A N N U A L R E P O R T 2 0 0 8
Oil & Gas Production
(MMCFE per day)
Oil & Gas Production
Per Share (MCFE)
350
300
250
200
150
100
50
2.00
1.50
1.00
0.50
04
05
06
07
08
04
05
06
07
08
Proved Oil & Gas Reserves
(BCFE)
1200
1000
800
600
400
200
Proved Oil & Gas Reserves
Per Share (MCFE)
20
15
10
05
04
05
06
07
08
04
05
06
07
08
Shareholders’ Equity
($ Millions)
Operating Cash Flow
($ Millions)
1200
1000
800
600
400
200
700
600
500
400
300
200
100
04
05
06
07
08
04
05
06
07
08
F I N A N C I A L H I G H L I G H T S
2008
2007
2006
2005
2004
In thousands except production, proved reserves, price data, and per share amounts, as adjusted for 2 for 1 split on March 31, 2005
Income Statement Data
Oil and gas production revenues
$ 1,158,304
$ 936,577
$ 758,913
$ 711,005
$ 413,318
Gains on sales and other
142,997
53,517
28,788
28,585
19,781
Total operating revenues
$ 1,301,301
$ 990,094
$ 787,701
$ 739,590
$ 433,099
91,553
$ 189,712
$ 190,015
$ 151,936
$ 92,479
Net income
Diluted earnings per share
$
$
1.45
Cash dividends declared and paid per share $
0.10
Diluted weighted average common
$
$
2.94
0.10
$
$
2.94
0.10
$
$
2.33
0.10
$
$
1.44
0.05
shares outstanding
63,133
64,850
65,962
66,894
66,894
Balance Sheet Data
Working capital
Total assets
Long-term debt
Stockholders’ equity
Average Net Daily Production
Gas (MMcf)
Oil (MBbl)
MMCFE (6:1)
Average Sales Price, net of hedging
Gas (per Mcf)
Oil (per Bbl)
Proved Reserves
Gas (MMcf)
Oil (MBbl)
MMCFE (6:1)
$
15,193
$ (92,604)
$
22,870
$
4,937
$ 12,035
2,695,016
2,571,680
1,899,097
1,268,747
587,500
1,127,485
572,500
863,345
433,980
743,374
99,885
569,320
945,460
136,791
484,455
204.7
18.1
313.1
181.0
18.9
294.5
154.7
16.6
254.2
141.9
16.2
239.4
127.3
13.1
206.0
$
$
8.79
75.59
$
$
7.63
62.60
$
$
7.37
56.60
$
$
7.90
50.93
$
$
5.52
32.53
557,366
51,363
865,544
613,450
78,847
1,086,532
482,475
74,195
927,647
417,075
62,903
794,493
319,196
56,574
658,638
1
L E T T E R T O S T O C K H O L D E R S
The theme of last year’s 2007 annual
St. Mary is doing something similar as a
has built a drilling inventor y in this
report was “Energized for 100 Years
company. We are making the changes to
program that is repeatable, scalable,
…and moving forward”. In 2008, St. Mary
our portfolio and organization that will
and will allow for several years of reserve
celebrated its 100th anniversar y. We
allow us to achieve even greater success
and production growth. The Company’s
celebrated the anniversar y in each of
than what we have achieved in the past.
tight oil program at Sweetie Peck in
our offices with employees, friends, and
Over the last several years, St. Mary has
the Permian Basin is another example
business par tners and finished our
been undergoing a focused, but quiet
of a repeatable program that fits the
celebration by ringing the closing bell at
transformation. The single largest part
resource play concept. Our new acreage
the New York Stock Exchange. It is a
of this transition has been the change in
positions in the Haynesville shale, the
tremendous accomplishment for any
our portfolio. In the past, the Company’s
Eagle Ford shale, and the Marcellus
company to thrive and grow for 100
growth was largely a function of niche
shale are areas that have the potential
years and we are certainly proud of our
acquisitions and subsequent exploitation.
to become resource plays that will
history and legacy. However, we know
St. Mary was highly successful with this
fuel fur ther growth. In addition to the
that we won’t last another 100 years by
strategy, but as we grew larger we were
changes to our portfolio, we have been
resting on our laurels; our goal as a
having a hard time finding enough of
transforming our organization. Importantly,
management team is to continue moving
these niche acquisition opportunities at
we have put in place a system and culture
the business forward and to find ways to
reasonable prices or at a size that would
that should provide exposure to emerging
build value for our stockholders.
be meaningful. We needed to find another
North American resource plays in the
way to grow and we have worked over
future. We have also changed our long-
The theme of this year’s annual report is
the last few years to focus our efforts
term incentive compensation system
“Making the Turn”, which is an important
more on resource plays. These types of
to tie our employees more directly to
period in the drilling of a horizontal well.
programs have the potential to provide
our stockholders.
