ended
December 31, 2012, 2011, and 2010, was $3.0 million, $5.0 million, and $4.8 million, respectively.

Director Shares

In 2012, 2011, and 2010, the Company issued 30,486, 21,568, and 24,258 shares, respectively, of the

Company’s common stock held as treasury shares to its non-employee directors pursuant to the Company’s Equity
Plan. The Company recorded compensation expense related to these issuances of $1.3 million, $1.2 million, and
$781,000 for the years ended December 31, 2012, 2011, and 2010, respectively.

Employee Stock Purchase Plan

Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of

the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without
accruing in excess of $25,000 in fair market value from purchases for each calendar year. The purchase price of the
stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period.
All shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is
intended to qualify under Section 423 of the IRC. The Company has 1.3 million shares available under the ESPP
for issuance as of December 31, 2012. Shares issued under the ESPP totaled 66,485 in 2012, 41,358 in 2011, and
52,948 in 2010. Total proceeds to the Company for the issuance of these shares were $2.8 million in 2012, $2.3
million in 2011, and $1.7 million in 2010, respectively.

The fair value of ESPP shares was measured at the date of grant using the Black-Scholes-Merton option-
pricing model. Expected volatility was calculated based on the Company’s historical daily common stock price,
and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a six month
vesting period.

118

The fair value of ESPP shares issued during the periods reported were estimated using the following

weighted-average assumptions:

Risk free interest rate
Dividend yield
Volatility factor of the expected market

price of the Company’s common stock

Expected life (in years)

For the Years Ended December 31,
2010
2011
2012

0.1%
0.2%

0.2%
0.2%

0.2%
0.3%

47.8%
0.5 years

36.3%
0.5 years

46.3%
0.5 years

The Company expensed $948,000, $682,000, and $550,000 for the years ended December 31, 2012, 2011,

and 2010, respectively, based on the estimated fair value of grants.

401(k) Plan

The Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee

Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute up to 60 percent
of their base salaries up to the contribution limits established under the IRC. The Company matches each
employee’s contribution up to six percent of the employee’s base salary and may make additional contributions at
its discretion. The Company’s matching contributions to the 401(k) Plan were $3.5 million, $2.9 million, and $2.5
million for the years ended December 31, 2012, 2011, and 2010, respectively. No discretionary contributions were
made by the Company to the 401(k) Plan for any of these years.

Net Profits Plan

Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during a year

were designated within a specific pool. Key employees recommended by senior management and designated as
participants by the Compensation Committee of the Company’s Board of Directors and employed by the Company
on the last day of that year became entitled to payments under the Net Profits Plan after the Company has received
net cash flows returning 100 percent of all costs associated with that pool. Thereafter, 10 percent of future net cash
flows generated by the pool are allocated among the participants and distributed at least annually. The portion of
net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has
recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the
10 percent level. In December 2007, the Board of Directors discontinued the creation of new pools under the Net
Profits Plan. As a result, the 2007 pool was the last Net Profits Plan pool established by the Company.

Cash payments made or accrued under the Net Profits Plan that have been recorded as either general and

administrative expense or exploration expense are detailed in the table below:

General and administrative expense
Exploration expense
Total

For the Years Ended December 31,

2012

2011

2010

15,565
1,751
17,316

(in thousands)
19,326
$
2,091
21,417

19,798
2,633
22,431

Additionally, the Company made or accrued cash payments under the Net Profits Plan of $2.3 million, $6.3

million, and $26.1 million for the years ended December 31, 2012, 2011, and 2010, respectively, as a result of
divestiture proceeds. The cash payments are accounted for as a reduction in the gain on divestiture activity in the
accompanying statements of operations.

119

The Company records changes in the present value of estimated future payments under the Net Profits Plan

as a separate line item in the accompanying statements of operations. The change in the estimated liability is
recorded as a non-cash expense or benefit in the current period. The amount recorded as an expense or benefit
associated with the change in the estimated liability is not allocated to general and administrative expense or
exploration expense because it is associated with the future net cash flows from oil and gas properties in the
respective pools rather than results being realized through current period production. If the Company allocated the
change in liability to these specific functional line items, based on the current allocation of actual distributions made
by the Company, such expenses or benefits would predominately be allocated to general and administrative
expense. The amount that would be allocated to exploration expense is minimal in comparison. Over time, less of
the amount distributed relates to prospective exploration efforts as more of the amount distributed is to individuals
that have terminated employment and do not provide ongoing exploration support to the Company.

Note 8 – Pension Benefits

The Company has a non-contributory defined benefit pension plan covering substantially all employees

who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-
contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together
with the Qualified Pension Plan, the “Pension Plans”).

Obligations and Funded Status for Both Pension Plans

The Company recognizes the funded status (i.e., the difference between the fair value of plan assets and the
projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset
or a liability and recognizes a corresponding adjustment to accumulated other comprehensive income, net of tax.
The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants
based on employee service and compensation including the effect of assumed future salary increases. The
accumulated benefit obligation uses the same factors as the projected benefit obligation but excludes the effects of
assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31.

For the Years Ended December 31,

2012

2011

(in thousands)

Change in benefit obligation:
Projected benefit obligation at beginning of year

Service cost
Interest cost
Plan amendments
Actuarial loss
Benefits paid

Projected benefit obligation at end of year

Change in plan assets:
Fair value of plan assets at beginning of year

Actual return on plan assets
Employer contribution
Benefits paid

Fair value of plan assets at end of year
Funded status at end of year

120

29,480
4,934
1,374
—
5,467
(1,018)
40,237

13,940
1,952
5,380
(1,018)
20,254
(19,983)

23,867
3,800
1,184
170
1,957
(1,498)
29,480

10,332
(176)
5,260
(1,476)
13,940
(15,540)

The Company’s underfunded status for the Pension Plans for the years ended December 31, 2012 and 2011,
is $20.0 million and $15.5 million, respectively, and is recognized in the accompanying balance sheets as a portion
of other noncurrent liabilities. No plan assets of the Qualified Pension Plan were returned to the Company during
the fiscal year ended December 31, 2012. There are no plan assets in the Nonqualified Pension Plan. The plan was
amended in 2011 to increase the vesting percent to 40 percent after attaining two years of service and increasing by
20 percent per year until fully vested. The impact of this change in the vesting schedule is reflected in plan
amendments in the table above.

Information for Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets for Both Plans

Projected benefit obligation

Accumulated benefit obligation
Less: Fair value of plan assets
Underfunded accumulated benefit obligation

As of December 31,

2012

2011

(in thousands)

40,237

29,437
(20,254)
9,183

29,480

21,697
(13,940)
7,757

Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits

earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The
expected long-term rate of return on plan assets is applied to a calculated value of plan assets that recognizes
changes in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension
expense, but it can have the effect of delaying recognition of differences between actual returns on assets and
expected returns based on long-term rate of return assumptions. Amortization of unrecognized net gain or loss
resulting from actual experience different from that assumed and from changes in assumptions (excluding asset
gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for
a year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the
projected benefit obligation and the market-related value of plan assets, then the amortization is the excess divided
by the average remaining service period of participating employees expected to receive benefits under the plan.

Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated

other comprehensive loss as of December 31, 2012, and 2011, consist of:

As of December 31,

2012

2011

Unrecognized actuarial losses
Unrecognized prior service costs
Unrecognized transition obligation
Accumulated other comprehensive loss

(in thousands)
12,427
153
—
12,580

8,501
170
—
8,671

The estimated net loss that will be amortized from accumulated other comprehensive income into net

periodic benefit cost over the next fiscal year is $876,000.

121

Pre-tax changes recognized in other comprehensive income (loss) during 2012, 2011, and 2010, were as

follows:

Net actuarial gain (loss)
Prior service cost
Less: Amortization of:
Prior service cost
Actuarial loss

Total other comprehensive income (loss)

2012

For the Years Ended December 31,
2011
(in thousands)

2010

(4,680)
—

(17)
(754)
(3,909)

(3,014)
(170)

—
(405)
(2,779)

(1,937)
—

—
(367)
(1,570)

Components of Net Periodic Benefit Cost for Both Pension Plans

2012

For the Years Ended December 31,
2011
(in thousands)

2010

Components of net periodic benefit cost

Service cost
Interest cost
Expected return on plan assets that
reduces periodic pension cost
Amortization of prior service cost
Amortization of net actuarial loss

Net periodic benefit cost

4,934
1,374

(1,165)
17
754
5,914

3,800
1,184

(880)
—
405
4,509

3,392
1,120

(638)
—
367
4,241

Gains and losses in excess of 10 percent of the greater of the benefit obligation and the market-related value

of assets are amortized over the average remaining service period of active participants.

Pension Plan Assumptions

Weighted-average assumptions to measure the Company’s projected benefit obligation and net periodic

benefit cost are as follows:

Projected benefit obligation

Discount rate
Rate of compensation increase

Net periodic benefit cost

Discount rate
Expected return on plan assets
Rate of compensation increase

2012

3.9%
6.2%

4.7%
7.5%
6.2%

As of December 31,
2011

4.7%
6.2%

5.3%
7.5%
6.2%

2010

5.3%
6.2%

6.1%
7.5%
6.2%

The Company’s pension investment policy includes various guidelines and procedures designed to ensure
that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans.
The policy does not permit the direct investment of plan assets in the Company’s securities. The Qualified Pension
Plan's investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term

122

perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The
key investment principles of diversification, assessment of risk, and targeting the optimal expected returns for given
levels of risk are applied.

The Qualified Pension Plan's investment portfolio contains a diversified blend of investments, which may

reflect varying rates of return. The investments are further diversified within each asset classification. This
portfolio diversification provides protection against a single security or class of securities having a disproportionate
impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a
periodic basis to maintain the target allocations. The weighted-average asset allocation of the Qualified Pension
Plan is as follows:

Asset Category
Equity securities
Debt securities
Other

Total

Target

2013

44.0%
33.0%
23.0%
100.0%

As of December 31,

2012

42.7%
32.8%
24.5%
100.0%

2011

61.8%
37.7%
0.5%
100.0%

There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan. An

expected return on plan assets of 7.5 percent was used to calculate the Company’s obligation under the Qualified
Pension Plan for 2012 and 2011. Factors considered in determining the expected rate of return include the long-
term historical rate of return provided by the equity and debt securities markets and input from the investment
consultants and trustees managing the plan assets. The difference in investment income using the projected rate of
return compared to the actual rates of return for the past two years was not material and will not have a material
effect on the accompanying statements of operations or cash flows from operating activities in future years.

123

Fair Value Assumptions

The fair value of the Company’s Qualified Pension Plan assets as of December 31, 2012, utilizing the fair

value hierarchy discussed in Note 11 – Fair Value Measurements is as follows:

Actual
Asset
Allocation

Fair Value Measurements Using:

Total

Level 1
Inputs

Level 2
Inputs
(in thousands)

Level 3
Inputs

3.8%

778

29.2%
13.5%
42.7%

6.1%
20.8%
5.9%
32.8%

5,920
2,740
8,660

1,240
4,204
1,186
6,630

5,920
2,740
8,660

1,240
4,204
1,186
6,630

—

—
—
—

—
—
—
—

—

—
—
—

—
—
—
—

Cash and Money Market Funds
Equity Securities
Domestic (1)
International (2)
Total Equity Securities

Fixed Income Securities
High-Yield Bonds (3)
Core Fixed Income (4)
Floating Rate Corp Loans (5)
Total Fixed Income Securities

Other Securities:

Commodities (6)
Real Estate (7)
Hedge Fund (8)
Total Other Securities

—
783
1,601
2,384
2,384
Total Investments
(1) Equity securities of United States large and small capitalization companies, which are actively traded securities that can be

3.3%
3.9%
13.5%
20.7%
100.0%

669
783
2,734
4,186
20,254

669
—
1,133
1,802
17,870

—
—
—
—
—

sold upon demand.

(2) International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in

developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging
markets and believed to have strong sustainable financial productivity at attractive valuations.

(3) High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high

current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis.

(4) The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the

investment results of the Barclay's Capital Aggregate Bond Index with a modest amount of variability in duration around
the index.

(5) Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to

account for changes in the level of interest rates.

(6) Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other

commodity-linked securities.

(7) The investment objective of direct real estate is to provide current income with the potential for long-term capital

appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity.

(8) The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative
investments and a hedge fund of funds that invests both long and short using a variety of investment strategies.

Included below is a summary of the changes in Level 3 plan assets (in thousands):

December 31, 2011
Purchases
Investment Returns
December 31, 2012

—
2,329
55
2,384

124

The fair value of the Company’s pension plan assets as of December 31, 2011, is as follows:

Fair Value Measurements Using:

Actual
Asset
Allocation

Total

Level 1
Inputs

Level 2
Inputs
(in thousands)

Level 3
Inputs

Cash and Money Market Funds
Equity Securities (1)
Domestic (2)
International (3)
Total Equity Securities

Fixed Income Securities

Intermediate Term Bond (4)

Total Investments

0.5%

47.1%
14.7%
61.8%

6,568
2,048
8,616

37.7%
100.0%

5,258
13,940

—

—
—
—

—
—

—

—
—
—

—
—

(1) Certain amounts have been reclassified to conform to current-year presentation.
(2) United States equities are invested in companies that trade on active exchanges within the United States and are well

diversified by industry sector and equity style, such as growth and value strategies, and passive management strategies are
employed.

(3) International equities are invested in companies that trade on active exchanges outside the United States and are well

diversified among more developed markets. Active and passive strategies are employed.

(4) Intermediate term bonds seek total return. At least 80% of this fund is invested in a diversified portfolio of bonds, which
include all types of securities. It invests primarily in bonds of corporate and governmental issues located in the United
States and foreign countries, including emerging markets, all of which trade on active exchanges.

Contributions

The Company contributed $5.4 million, $5.3 million, and $1.7 million, to the Pension Plans in the years

ended December 31, 2012, 2011, and 2010, respectively. The Company is required to make a $373,000
contribution to the Pension Plans in 2013.

Benefit Payments

The Pension Plans made actual benefit payments of $1.0 million, $1.5 million, and $1.7 million in the years

ended December 31, 2012, 2011, and 2010, respectively. Expected benefit payments over the next ten years are as
follows (in thousands):

Years Ending December 31,
2013
2014
2015
2016
2017
2018 through 2022

$
$
$
$
$
$

2,631
2,385
2,715
3,298
3,885
29,884

125

Note 9 – Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil

and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the
carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase
in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company
depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the
accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas
properties. Cash paid to settle asset retirement obligations is included in the operating section of the Company’s
accompanying statements of cash flows.

The Company’s estimated asset retirement obligation liability is based on historical experience in
abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal
and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the
time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s
abandonment liabilities range from 5.5 percent to 12 percent. Revisions to the liability could occur due to changes
in estimated abandonment costs or well economic lives or if federal or state regulators enact new requirements
regarding the abandonment of wells.

A reconciliation of the Company’s asset retirement obligation liability is as follows:

As of December 31,

2012

2011

(in thousands)

Beginning asset retirement obligation

Liabilities incurred
Liabilities settled
Accretion expense
Revision to estimated cash flows

Ending asset retirement obligation

95,906
13,050
(8,101)
4,679
14,984
120,518

82,849
5,465
(8,365)
5,948
10,009
95,906

As of December 31, 2012, and 2011, the Company had $1.4 million and $1.3 million, respectively, of asset
retirement obligation associated with the oil and gas properties held for sale included in a separate line item on the
Company’s accompanying balance sheets. Additionally, as of December 31, 2012, and 2011, accounts payable and
accrued expenses contain $6.2 million and $7.5 million, respectively, related to the Company’s current asset
retirement obligation liability for estimated plugging and abandonment costs associated with platforms that are
being relinquished or retired.

Note 10 – Derivative Financial Instruments

The Company has entered into various commodity derivative contracts to mitigate a portion of the exposure

to potentially adverse market changes in commodity prices and the associated impact on cash flows. The
Company’s derivative contracts in place include swap and collar arrangements for oil, gas, and NGLs. As of
December 31, 2012, the Company has commodity derivative contracts outstanding through the third quarter of 2015
for a total of 10.1 million Bbls of oil production, 80.7 million MMBtu of gas production, and 1.2 million Bbls of
NGL production. As of February 14, 2013, the Company had commodity derivative contracts in place through the
fourth quarter of 2015 for a total of 14.5 million Bbls of oil, 114.8 million MMBtu of gas, and 2.0 million Bbls of
NGLs.

The Company’s commodity derivatives are measured at fair value and are included in the accompanying
balance sheets as derivative assets and liabilities. The fair value of the commodity derivative contracts was a net
asset of $38.7 million and $31.2 million at December 31, 2012, and 2011, respectively.

126

Discontinuance of Cash Flow Hedge Accounting

Prior to January 1, 2011, the Company designated its commodity derivative contracts as cash flow hedges,
for which unrealized changes in fair value were recorded to AOCIL, to the extent the hedges were effective. As of
January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been
previously designated as cash flow hedges at December 31, 2010. As a result, subsequent to December 31, 2010,
the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in
earnings rather than deferring any such amounts in AOCIL. The Company had no derivatives designated as cash
flow hedges for the years ended December 31, 2012, and 2011, and as such, no ineffectiveness was recognized in
earnings for the respective periods.

As a result of discontinuing hedge accounting on January 1, 2011, such fair values at December 31, 2010,

were frozen in AOCIL as of the de-designation date and are reclassified into earnings as the original derivative
transactions settle. As of December 31, 2012, AOCIL included $1.1 million of net unrealized losses, net of income
tax, on commodity derivative contracts that had been previously designated as cash flow hedges, all of which will
be reclassified to earnings from AOCIL during the next twelve months. Please refer to Note 11 – Fair Value
Measurements for more information regarding the Company’s derivative instruments.

The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by

category:

As of December 31, 2012

Derivative Assets

Derivative Liabilities

Balance Sheet
Classification

Fair Value

Balance Sheet
Classification

Commodity Contracts
Commodity Contracts
Derivatives not designated as hedging
instruments

Current assets
Noncurrent assets

(in thousands)

37,873 Current liabilities
16,466 Noncurrent liabilities

54,339

Fair Value

8,999
6,645

15,644

As of December 31, 2011

Derivative Assets

Derivative Liabilities

Balance Sheet
Classification

Fair Value

Balance Sheet
Classification

Commodity Contracts
Commodity Contracts
Derivatives not designated as hedging
instruments

Current assets
Noncurrent assets

(in thousands)

55,813 Current liabilities
31,062 Noncurrent liabilities

86,875

Fair Value

42,806
12,875

55,681

127

The following table summarizes the components of unrealized and realized derivative (gain) loss presented

in the accompanying statements of operations:

Cash settlement (gain) loss:

Oil contracts
Gas contracts
NGL contracts

Total cash settlement (gain) loss

Unrealized (gain) loss on change in fair value:

Oil contracts
Gas contracts
NGL contracts

Total net unrealized (gain) on change in fair value
Total unrealized and realized derivative (gain)

For the Years Ended December 31,

2012

2011

(in thousands)

11,893
(47,270)
(8,887)
(44,264)

(31,981)
31,777
(11,162)
(11,366)
(55,630)

22,633
(10,711)
13,749
25,671

(3,391)
(64,310)
4,944
(62,757)
(37,086)

The following table details the effect of derivative instruments on AOCIL and the accompanying statements

of operations (net of income tax):

Location on
Accompanying
Statements of
Operations

Derivatives

For the Years Ended
December 31,
2011
(in thousands)

2010

2012

Amount reclassified from AOCIL

Commodity
Contracts

Realized hedge
gain (loss)

$ (2,264) $ 12,997

$ 6,641

The realized net hedge gain for the year ended December 31, 2012, and net hedge loss for December 31,

2011, are comprised of realized cash settlements on commodity derivative contracts that were previously designated
as cash flow hedges, whereas the realized net hedge gain for the year ended December 31, 2010, is comprised of
realized cash settlements on all commodity derivative contracts. Realized hedge gains or losses from the settlement
of commodity derivatives previously designated as cash flow hedges are reported in the total operating revenues
and other income section of the accompanying statements of operations. The Company realized a pre-tax net gain
of $3.9 million, a net loss of $20.7 million, and a net gain of $23.5 million from its commodity derivative contracts
for the years ended December 31, 2012, 2011, and 2010, respectively.