The “turn” is when you begin to extend the
more predictable and impacting reserve
lateral that will expose a larger section
and production growth. The Company’s
of pay than what you could otherwise
horizontal Woodford shale program in
achieve with a vertical well. Conceptually,
the Arkoma Basin is a good example of
a resource play where we have been
successful. As a result of the Company’s
success in the Woodford shale, St. Mary
2
2008 Results
• We set a record for net cash from
rise from current low levels, we expect
operating activities of $678.2 million,
that these reserves will be recovered
It would be an understatement to say
up 8% year over year.
without additonal capital investment. In
that 2008 was an interesting year. As
the current economic environment where
an industry, we saw commodity prices
• Net income was $91.6 million, or $1.45
capital dollars are precious, this is an
rocket to an all-time high and then quickly
per diluted share. The results for 2008
important distinction. We also had a
retrench as a result of the broader
were significantly impacted by non-cash
negative performance revision of 44.5
financial crisis. Due to the weaker
impairments of proved proper ties,
BFCE, which related primarily to our
commodity prices at year-end, many E&P
unproved properties, and goodwill.
Olmos shallow gas properties in South
companies saw meaningful negative
Texas that we acquired in 2007. The
price revisions, which in many cases
As I noted above, proved reser ves for
Olmos reservoir has proved to be more
resulted in impairments or write-downs
2008 were 865.5 BCFE, which is 20%
complex than we originally thought, and
of assets. St. Mary was not immune
lower than the 1,086.5 BCFE from a year
we have seen lower reserve outcomes
to these industry developments and our
ago. I should also mention that we have
than we expected in attempting to infill
repor ted financial results reflect that
nothing in our proved reserves for our
the field. As a result, our expected
this year. Below is a summary of our
potential in the Haynesville, Eagle Ford,
drilling and recompletion programs for
2008 operational and financial results:
or Marcellus shale plays as of year-end.
those proper ties will be significantly
We had a significant negative price
smaller compared to our plan at the time
• Proved reserves declined 20% year
revision in reserves of 199.7 BCFE as a
of acquisition. While we are disappointed
over year to 865.5 BCFE in 2008, due to
result of the lower commodity prices and
with these results, there is a bit of a silver
negative revisions (from lower prices and
wider price differentials in effect at
lining in that these properties provided
field performance) and divestitures.
year-end 2008. Two-thirds of this related
our initial position in the Maverick Basin,
to the oil-weighted Rocky Mountain region,
which we have built upon to gain mean-
• Average daily production reached a
with lower prices for natural gas liquids
ingful exposure to the emerging Eagle
new annual record of 313.1 MMCFE per
in South Texas also contributing to the
Ford and Pearsall shale plays.
day, which is up 6% year over year. Year
downward price revision. An important
over year daily production growth would
fact to point out is that 74% of the
have been 13% if we had not divested a
negative price revision related to proved
number of non-strategic assets in 2008.
developed reserves. As operating costs
come down to a level commensurate
with current product prices or as prices
5
a year ago. The ability to access this
market has become harder and the cost
of accessing it has increased significantly.
Our prudent use of leverage and a solid
reser ve base have helped St. Mar y
Our finding costs from drilling, excluding
play-leveraged company. Results of
maintain a strong balance sheet, which
price and per formance revisions, in
St. Mary’s development of the Woodford
is imperative in the current environment.