As noted above, effective January 1, 2011, the Company elected to de-designate all of its commodity

derivative contracts that had been previously designated as cash flow hedges. No new gains or losses are deferred
in AOCIL at December 31, 2012, and 2011, respectively.

128

The Company had no derivatives designated as cash flow hedges at December 31, 2012, and 2011,

respectively. The following table details the ineffective portion of derivative instruments classified as cash flow
hedges on the accompanying statements of operations for the year ended December 31, 2010.

Derivatives Qualifying as
Cash Flow Hedges

Location on Accompanying
Statements of Operations

Loss Recognized in
Earnings
(Ineffective Portion)

For the Year Ended
December 31, 2010
(in thousands)

Commodity Contracts

Unrealized and realized derivative (gain) loss

8,899

Credit Related Contingent Features

As of December 31, 2012, and through the filing date of this report, all of the Company’s derivative

counterparties were members of the Company’s credit facility syndicate. The Company’s obligations under its
credit facility and derivative contracts are secured by liens on substantially all of the Company’s proved oil and gas
properties.

Convertible Note Derivative Instrument

The contingent interest provision of the 3.50% Senior Convertible Notes was an embedded derivative
instrument. The fair value of this derivative was determined to be immaterial as of December 31, 2011. The 3.50%
Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-term Debt
for additional discussion.

Note 11 – Fair Value Measurements

The Company follows fair value measurement authoritative accounting guidance for all assets and
liabilities measured at fair value. That authoritative accounting guidance defines fair value as the price that would
be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market
participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by
assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for
grouping these assets and liabilities is based on the significance level of the following inputs:

• Level 1 – quoted prices in active markets for identical assets or liabilities

• Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or
similar instruments in markets that are not active, and model-derived valuations whose inputs are
observable or whose significant value drivers are observable

• Level 3 – significant inputs to the valuation model are unobservable

129

The following table is a listing of the Company’s assets and liabilities that are measured at fair value and

where they were classified within the fair value hierarchy as of December 31, 2012:

Assets:

Derivatives (1)
$
Proved oil and gas properties (2)
$
Unproved oil and gas properties (2) $

Liabilities:

Derivatives (1)
Net Profits Plan (1)

$
$

Level 1

Level 2
(in thousands)

Level 3

— $
— $
— $

— $
— $

54,339

$
— $
— $

15,644

$
— $

—
209,959
42,765

—
78,827

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
(2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

The following table is a listing of the Company’s assets and liabilities that are measured at fair value and

where they were classified within the hierarchy as of December 31, 2011:

Level 1

Level 2
(in thousands)

Level 3

Assets:

Derivatives (1)
Proved oil and gas properties (2)
Unproved oil and gas properties (2)

Liabilities:

Derivatives (1)
Net Profits Plan (1)

$
$
$

$
$

— $
— $
— $

— $
— $

86,875

$
— $
— $

55,681

$
— $

—
139,992
15,809

—
107,731

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy

based on the lowest level of input that is significant to the fair value measurement. The following is a description of
the valuation methodologies used by the Company as well as the general classification of such instruments pursuant
to the above fair value hierarchy.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives.

Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into
consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These
valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors
result in an estimated exit-price. Management believes this approach provides a reasonable and consistent
methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not
considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative
markets are highly active.

130

Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal

credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to
determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may
ask counterparties to post collateral if their ratings deteriorate. Currently, one counterparty posts collateral when
requested by the Company. In some instances the Company will attempt to novate the trade to a more stable
counterparty.

Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of

any derivative liability position. This adjustment takes into account any credit enhancements, such as collateral
margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties.
The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit
risk and takes into account the Company’s credit rating, current credit facility margins, and any change in such
margins since the last measurement date. All of the Company’s derivative counterparties are members of the
Company’s credit facility bank syndicate.

The methods described above may result in a fair value estimate that may not be indicative of net realizable
value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation
methods utilized are appropriate and consistent with accounting authoritative guidance and with other marketplace
participants, the Company recognizes that third parties may use different methodologies or assumptions to
determine the fair value of certain financial instruments that could result in a different estimate of fair value at the
reporting date.

Refer to Note 10 - Derivative Financial Instruments for more information regarding the Company’s

derivative instruments.

Net Profits Plan

The Net Profits Plan is a standalone liability for which there is no available market price, principal market,

or market participants. Certain inputs for this instrument are unobservable and are therefore classified as Level 3
inputs. The Company employs the income approach, which converts expected future cash flow amounts to a single
present value amount. This technique uses the estimate of future cash payments, expectations of possible variations
in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value.
There is a direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the
Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and lower
commodity prices result in a smaller Net Profits Plan liability.

The Company records the estimated fair value of the long-term liability for estimated future payments

under the Net Profits Plan based on the discounted value of estimated future payments associated with each
individual pool. The calculation of this liability is a significant management estimate. For those pools currently in
payout, a discount rate of 12 percent is used to calculate this liability. A discount rate of 15 percent is used to
calculate the liability for pools that have not reached payout.

The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions,

discount rates, and the overall market conditions, all of which are continually evaluated to consider the current
market environment. The Net Profits Plan liability is determined using price assumptions of five one-year strip
prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price
differentials and to include the effects of the forecasted production covered by derivatives contracts in the relevant
periods. The non-cash expense associated with this significant management estimate is highly volatile from period
to period due to fluctuations that occur in the crude oil, gas, and NGL commodity markets.

131

If the commodity prices used in the calculation changed by five percent, the liability recorded at
December 31, 2012, would differ by approximately $7 million. A one percent increase in the discount rate would
decrease the liability by approximately $3 million, whereas a one percent decrease in the discount rate would
increase the liability by approximately $4 million. Actual cash payments to be made to participants in future
periods are dependent on realized actual production, realized commodity prices, and actual costs associated with the
properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently
different from the amounts estimated.

No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits
Plan liability. Consequently, the recorded fair value is based entirely on management estimates that are described
within this footnote. While some inputs to the Company’s calculation of fair value of the Net Profits Plan’s future
payments are from published sources, others, such as the discount rate and the expected future cash flows, are
derived from the Company’s own calculations and estimates.

The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value

using Level 3 inputs:

2012

For the Years Ended December 31,
2011
(in thousands)

2010

Beginning balance

Net increase (decrease) in liability (1)
Net settlements (1) (2) (3)
Transfers in (out) of Level 3

107,731 $
(9,251)
(19,653)
—
78,827 $

135,850 $
2,269
(30,388)
—
107,731 $

170,291
14,063
(48,504)
—
135,850

Ending balance
(1) Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the

accompanying statements of operations.

(2) Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash

payments made or accrued under the Net Profits Plan of $2.3 million, $6.3 million, and $26.1 million relating to divestiture
proceeds for the years ended December 31, 2012, 2011, and 2010 respectively.

(3) During 2011, the Company elected to cash out several Net Profits Plan pools with a $2.6 million direct payment. As a
result, the Company reduced its Net Profits Plan liability by that amount. There was no impact on the accompanying
statements of operations for the period ended December 31, 2011, related to these settlements.

Long-term Debt

The following table reflects the fair value of the 3.50% Senior Convertible Notes, 2019 Notes, 2021 Notes,

and 2023 Notes measured at fair value using Level 1 inputs based on quoted secondary market trading prices:

As of December 31,

2012

2011

3.50% Senior Convertible Notes (1) (2) $
$
2019 Notes
$
2021 Notes
2023 Notes (3)
$
(1) The 3.50% Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-term

394,068
359,408
360,283
—

(in thousands)
— $
371,875 $
371,070 $
424,200 $

Debt for additional discussion.

(2) The estimated fair value of the embedded contingent interest derivative was immaterial as of December 31, 2011.
(3) The 2023 Notes were issued on June 29, 2012.

132

There was no long-term debt measured at fair value on the accompanying balance sheets as of

December 31, 2012, or 2011; all long-term debt is presented at historical value.

Proved Oil and Gas Properties

Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an

indication that the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income
valuation technique, which converts future estimated cash flows to a single present value amount, to measure the
fair value of proved properties through an application of discount rates and price forecasts selected by the
Company’s management. The calculation of the discount rate is based on the best information available and was
estimated to be 12 percent as of December 31, 2012, and 2011. Management believes that the discount rate is
representative of current market conditions and takes into account estimates of future cash payments, expectations
of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The
prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five
years. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the
market is actively trading, after which a flat terminal price is used for each commodity stream. Future operating
costs are also adjusted as deemed appropriate for these estimates.

As a result of asset write-downs, the proved oil and gas properties measured at fair value within the
accompanying balance sheets totaled $210.0 million and $140.0 million as of December 31, 2012 and 2011,
respectively.

Unproved Oil and Gas Properties

Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an

indication that the carrying costs may not be recoverable. The Company uses a market approach, which takes into
account the following significant assumptions: future development plans, risk weighted potential resource recovery,
and estimated reserve values to measure the fair value of unproved properties.

As a result of the asset write-downs, unproved oil and gas properties measured at fair value within the

accompanying balance sheets totaled $42.8 million as of December 31, 2012, and $15.8 million at December 31,
2011.

Materials Inventory

Materials inventory is valued at the lower of cost or market. The Company uses Level 2 inputs to measure
the fair value of materials inventory, which is primarily comprised of tubular goods. The Company uses third party
market quotes and compares the quotes to the book value of the materials inventory. If the book value exceeds the
quoted market price, the Company reduces the book value to the market price. The considered factors result in an
estimated exit-price. Management believes this approach provides a reasonable and consistent methodology for
valuing materials inventory. There were no materials inventory measured at fair value within the accompanying
balance sheets at December 31, 2012, and 2011.

Asset Retirement Obligations

The income valuation technique is utilized by the Company to determine the fair value of the asset
retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, the time value of
money, and the current economic state to the undiscounted expected abandonment cash flows. Given the
unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to
use Level 3 inputs. There were no asset retirement obligations measured at fair value within the accompanying
balance sheets at December 31, 2012 and 2011.

133

Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement

Acquisition and Development Agreement

In June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui (the

“Acquisition and Development Agreement”). Pursuant to the Acquisition and Development Agreement, the
Company agreed to transfer to Mitsui a 12.5 percent working interest in certain non-operated oil and gas assets
representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As
consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percent of certain drilling
and completion costs attributable to the Company’s remaining interest in these assets until Mitsui has expended an
aggregate $680.0 million on behalf of the Company. Based on the Company’s forecast of the operator’s drilling
plans, it will take approximately two more years to fully utilize the carry. The Acquisition and Development
Agreement also provided for reimbursement of capital expenditures and other costs, net of revenues, paid by the
Company that were attributable to the transferred interest during the period between the effective date and the
closing date, which the parties agreed would be applied over the carry period to cover the Company’s remaining 10
percent of drilling and completion costs for the affected acreage.

As of December 31, 2012, the Company held $86.8 million in cash that is contractually restricted for use in

the development of assets covered by our Acquisition and Development Agreement with Mitsui. This cash relates
to the reimbursement of net costs for the period between the effective date and closing date, as discussed above, as
well as an estimate of 90 percent of two months of activity of the Company’s proportionate share of estimated
drilling and completion costs. This restricted cash is classified as a non-current asset in the accompanying balance
sheets. The Company has recorded a corresponding liability equal to the restricted cash balance. The portion of the
liability related to development operations expected to occur within the next year is recorded in accounts payable
and accrued expenses within the accompanying balance sheets. The portion of the liability related to development
operations expected to occur more than one year in the future is recorded in other noncurrent liabilities within the
accompanying balance sheets. There was no net impact on the accompanying statements of cash flows as restricted
cash was offset against the corresponding liability in investing activities. There is no direct impact to the
accompanying statements of operations as a result of the Acquisition and Development Agreement, with the
exception of legal and commission costs associated with the execution of the arrangement which were expensed in
2011. Of the original $680.0 million carry amount, $277.5 million had been spent as of December 31, 2012.

Carry and Earning Agreement

On April 29, 2010, the Company entered into a Carry and Earning Agreement that provided for a third party

to earn 95 percent of SM Energy’s interest in approximately 8,400 net acres in a portion of the Company’s east
Texas Haynesville shale acreage, as well as an interest in several wells, and five percent of SM Energy’s interest in
approximately 23,400 net acres in a separate portion of the Company’s Haynesville acreage in East Texas. In
exchange for these interests, the third party invested $91.3 million to fund the drilling and completion costs of wells
in the portion of the leases where the Company retained 95 percent of its interest. The parties now share all costs of
operations within the area of joint ownership in accordance with their respective ownership interests.

134

Note 13 - Suspended Well Costs

The following table reflects the net changes in capitalized exploratory well costs during 2012, 2011, and

2010. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to
producing well costs in the same year:

Beginning balance on January 1,
Additions to capitalized exploratory well costs pending
the determination of proved reserves

Reclassifications to wells, facilities, and equipment based
on the determination of proved reserves
Capitalized exploratory well costs charged to expense
Ending balance at December 31,

2012

For the Years Ended December 31,
2011
(in thousands)
35,862
$

18,600

2010

9,100

15,618

(5,865)
(12,735)
9,100

(32,880)
—
18,600

34,384

35,862

(34,384)
—
35,862

The following table provides an aging of capitalized exploratory well costs based on the date the drilling

was completed and the number of projects for which exploratory well costs have been capitalized for more than one
year since the completion of drilling:

Exploratory well costs capitalized for one year or less
Exploratory well costs capitalized for more than one year
Ending balance at December 31,
Number of projects with exploratory well costs that have

been capitalized more than a year

2012

9,100
—
9,100

—

As of December 31,
2011
(in thousands)
15,618
$
2,982
18,600

2010

35,862
—
35,862

—

In the third quarter of 2012, the Company expensed $3.6 million of costs related to two exploratory wells

that had been disclosed at December 31, 2011, as suspended well costs being capitalized for more than one year.

135

Supplemental Oil and Gas Information (unaudited)

Costs Incurred in Oil and Gas Producing Activities

Costs incurred in oil and gas property acquisition, exploration and development activities, whether

capitalized or expensed, are summarized as follows:

2012

For the Years Ended December 31,
2011
(in thousands)

2010

1,346,216
220,921

1,320,627
177,465

379,636
443,888

Development costs (1)
Exploration costs
Acquisitions

Proved properties
Unproved properties (2)

5,773
114,971
1,687,881

—
55,237
1,553,329

664
53,192
877,380

Total, including asset retirement obligation (3)(4)
(1) Includes facility costs of $62.2 million, $112.4 million, and $80.3 million for the years ended December 31, 2012, 2011,

and 2010, respectively.

(2) Includes $3.4 million of unproved properties acquired for the year ended December 31, 2012. The remaining balance

relates to leasing activity.

(3) Includes capitalized interest of $12.1 million, $10.8 million, and $4.3 million for the years ended December 31, 2012,

2011, and 2010, respectively.

(4) Includes amounts relating to estimated asset retirement obligations of $30.6 million, $19.3 million, and $5.8 million for the

years ended December 31, 2012, 2011, and 2010, respectively.

Oil and Gas Reserve Quantities

The reserve estimates presented below were made in accordance with GAAP requirements for disclosures

about oil and gas producing activities and SEC rules for oil and gas reporting reserve estimation and disclosure.

Proved reserves are the estimated quantities of oil, gas, and NGLs, 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir
is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date
of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month
price for each month within such period, unless prices are defined by contractual arrangements, excluding
escalations based upon future conditions. All of the Company’s estimated proved reserves are located in the United
States.

136

The table below presents a summary of changes in the Company’s estimated proved reserves for each of the

years in the three-year period ended December 31, 2012. The Company engaged Ryder Scott to audit internal
engineering estimates for at least 80 percent of the PV-10 value of its estimated proved reserves in each year
presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new
discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas
properties. Accordingly, these estimates are expected to change as future information becomes available.

2012 (1)

For the Years Ended December 31,
2011 (2)

2010 (3)

Oil
(MMBbl)

Gas
(Bcf)

NGLs
(MMBbl)

Oil
(MMBbl)

Gas
(Bcf)

NGLs
(MMBbl)

Oil
(MMBbl)

Gas
(Bcf)

NGLs
(MMBbl)

71.7

664.0

27.5

57.4

640.0

(4.5)

(123.3)

(2.4)

(0.9)

(76.7)

17.1

297.4

30.6

26.9

223.5

—

15.6

17.8

53.8

449.5

3.1

6.1

16.2

172.9

19.2

125.1

12.7

2.8

14.8

0.5

2.8

97.2

(1.0)

(11.0)

—

(6.4)

(37.3)

(2.9)

(12.1)

(14.0)

0.1
(10.4)
92.2

1.2
(120.0)
833.4

50.3
58.8

451.2
483.2

—
(6.1)
62.3

15.2
27.2

—
(8.1)
71.7

—
(100.3)
664.0

46.0
50.3

411.0
451.2

—
(3.5)
27.5

—
15.2

—
(6.4)
57.4

0.2
(71.9)
640.0

48.1
46.0

342.0
411.0

21.4
33.5

212.8
350.2

12.3
35.1

11.4
21.4

229.0
212.8

—
12.3

5.7
11.4

107.5
229.0

—

—
—
—

—
—

Total proved
reserves

Beginning of year
Revisions of

previous estimate

Discoveries and
extensions

Infill reserves in an
existing proved
field

Sales of
reserves (4)
Purchases of

minerals in place

Production
End of year (5)
Proved developed

reserves

Beginning of year
End of year

Proved

undeveloped
reserves

Beginning of year
End of year

(1) Please refer to Part I, Items 1 and 2 and Part II, Item 7 for current year reserve discussion.
(2) For the year ended December 31, 2011, of the 11.5 BCFE upward revision of a previous estimate, (25.3) BCFE and
36.8 BCFE relate to price and performance revisions, respectively. The prices used in the calculation of proved
reserve estimates as of December 31, 2011, were $96.19 per Bbl and $4.12 per MMBtu, for oil and natural gas
respectively. These prices were 21 percent higher and six percent lower, respectively, than the prices used in 2010.
The per Bbl price used to estimate proved NGL reserves as of December 31, 2011 was $59.37. There is no 2010
comparative price as 2010 NGL production volumes, revenues, and prices have not been reclassified to conform with
current presentation given the immateriality of NGL volumes in that period. Performance revisions in 2011 resulted in
a net 36.8 BCFE increase in our estimate of proved reserves. This increase includes the impact of the Company's
conversion to three stream production, which is partially offset by downward engineering revisions due primarily to
the failure of Woodford shale wells in the Company's Mid-Continent region to satisfy internal economic hurdles. The
Company added 526.1 BCFE from its drilling program, the majority of which related to activity in the Eagle Ford
shale in South Texas. These additions are included in discoveries and extensions and infill reserves.