2008 was $3.99 per MCFE. This is an
shale and Wolfberr y tight oil assets
improvement over the $5.32 per MCFE
improved nicely over 2008. During
Plans for 2009
from 2007 and below our 3 year average
the year we also gained exposure to
of $4.48 per MCFE. Our reserve replace-
several emerging resource plays — the
Clearly, the overall economic environment
ment from drilling activity, excluding price
Haynesville shale, the Eagle Ford shale,
is much different today than it was early
and performance revisions, was 148%
and the Marcellus shale — that we did
in 2008. The broader financial crisis has
in 2008. As with our 2008 finding costs,
not have in our portfolio at the beginning
impacted the exploration and production
this was an improvement from both the
of 2008. While we were for tunate to
industr y in two key ways. First, the
123% in 2007 and the 3 year average
already own acreage with Haynesville
economic slowdown has resulted in
of 133%. We believe that finding costs
rights, our entry into the Eagle Ford and
diminished demand for natural gas and
and reserve replacement using drilling
Marcellus are a result of our deliberate
oil, which in turn puts downward pressure
activity, excluding price and performance
efforts to enter emerging resource plays
on the price for those commodities. The
revisions, are meaningful indicators
at an earlier stage of their life cycle. We
amount of cash flow we will have available
of our operational per formance in a
also continued to optimize our portfolio
in 2009 for capital investment is tied to
given year.
of assets. You’ll recall that we sold a
the prices we receive for our production.
large divestiture package in Januar y of
Second, the capital markets have become
I believe that St. Mar y is a stronger
2008, the largest in the Company’s
much more difficult to access and the
company today compared to when I
history. Throughout 2008 we rationalized
price to do so has increased significantly.
wrote to you last year. During the year
our portfolio further as we sold out of
we continued to execute on our strategy
assets in the Greater Green River Basin
of transforming St. Mary into a resource
and the Judge Digby Field in Louisiana.
Lastly, the capital market environment is
clearly much different today than it was
6
7
8
Fortunately, St. Mary is well positioned to
current commodity prices and our view of
Haynesville, Eagle Ford, and Marcellus
weather these stormy times. As you have
the deflationary pressures on the oilfield
shales have the potential to create
come to expect with St. Mary, our balance
services sector, we believe that the most
significant value for our stockholders.
sheet is in solid shape. At year-end 2008,
rational decision is to defer investment
our debt-to-book capitalization ratio stood
in development programs. With no mean-
While we are “Making the Turn”, there
at 34% and we had $200 million available
ingful lease expirations in the near-term
are certain things at St. Mary that won’t
under our reserve-backed lending facility.
and limited long-term rig commitments,
change. Our focus on net asset value
We also have a solid hedge position that
we have the luxur y of time and can wait
per share growth and our emphasis on
helps provide a predictable level of cash
until commodity prices improve and/or
maintaining a strong balance sheet are
flow. In order to maintain this financial
well costs come down.
fundamental to our business strategy.
strength, our plan in 2009 is to invest
capital at or within cash flow. The priorities
Conclusion
for investing this capital are first to test
And our commitment to being a great
place to work for our employees and
to contribute to the communities where
the potential of the emerging resource
As I mentioned earlier, I believe St. Mary
we live and work has never been more
plays to which St. Mary has exposure,
is stronger today than a year ago, and I
impor tant than in these difficult
and then invest capital in development
also believe that St. Mary will exit 2009
economic times.
projects with the highest economic
a stronger company than it is today. We
returns. With respect to the Company’s
have the ability to be highly flexible
St. Mar y is well positioned as it
resource play testing, we expect to drill
throughout 2009 — we can ramp up our
“Makes the Turn” into its second
operated wells in the Haynesville, Eagle
activity should conditions improve and
centur y. I look for ward to our future
Ford, and Marcellus shales in 2009.
we have the ability to slow down should
success and the associated growth
We have the ability to capture 50,000,
circumstances warrant. Our strong
in value for our stockholders.