(3) For the year ended December 31, 2010, of the 24.7 BCFE upward revision of a previous estimate, 42.6 BCFE and
(17.9) BCFE relate to price and performance revisions, respectively. The prices used in the calculation of proved
reserve estimates as of December 31, 2010, were $79.43 per Bbl and $4.38 per MMBtu for oil and natural gas,
respectively. These prices were 30 percent and 13 percent higher, respectively, than the prices used in 2009.

137

Performance revisions in 2010 resulted in a net 11.2 BCFE decrease in the Company's estimate of proved reserves.
While the Company recognized upward performance revisions in every region on proved developed properties, it had
approximately 19.3 BCFE of downward performance revisions related to estimated proved undeveloped reserves in
primarily dry gas assets, resulting from lower gas prices and higher well costs which negatively impacted the
economics of these assets. The Company added 384.2 BCFE from its drilling program, the majority of which related
to activity in the Eagle Ford shale in south Texas. These additions are included in discoveries and extensions and infill
reserves.

(4) The Company divested of certain non-core assets during 2012, 2011, and 2010. Please refer to Note 3 - Divestitures

and Assets Held for Sale for additional information.

(5) For the years ended December 31, 2012, 2011, and 2010, amounts included approximately 299, 175, and 356 MMcf

respectively, representing the Company’s net underproduced gas balancing position.

Note: Prior to 2011, the Company reported its natural gas production as a single stream of rich gas measured at the well head.
Beginning in the first quarter of 2011, the Company changed its reporting for natural gas volumes to separately show natural
gas and NGL production volumes, revenues, and pricing consistent with title transfer for each product. Please refer to
additional discussion above under the caption Oil, Gas, and NGL Prices.

Standardized Measure of Discounted Future Net Cash Flows

The Company computes a standardized measure of future net cash flows and changes therein relating to

estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and
production and development costs are determined by applying prices and costs, including transportation, quality,
and basis differentials, to the year-end estimated future reserve quantities. Each property the Company operates is
also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are
computed using the current statutory income tax rates, including consideration for estimated future statutory
depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10 percent annual
discount factor.

Future operating costs are determined based on estimates of expenditures to be incurred in developing and
producing the proved reserves in place at the end of the period using year-end costs and assuming continuation of
existing economic conditions, plus Company overhead incurred by the central administrative office attributable to
operating activities.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC.

These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from
those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as
discussed previously, are equally applicable to the standardized measure computations since these reserve quantity
estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and
basis differentials were used in the calculation of the standardized measure:

For the Years Ended December 31,
2011

2010

2012

Gas (per Mcf)
Oil (per Bbl)
NGLs (per Bbl)

$
$
$

3.08
86.80
41.00

$
$
$

4.72
88.00
51.95

$
$
$

5.54
70.60
—

138

The following summary sets forth the Company’s future net cash flows relating to proved oil, gas, and NGL

reserves based on the standardized measure.

Future cash inflows
Future production costs
Future development costs
Future income taxes

Future net cash flows

10 percent annual discount
Standardized measure of discounted
future net cash flows

2012

13,129,243
(5,013,720)
(1,742,978)
(1,609,397)
4,763,148
(1,742,134)

As of December 31,
2011
(in thousands)
$

10,871,281
(3,786,887)
(1,036,352)
(1,740,394)
4,307,648
(1,727,608)

2010

7,598,159
(2,512,091)
(789,493)
(1,335,576)
2,960,999
(1,294,632)

3,021,014

2,580,040

1,666,367

The principle sources of change in the standardized measure of discounted future net cash flows are:

Standardized measure, beginning of year
Sales of oil, gas, and NGLs produced, net of

production costs

Net changes in prices and production costs
Extensions, discoveries and other including infill

reserves in an existing proved field, net
of production costs
Sales of reserves in place
Purchase of reserves in place
Development costs incurred during the year
Changes in estimated future development costs
Revisions of previous quantity estimates
Accretion of discount
Net change in income taxes
Changes in timing and other
Standardized measure, end of year

2012

For the Years Ended December 31,
2011
(in thousands)
1,666,367
$

2,580,040

2010

1,015,967

(1,081,997)
(550,293)

(1,042,281)
454,646

(641,213)
557,681

1,872,810
(41,020)
3,785
163,937
47,980
(452,454)
346,118
53,005
79,103
3,021,014

1,816,640
(369,820)
—
49,246
(31,410)
32,992
234,433
(203,169)
(27,604)
2,580,040

989,365
(151,315)
804
43,900
49,531
66,759
128,408
(409,848)
16,328
1,666,367

139

Quarterly Financial Information (unaudited)

The Company’s quarterly financial information for fiscal years 2012 and 2011 is as follows (in thousands,

except per share amounts):

First
Quarter

Second
Quarter

Third
Quarter

Fourth (1)
Quarter

Year Ended December 31, 2012
Total operating revenues
Total operating expenses
Income (loss) from operations
Income (loss) before income taxes
Net income (loss)
Basic net income (loss) per common share
Diluted net income (loss) per common share
Dividends declared per common share

Year Ended December 31, 2011
Total operating revenues
Total operating expenses
Income (loss) from operations
Income (loss) before income taxes
Net income (loss)
Basic net income (loss) per common share
Diluted net income (loss) per common share
Dividends declared per common share

$
$
$
$
$
$

377,423
321,198
56,225
42,017
26,336
0.41
0.39
0.05

315,329
335,301
(19,972)
(29,558)
(18,503)
(0.29)
(0.29)
0.05

$
$
$
$
$
$

304,420
252,029
52,391
39,684
24,889
0.39
0.37

$
$
$
$
$
— $

377,873
166,166
211,707
197,384
124,533
1.96
1.86

$
$
$
$
$
— $

378,951
421,787
(42,836)
(61,072)
(38,336)
(0.58)
(0.58)
0.05

530,574
157,786
372,788
363,443
230,097
3.60
3.41
0.05

$
$
$
$
$
$

444,308
530,105
(85,797)
(104,146)
(67,138)
(1.02)
(1.02)
—

379,542
559,681
(180,139)
(192,268)
(120,711)
(1.89)
(1.89)
—

(1) The fourth quarter of 2012 and 2011 included $170.4 million and $170.5 million, respectively, of impairment of proved
properties expense. Please refer to the caption Impairment of Proved and Unproved Properties included in Note 1 -
Summary of Significant Accounting Policies for additional discussion.

140

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that

information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the
time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated
and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as
appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that

our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act)
(“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of
controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the
company have been detected. These inherent limitations include the realities that judgments in decision-making can
be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be
circumvented by the individual acts of some persons, by collusion of two or more people, or by management
override of the control. The design of any system of controls also is based in part upon certain assumptions about
the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated
goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system,
misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make
modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems
change and conditions warrant.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as

of the end of the period covered by this report. This evaluation was performed under the supervision and with the
participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon
that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls
are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes during the fourth quarter of 2012 that have materially affected, or are

reasonably likely to materially affect, our internal control over financial reporting.

141

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over

financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as
amended. The Company’s internal control over financial reporting is designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. The Company’s internal control over financial reporting
includes those policies and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the

transactions and dispositions of the assets of the Company;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of

financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the Company are being made only in accordance with authorizations of management
and directors of the Company; and

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use,

or disposition of the Company’s assets that have a material effect on the financial statements.

Because of the inherent limitations, internal controls over financial reporting may not prevent or detect

misstatements. Even those systems determined to be effective can provide only reasonable assurance with respect
to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the
degree of compliance with the policies and procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of

December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on our assessment and those criteria, management believes that the Company maintained effective

internal control over financial reporting as of December 31, 2012.

The Company’s independent registered public accounting firm has issued an attestation report on the

Company’s internal controls over financial reporting. That report immediately follows this report.

142

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
SM Energy Company and Subsidiaries
Denver, Colorado

We have audited the internal control over financial reporting of SM Energy Company and subsidiaries (the
“Company”) as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management
is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on
Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal
control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the
company’s principal executive and principal financial officers, or persons performing similar functions, and effected
by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of the financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion
or improper management override of controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over
financial reporting to future periods are subject to the risk that controls may become inadequate because of changes
in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2012, based on the criteria established in Internal Control – Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the consolidated financial statements as of and for the year ended December 31, 2012, of the Company and
our report dated February 21, 2013, expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
February 21, 2013

143

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The information required by this Item concerning SM Energy’s Directors and corporate governance is
incorporated by reference to the information provided under the captions Structure of the Board of Directors,
Proposal 1 - Election of Directors, and Corporate Governance in SM Energy’s definitive proxy statement for the
2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012.

The information required by this Item concerning compliance with Section 16(a) of the Securities Exchange

Act of 1934 is incorporated by reference to the information provided under the caption Section 16(a) Beneficial
Ownership Reporting Compliance in SM Energy’s definitive proxy statement for the 2013 annual meeting of
stockholders to be filed within 120 days from December 31, 2012.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth the names, ages and positions of SM Energy’s executive officers. The age of

the executive officers is as of February 14, 2013.

Name

Age

Position

Anthony J. Best
Javan D. Ottoson
A. Wade Pursell
David W. Copeland
Gregory T. Leyendecker
Mark D. Mueller
Lehman E. Newton, III
Herbert S. Vogel
Kenneth J. Knott
Mary Ellen Lutey
Mark T. Solomon
David J. Whitcomb
Dennis A. Zubieta

President and Chief Operating Officer
Executive Vice President and Chief Financial Officer
Senior Vice President, General Counsel and Corporate Secretary
Senior Vice President and Regional Manager
Senior Vice President and Regional Manager
Senior Vice President and Regional Manager
Senior Vice President - Portfolio Development and Technical Services

63 Chief Executive Officer
54
47
56
55
48
57
52
48 Vice President - Land
41 Vice President and Regional Manager
44 Vice President - Controller and Assistant Secretary
50 Vice President - Marketing
46 Vice President - Engineering, Evaluation and A&D

Anthony J. Best. Mr. Best joined the Company in June 2006 as President and Chief Operating Officer. In
December 2006, Mr. Best relinquished his position as Chief Operating Officer when the Board appointed Javan D.
Ottoson to that office. Mr. Best was elected Chief Executive Officer and a director of the Company in February
2007. Mr. Best relinquished his position as President when the Board appointed Mr. Ottoson to that office in
October 2012. From November 2005 to June 2006, Mr. Best was developing a business plan and securing capital
commitments for a new exploration and production entity. From 2003 to October 2005, Mr. Best was President and
Chief Executive Officer of Pure Resources, Inc., an independent oil and natural gas exploration and production
company that was a subsidiary of Unocal, where he managed all of Unocal’s onshore United States assets. From
2000 to 2002, Mr. Best had an oil and gas consulting practice, working with various energy firms. From 1979 to
2000, Mr. Best was with ARCO in a variety of positions, including serving as President-ARCO Latin America,
President-ARCO Permian, Field Manager for Prudhoe Bay and VP-External Affairs for ARCO Alaska. Mr. Best
has over 34 years of experience in the energy industry.

144

Javan D. Ottoson. Mr. Ottoson joined the Company in December 2006 as Executive Vice President and
Chief Operating Officer. Mr. Ottoson was appointed as President of the Company in October 2012. Mr. Ottoson
has been in the energy industry for over 31 years. From April 2006 until he joined the Company in December 2006,
Mr. Ottoson was Senior Vice President-Drilling and Engineering at Energy Partners, Ltd., an independent oil and
natural gas exploration and production company, where his responsibilities included overseeing all aspects of its
drilling and engineering functions. Mr. Ottoson managed Permian Basin assets for Pure Resources, Inc., a Unocal
subsidiary, and its successor owner, Chevron, from July 2003 to April 2006. From April 2000 to July 2003,
Mr. Ottoson owned and operated a homebuilding company in Colorado and ran his family farm. Prior to 2000,
Mr. Ottoson worked for ARCO in management and operational roles, including serving as President of ARCO
China, Commercial Director of ARCO United Kingdom, and Vice President of Operations and Development,
ARCO Permian.

A. Wade Pursell. Mr. Pursell joined the Company in September 2008 as Executive Vice President and

Chief Financial Officer. Mr. Pursell was Executive Vice President and Chief Financial Officer for Helix Energy
Solutions Group, Inc., a global provider of life-of-field services and development solutions to offshore energy
producers and an oil and gas producer, from February 2007 to September 2008. From October 2000 to February
2007, he was Senior Vice President and Chief Financial Officer of Helix. He joined Helix in May 1997, as Vice
President-Finance and Chief Accounting Officer. From 1988 through May 1997, Mr. Pursell was with Arthur
Andersen LLP, serving lastly as an Experienced Manager specializing in the offshore services industry. Mr. Pursell
has over 25 years of experience in the energy industry.

David W. Copeland. Mr. Copeland joined the Company in January 2011 as Senior Vice President and

General Counsel. He was appointed as the Company’s Corporate Secretary in July 2011. Mr. Copeland has over
31 years of experience in the legal profession, including over 21 years as internal counsel for various energy
companies. Prior to joining the Company, he co-founded Concho Resources Inc., in Midland, Texas, where he
served as its Vice President, General Counsel and Secretary from April 2004 through November 2009, and then as
its Senior Counsel through December 2010. From August 1997 through March 2004, Mr. Copeland served as an
executive officer and general counsel of two energy companies he co-founded in Midland, Texas with others.
Mr. Copeland started his career in 1982 with the Stubbeman, McRae, Sealy, Laughlin & Browder law firm in
Midland, Texas.

Gregory T. Leyendecker. Mr. Leyendecker was appointed Senior Vice President and Regional Manager in

May 2010. From July 2007 to May 2010, he served as Vice President and Regional Manager. Mr. Leyendecker
joined the Company in December 2006 as Operations Manager for the South Texas & Gulf Coast region in
Houston, Texas. Mr. Leyendecker has over 32 years of experience in the energy industry, and held various positions
with Unocal Corporation, an independent oil and natural gas exploration and production company, from 1980 until
its acquisition in 2005. During his career with Unocal, he was the Asset Manager for Unocal Gulf Region USA
from 2003 to June 2004 and Production and Reservoir Engineering Technology Manager for Unocal from June
2004 to August 2005. He was appointed Drilling and Workover Manager for the San Joaquin Valley business unit
of Chevron, as successor-by-merger of Unocal Corporation, in Bakersfield, California in August 2005, and held this
position until January 2006. Immediately prior to joining the Company, Mr. Leyendecker was Vice President of
Drilling Management Services from February 2006 to November 2006 for Enventure Global Technology, a provider
of solid expandable tubular technology.

145

Mark D. Mueller. Mr. Mueller joined the Company in September 2007 as Senior Vice President.

Mr. Mueller was appointed as the Regional Manager of the Rocky Mountain region effective January 1, 2008.
Mr. Mueller has been in the energy industry for over 26 years. From September 2006 to September 2007, he was
Vice President and General Manager at Samson Exploration Ltd., an oil and gas exploration and production
company that was a subsidiary of Samson Investment Company, in Calgary, Canada, where his responsibilities
included fiscal performance, reserves, and all operational functions of the company. From April 2005 until its sale
in August 2006, Mr. Mueller was Vice President and General Manager for Samson Canada Ltd., an oil and gas
exploration and production company that was a subsidiary of Samson Investment Company, where he was
responsible for all business units and the eventual sale of the company. Mr. Mueller joined Samson Canada Ltd. as
Project Manager in May 2003 to build a new basin-centered gas business unit and was Vice President from
December 2003 to August 2006. Prior to joining Samson, Mr. Mueller was West Central Alberta Engineering
Manager for Northrock Resources Ltd., a Canadian oil and gas company that was a wholly-owned subsidiary of
Unocal Corporation, in Calgary, Canada. From 1986 to 2003, Mr. Mueller held positions of increasing
responsibility in engineering and management for Unocal throughout North America and Southeast Asia.

Lehman E. Newton, III. Mr. Newton joined the Company in December 2006 as General Manager for the
Midland, Texas office, was appointed Vice President and Regional Manager of the Permian region in June 2007,
and was appointed Senior Vice President and Regional Manager in May 2010. Mr. Newton has over 34 years of
experience in the energy industry. From November 2005 to November 2006, Mr. Newton served as Project
Manager for one of Chevron’s largest Lower 48 projects. Mr. Newton joined Pure Resources in February 2003 as
the Business Development Manager and worked in that capacity until October 2005. Mr. Newton was a founding
partner in Westwin Energy, an independent Permian Basin exploration and production company, from June 2000 to
January 2003. Prior to that, Mr. Newton spent 21 years with ARCO in various engineering, operations and
management roles, including as Asset Manager, ARCO’s East Texas operations, Vice President, Business
Development, ARCO Permian, and Vice President of Operations and Development, ARCO Permian.

Herbert S. Vogel. Mr. Vogel joined the Company in March 2012 as Senior Vice President-Portfolio
Development and Technical Services, and is responsible for Corporate Exploration, Engineering, Land, Marketing
and EHS activities. Mr. Vogel has over 28 years of experience in the oil and gas business. He joined the Company
after his retirement from BP, where he most recently served as the President of BP Energy Co. and Regional
Business Unit Leader of North American Gas & Power. His previous roles included COO-NGL, Power & Financial
Products in Houston, Managing Director Gas Europe & Africa in London, and Sr. VP of the Tangguh LNG Project
in Indonesia. Mr. Vogel started his career as a reservoir engineer with ARCO Alaska, Inc., and progressed through a
series of positions of increasing responsibility in engineering, operations management, new ventures development,
and business unit management at ARCO and BP.

Kenneth J. Knott. Mr. Knott was appointed Vice President - Land in October 2012, and is responsible for

all of the Company's regional and administrative land functions. Mr. Knott was appointed Vice President of
Business Development & Land and Assistant Secretary in August 2008. Mr. Knott joined SM Energy in November
2000 as Senior Landman for the Gulf Coast region in Lafayette, Louisiana, and later assumed the position of Gulf
Coast Regional Land Manager when the office was moved to Houston in March 2004.

146

Mary Ellen Lutey. Ms. Lutey was appointed Vice President and Regional Manager of the Mid-Continent

region in December 2012. She joined SM Energy in June 2008 as North Rockies Asset Manager, where she
managed the Company's activities in the Williston Basin. Prior to joining SM Energy, Ms. Lutey held various
technical and managerial positions in several regions of the United States and Canada. She was a Senior Reservoir
Engineer with Chesapeake Energy Corporation from September 2007 until June 2008, where she was responsible
for the resource development of the Fayetteville Shale in Arkansas. Ms. Lutey was a Team Lead for Engineering
and Geoscience, with ConocoPhillips Canada from April 2006 until September 2007, where she was responsible for
the technical and business performance of two multi-discipline groups in Western Canada. From July 2005 until
April 2006, she was a Team Lead for Engineering and Geoscience, with Burlington Resources Canada where she
managed the growth and development of resource plays in Western Canada. From 1994 until 2005, Ms. Lutey held
various engineering and leadership positions of increasing responsibility for Burlington Resources. Ms. Lutey has
over 21 years of experience in the energy industry.

Mark T. Solomon. Mr. Solomon was appointed Vice President-Controller and Assistant Secretary of the

Company in May 2011. He was appointed Controller of the Company in January 2007. Mr. Solomon served as the
Company’s Acting Principal Financial Officer from April 2008, to September 2008, which was during the period of
time that the Company’s Chief Financial Officer position was vacant. Mr. Solomon joined the Company in 1996.
He served as Financial Reporting Manager from February 1999 to September 2002, Assistant Vice President-
Financial Reporting from September 2002 to May 2006 and Assistant Vice President-Assistant Controller from May
2006 to January 2007. Prior to joining the Company, Mr. Solomon was an auditor with Ernst & Young.
Mr. Solomon has over 16 years of experience in the energy industry.

David J. Whitcomb. Mr. Whitcomb was appointed Vice President - Marketing in August 2008. Mr.
Whitcomb joined SM Energy in November 1994 as Gas Contract Analyst and was named Assistant Vice President
of Gas Marketing in October 1995. In March 2007, his responsibilities were expanded to include oil marketing, at
which time his title was changed to Assistant Vice President and Director of Marketing.

Dennis A. Zubieta. Mr. Zubieta was appointed Vice President-Engineering, Evaluation and A&D in

October 2012. He was appointed Vice President-Engineering and Evaluation of the Company in August 2008.
Mr. Zubieta joined the Company in June 2000 as Corporate A&D Engineer, assumed the role of Reservoir Engineer
in February 2003, and was appointed Reservoir Engineering Manager in August 2005. Mr. Zubieta was employed
by Burlington Resources from June 1988 to May 2000 in various operations and reservoir engineering capacities.
Mr. Zubieta has over 25 years of experience in the energy industry.

ITEM 11.

EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the information provided under the
captions, Executive Compensation and Director Compensation in SM Energy’s definitive proxy statement for the
2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS

The information required by this Item concerning security ownership of certain beneficial owners and
management is incorporated by reference to the information provided under the caption Security Ownership of
Certain Beneficial Owners and Management in SM Energy’s definitive proxy statement for the 2013 annual
meeting of stockholders to be filed within 120 days from December 31, 2012.

147

Securities Authorized for Issuance Under Equity Compensation Plans. SM Energy has the Equity Plan

under which options and shares of SM Energy common stock are authorized for grant or issuance as compensation
to eligible employees, consultants, and members of the Board of Directors. Our stockholders have approved this
plan. See Note 7 – Compensation Plans included in Part II, Item 8 of this report for further information about the
material terms of our equity compensation plans. The following table is a summary of the shares of common stock
authorized for issuance under the equity compensation plans as of December 31, 2012:

(a)

(b)

(c)

Number of
securities to be
issued upon
exercise of
outstanding
options,
warrants, and
rights

Weighted-
average
exercise price
of outstanding
options,
warrants, and
rights

Number of
securities remaining
available for future
issuance under
equity
compensation plans
(excluding
securities reflected
in column (a))

267,846
496,244
899,604
1,663,694
-

-
1,663,694

14.95
N/A
N/A
14.95
-

-
14.95

1,366,465
1,307,484

-
2,673,949

Plan category
Equity compensation plans approved by security

holders:

Equity Incentive Compensation Plan

Stock options and incentive stock options (1)
Restricted stock (1)(3)
Performance share units (1)(3)(4)

Total for Equity Incentive Compensation Plan
Employee Stock Purchase Plan (2)
Equity compensation plans not approved by

security holders
Total for all plans

(1) In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units,
non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and
stock-based awards to key employees, consultants, and members of the Board of Directors of SM Energy or any affiliate of
SM Energy. The Equity Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the
St. Mary Land & Exploration Company Incentive Stock Option Plan, the SM Energy Company Restricted Stock Plan, and
the SM Energy Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor
Plans”). All grants of equity are now made under the Equity Plan, and no further grants will be made under the
Predecessor Plans. Each outstanding award under a Predecessor Plan immediately prior to the effective date of the Equity
Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances.
Our Board of Directors approved amendments to the Equity Plan in 2009 and 2010 and each amended plan was approved
by stockholders at the respective annual stockholders’ meetings. The awards granted in 2012, 2011, and 2010 under the
Equity Plan were 724,671, 386,802, and 540,774, respectively.

(2) Under the SM Energy Company ESPP, eligible employees may purchase shares of our common stock through payroll

deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of
the fair market value of the stock on the first or last day of the six-month offering period, and shares issued under the ESPP
on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of
the Internal Revenue Code. Shares issued under the ESPP totaled 66,485, 41,358, and 52,948 in 2012, 2011, and 2010,
respectively.

(3) RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per share fair value,

which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The
weighted-average grant date per share fair value for the outstanding RSUs and PSUs was $51.81 and $63.08, respectively.
Please refer to Note 7 - Compensation Plan for additional discussion.

(4) The number of awards vested assumes a one multiplier. The final number of shares issued upon settlement may vary
depending on the three-year multiplier determined at the end of the performance period under the Equity Plan, which
ranges from zero to two.

148

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE

The information required by this Item is incorporated by reference to the information provided under the

caption Certain Relationships and Related Transactions, and Corporate Governance, in SM Energy’s definitive
proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item is incorporated by reference to the information provided under the

caption Independent Registered Public Accounting Firm and Audit Committee Preapproval Policy and Procedures
in SM Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days
from December 31, 2012.

149

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:

PART IV

Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements

89
90
91
92
93
94
96

All schedules are omitted because the required information is not applicable or is not present in amounts

sufficient to require submission of the schedule or because the information required is included in the Consolidated
Financial Statements and Notes thereto.

(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report

on Form 10-K:

Exhibit
Number

Description

2.1

2.2

2.3

2.4

2.5

3.1

3.2

Purchase and Sale Agreement dated December 17, 2009 and effective as of November 1, 2009,
between Legacy Reserves Operating LP and St. Mary Land & Exploration Company (filed as
Exhibit 2.5 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009
and incorporated herein by reference)
Purchase and Sale Agreement dated January 7, 2010 and effective as of November 1, 2009,
between Sequel Energy Partners LP, Bakken Energy Partners, LLC, Three Forks Energy Partners,
LLC and St. Mary Land & Exploration Company (filed as Exhibit 2.6 to the registrant’s Annual
Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by
reference)
Purchase and Sale Agreement dated June 9, 2011, among SM Energy Company, Statoil Texas
Onshore Properties LLC, and Talisman Energy USA Inc. (filed as Exhibit 2.1 to the registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 and incorporated herein by
reference)
Acquisition and Development Agreement dated June 29, 2011 between SM Energy Company and
Mitsui E&P Texas LP (filed as Exhibit 2.2 to the registrant’s Quarterly Report on Form 10-Q for
the quarter ended June 30, 2011 and incorporated herein by reference)
First Amendment to Acquisition and Development Agreement dated October 13, 2011 between
SM Energy Company and Mitsui E&P Texas (filed as Exhibit 2.1 to the registrant’s Quarterly
Report on Form 10-Q for the quarter ended September 30, 2011 and incorporated herein by
reference)
Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010
(filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June
30, 2010 and incorporated herein by reference)
Amended and Restated By-Laws of SM Energy Company amended effective as of January 1,
2013 (filed as Exhibit 3.1 to the registrant’s Current Report on Form 8-K filed on January 7, 2013,
and incorporated herein by reference)

150

4.1

4.2

4.3

4.4

4.5

10.1†

10.2†

10.3†

10.4†

10.5†

10.6

10.7

10.8†

10.9†

10.10

10.11†

Indenture related to the 3.50% Senior Convertible Notes due 2027, dated as of April 4, 2007,
between St. Mary Land & Exploration Company and Wells Fargo Bank, National Association, as
trustee (including the form of 3.50% Senior Convertible Note due 2027) (filed as Exhibit 4.1 to
the registrant’s Current Report on Form 8-K filed on April 4, 2007 and incorporated herein by
reference)
Indenture related to the 6.625% Senior Notes due 2019, dated as of February 7, 2011, by and
between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as
Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on February 10, 2011, and
incorporated herein by reference)
Indenture related to the 6.50% Senior Notes due 2021, dated as of November 8, 2011, by and
among SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as
Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on November 10, 2011, and
incorporated herein by reference)
Indenture related to the 6.50% Senior Notes due 2023, dated June 29, 2012, between SM Energy
Company, as Issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the
registrant’s Current Report on Form 8-K filed on July 3, 2012, and incorporated herein by
reference)
Registration Rights Agreement, dated June 29, 2012, among SM Energy Company and Wells
Fargo Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan
Securities LLC, as representatives of several purchasers (filed as Exhibit 4.2 to the registrant’s
Current Report on Form 8-K filed on July 3, 2012, and incorporated herein by reference)
Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s
Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by
reference)
Incentive Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to the
registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated
herein by reference)
Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001 and
incorporated herein by reference)
Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as
Exhibit 10.9 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
2005 and incorporated herein by reference)
Employment Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the registrant’s
Current Report on Form 8-K filed on May 4, 2006 and incorporated herein by reference)
Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment,
Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank,
National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as
Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and
incorporated herein by reference)
Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective
as of April 14, 2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on
April 20, 2009, and incorporated herein by reference)
Equity Incentive Compensation Plan as Amended and Restated as of March 26, 2009 (filed as
Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2009, and
incorporated herein by reference)
Equity Incentive Compensation Plan As Amended and Restated as of April 1, 2010 (filed as
Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on June 2, 2010, and
incorporated herein by reference)
SM Energy Company Equity Incentive Compensation Plan, As Amended as of July 30, 2010 (filed
as Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September
30, 2010 and incorporated herein by reference)
Third Amendment to Employee Stock Purchase Plan dated September 23, 2009 (filed as Exhibit
10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009,
and incorporated herein by reference)

151

10.12†

10.13

10.14

10.15†

10.16†

10.17†

10.18***

10.19

10.20

10.21

10.22†

10.23†

10.24

10.25

10.26+

10.27*†
10.28

10.29

Fourth Amendment to Employee Stock Purchase Plan dated December 29, 2009 (filed as Exhibit
10.46 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009, and
incorporated herein by reference)
Employee Stock Purchase Plan, As Amended and Restated as of July 30, 2010 (filed as Exhibit
10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010
and incorporated herein by reference)
Carry and Earning Agreement between St. Mary Land & Exploration Company and Encana Oil &
Gas (USA) Inc. executed as of April 29, 2010 (filed as Exhibit 10.2 to the registrant’s Quarterly
Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference)
Form of Performance Share and Restricted Stock Unit Award Agreement as of July 1, 2010 (filed
as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
2010 and incorporated herein by reference)
Form of Performance Share and Restricted Stock Unit Award Notice as of July 1, 2010 (filed as
Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
2010 and incorporated herein by reference)
Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as
Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
2010 and incorporated herein by reference)
Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle
Ford Gathering LLC (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for
the quarter ended September 30, 2010 and incorporated herein by reference)
Cash Bonus Plan, As Amended on July 30, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly
Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by
reference)
Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as
Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September
30, 2010 and incorporated herein by reference)
SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan, As Amended as of
July 30, 2010 (filed as Exhibit 10.8 to the registrant’s Quarterly Report on Form 10-Q for the
quarter ended September 30, 2010 and incorporated herein by reference)
Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as
Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on December 29, 2010, and
incorporated herein by reference)
Amendment to A.J. Best Employment Agreement dated December 31, 2010 (filed as Exhibit
10.28 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010,
and incorporated herein by reference)
Purchase Agreement, dated January 31, 2011, among SM Energy Company and Merrill Lynch,
Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the
Initial Purchasers named therein (filed as Exhibit 10.1 to the registrant’s Current Report on Form
8-K filed on February 1, 2011, and incorporated herein by reference)
Pension Plan for Employees of SM Energy Company as Amended and Restated as of
January 1, 2010 (filed as Exhibit 10.30 to the registrant’s Annual Report on Form 10-K filed for
the year ended December 31, 2010, and incorporated herein by reference)
SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of
November 9, 2010 (filed as Exhibit 10.31 to the registrant’s Annual Report on Form 10-K filed for
the year ended December 31, 2010, and incorporated herein by reference)
Summary of Compensation Arrangements for Non-Employee Directors

Fourth Amended and Restated Credit Agreement dated May 27, 2011 among SM Energy
Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders
party thereto (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the
quarter ended June 30, 2011, and incorporated herein by reference)
Gas Gathering Agreement dated May 31, 2011 between Regency Field Services LLC and SM
Energy Company (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the
quarter ended June 30, 2011, and incorporated herein by reference)

152

10.30

10.31

10.32†

10.33†

10.34†

10.35†

10.36†

10.37

10.38

12.1*
21.1*
23.1*
23.2*
24.1*
31.1*

31.2*

32.1**

Gathering and Natural Gas Services Agreement effective as of April 1, 2011 between SM Energy
Company and ETC Texas Pipeline, Ltd. (filed as Exhibit 10.3 to the registrant’s Quarterly Report
on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
Gas Processing Agreement effective as of April 1, 2011 between ETC Texas Pipeline, Ltd. and SM
Energy Company (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the
quarter ended June 30, 2011, and incorporated herein by reference)
Employee Stock Purchase Plan, As Amended and Restated as of June 10, 2011 (filed as Exhibit
10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and
incorporated herein by reference)
Form of Performance Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.6 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated
herein by reference)
Form of Restricted Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.7 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated
herein by reference)
Form of Performance Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.1
to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and
incorporated herein by reference)
Form of Restricted Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.2 to
the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and
incorporated herein by reference)
Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of
January 1, 2011 (filed as Exhibit 10.41 to the registrant’s Annual Report on Form 10-K filed for
the year ended December 31, 2011, and incorporated herein by reference)
Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of
January 1, 2012 (filed as Exhibit 10.42 to the registrant’s Annual Report on Form 10-K filed for
the year ended December 31, 2011, and incorporated herein by reference)
Computation of Ratio of Earnings to Fixed Charges
Subsidiaries of Registrant
Consent of Deloitte & Touche LLP
Consent of Ryder Scott Company L.P.
Power of Attorney

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of
2002
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of
2002
Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the
Sarbanes- Oxley Act of 2002
Ryder Scott Audit Letter

99.1*
101.INS**** XBRL Instance Document
101.SCH**** XBRL Schema Document
101.CAL**** XBRL Calculation Linkbase Document
101.LAB**** XBRL Label Linkbase Document
101.PRE**** XBRL Presentation Linkbase Document
101.DEF**** XBRL Taxonomy Extension Definition Linkbase Document

Filed with this Form 10-K.
Furnished with this Form 10-K.

*
**
*** Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the

Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934.
**** Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of

153

Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for
purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the
Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.
Exhibit constitutes a management contract or compensatory plan or agreement.
Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30,
2010 primarily to reflect the recent change in the name of the registrant from St. Mary Land & Exploration Company to
SM Energy Company. There were no material changes to the substantive terms and conditions in this document.
Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on
November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue
Code. There were no material changes to the substantive terms and conditions in this document.

†

154

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.

SIGNATURES

SM ENERGY COMPANY
(Registrant)

Date:

February 21, 2013

By:

/s/ ANTHONY J. BEST
Anthony J. Best
Chief Executive Officer
(Principal Executive Officer)

GENERAL POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and
appoints each of Anthony J. Best and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full
power of substitution and resubstitution, and each with full power to act alone, for the undersigned and in his or her
name, place and stead, in any and all capacities, to sign any amendments to this Annual Report on Form 10-K for the
fiscal year ended December 31, 2012, and to file the same, with exhibits thereto and other documents in connection
therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorney-
in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof.

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/ ANTHONY J. BEST
Anthony J. Best

Chief Executive Officer and Director
(Principal Executive Officer)

February 21, 2013

/s/ A. WADE PURSELL
A. Wade Pursell

Executive Vice President and Chief
Financial Officer
(Principal Financial Officer)

February 21, 2013

/s/ MARK T. SOLOMON
Mark T. Solomon

Vice President - Controller and Assistant
Secretary
(Principal Accounting Officer)

February 21, 2013

155

Signature

Title

Date

/s/ WILLIAM D. SULLIVAN
William D. Sullivan

/s/ BARBARA M. BAUMANN
Barbara M. Baumann

/s/ LARRY W. BICKLE
Larry W. Bickle

/s/ STEPHEN R. BRAND
Stephen R. Brand

/s/ WILLIAM J. GARDINER
William J. Gardiner

/s/ LOREN M. LEIKER
Loren M. Leiker

/s/ JULIO M. QUINTANA
Julio M. Quintana

/s/ JOHN M. SEIDL
John M. Seidl

Chairman of the Board of Directors

February 21, 2013

Director

156

This Page Intentionally Left Blank

Stockholder Information

OFFICES

INVESTOR RELATIONS CONTACT

Denver, CO – Corporate Headquarters
1775 Sherman Street
Suite 1200
Denver, CO 80203
Main Telephone: (303) 861-8140

Billings, MT
550 N. 31st Street
Suite 500
Billings, MT 59101
Main Telephone: (406) 245-6248

Houston, TX
777 N. Eldridge Pkwy
Suite 1100
Houston, TX 77079
Main Telephone: (281) 677-2800

Midland, TX
3300 N. A Street
Building 7
Suite 200
Midland, TX 79705
Main Telephone: (432) 688-1700

Tulsa, OK
6120 S. Yale Ave.
Suite 1300
Tulsa, OK 74136
Main Telephone: (918) 488-7600

DESIGN BY: MARK MULVANY GRAPHIC DESIGN (DENVER, COLORADO)

PHOTOGRAPHY BY: JIM BLECHA (AURORA, COLORADO)

Stockholders, securities analysts, or portfolio managers who have

questions or need information concerning SM Energy may contact

James R. Edwards, Manager of Investor Relations at 303-861-8140.

Email: ir@sm-energy.com

Annual Reports, 10-Ks, 10-Qs

To receive an information packet on SM Energy or to be added to

our mailing list, contact Pam Sweet at 303-861-8140.

Email: information@sm-energy.com

Please visit our Investor Relations website at: sm-energy.com

Stock Transfer Agent

Any stockholder with questions or inquiries regarding stock certificate

holdings, changes in registration address, lost certificates, dividend

payments, and other stockholder account matters should be directed to

SM Energy Company’s transfer agent at the following address or

phone number:

Computershare Trust Company NA

350 Indiana Street, Suite 800

Golden, CO 80401

(303) 262-0600

NYSE: SM

The Company’s common stock is listed for trading on the New York

Stock Exchange under the symbol (SM).

The price ranges of the Company’s common stock by quarter for the

last two years are provided below. As of February 14, 2013, the

Company had 66,205,901 shares of common stock outstanding,

which is net of 50,581 treasury shares held by the Company.

Closing Prices

2012— Quarter Ended

2011— Quarter Ended

March 31

June 30

September 30

December 31

High

83.35

70.96

57.78

59.73

Low

70.51

43.80

41.80

47.05

High

74.19

77.57

83.08

87.05

Low

56.04

62.28

60.65

57.27

Other Information

In 2012, SM Energy submitted to the New York Stock Exchange a

certificate of the Chief Executive Officer of SM Energy certifying that

he was not aware of any violation by SM Energy of the New York

Stock Exchange corporate governance listing standards. SM Energy

has filed with the SEC certifications of the Chief Executive Officer and

Chief Financial Officer required under Section 302 of the Sarbanes-

Oxley Act as exhibits to the Annual Report on Form 10-K for the year

ended December 31, 2012.

SM Energy Company • sm-energy.com