210,000, and 43,000 net acres,
balance sheet gives us the dr y powder
respectively, in these plays.
to weather a downturn in commodity
March 10, 2009
We have deferred many of our develop-
should any unique acquisition targets
ment programs due to our view that costs
present themselves. We have some
to drill and complete wells will continue
solid development projects “in the bag”
prices and the ability to be opportunistic
to come down throughout 2009. Given
that can be developed in more favorable
Anthony J. Best
conditions. Lastly, our exposure to
Chief Executive Officer and President
the emerging resource plays in the
9
O U R E M P L O Y E E S
David Abegg • Kelly Abelmann •Tonya Adam • Denise Adams • Judy Adamsson • Jerr y Alexander • Tina Allen • Beverly Allgood • Billy Allmon • Melissa Andreani
Leslie Andrus • Carmen Angel • Joanne Anschutz • Debra Arroyo • Nathan Aucoin • Penny Ayers • Robert Bachman • Thomas Bagley • Justin Balkenbush • Michael Barbula
James Barnes • Kenneth Barnett • Jessica Baros • Tracy Bar tholomew • Jayme Bauman • Richard Baumann • Cindy Beatty • Rebecca Beaumier • Laura Beers
William Bentley • Diane Bents • Sandra Beresford • Frank Berry • Tony Best • Gary Bjerke • Kerry Bjorgen • Kory Bjorgen • Jordan Blackburn • Brooke Blackburn
Carla Blair • Louis Bradshaw • Mark Brannum • Gary Breitling • Judith Brewer • Linda Brewer • Jill Briesch • Stephen Briggs • Chasity Broadbrooks • Marianne Brocklebank
Cynthia Brogren • Gregory Brooks • Brandy Brooks • Nancy Brostuen • Laurel Brown • Leah Brumlow • Kristyn Bryan • Michael Bryant • Nathan Buchanan • Janet Buckley
Willis Buckley • Rita Buress • Jacqueline Burgesser • Susan Burk • Karen Burns • Katharen Burns • Linda Burrow • Naomi Burrow • Sherrie Burrow • Angel Bustamante
Paul Button • David Caceres • Debra Calhoun • Diane Cameron • Guadalupe Campos • Bruce Carathers • Ashley Cardenas • Roel Cardona • William Carignan
Randall Carlson • Nicholas Carlson • Kimberly Carr • William Carroll • Bartow Carroll • Vicki Cartledge • Debra Casey • Michael Cash • Megan Casselman • Paul Causey
Donna Caviness • Joanne Celentano • Melchor Cervantez • Melanie Chaffin • Jarrod Charlifue • Karen Chism • Frank Chomout • Cynthia Christianson • Avis Clark
Donald Clark • Rachelle Clemons • Carole Clingman • Mark Cody • Brent Collins • Anthony Cook • Alan Cooke • Jeffrey Cragwick • Bruce Crain • Danielle Crane
Aaron Cross • Kerry Culbertson • John Curley • Thomas Dahill • Melissa Dailey • Ryan Davis • Marilee Day • Carla Deangelis • Mark Degenhart • Janice DeLuzio
Revah DeMar • Michael Detrick • Jimmy Dew • Ryan Dial • Ricardo Diaz • Robin Diedrich • Debra Dinner • Linda Ditsworth • Jamie Dittman • William Dodd • John Dodds
Clare Domingue • Jamie Donovan • Carolyn Doolittle • Kevin Dorrington • Cal Dowhaniuk • William Downs • Karla Drange • Coni Dreyer • David Dubiel • Mark Dunham
Kristal Duval • Mark Eck • James Edwards • Tanner Egan • Patricia Ellington • Dustin Ellis • Harvey Ellis • Robert Elrod • Teri Elrod • James Erlandson • Jason Faiman
Thomas Ferguson • Serena Ferrin • Gary Fifer • Carla Fishback • David Flores • Margarito Flores • Rosendo Flores • David Flurry • Tammy Fode • Brantley Forgy • Dana Fox
Julie Fragnito • Dale Fredrickson • George Friesen • Paula Frisbee • Eric Fugate • Jenice Fugere • Jeffrey Fulco • Alfredo Galan • Sandra Garbiso • Shannon Garcie
Albert Garza • Carlos Garza • Gayle Gaul • Jessica Gaul • Bob Geries • Karun Ghimire • Mac Gilger • Jesse Gilman • Aric Glasser • Vicky Gonzales • Gazaan Gonzalez
Jennifer Gordon • Donna Grant • Julie Gray • Daniel Green • David Greene • Connie Greenlee • Logan Greer • Angela Gregerson • Thomas Grier • Lorena Griggs
Jack Griswold • Diane Grootenhaar • Dennis Guenther • Lisa Hagelstein • Gloria Hall • David Hall • Aaron Hancock • Mike Haney • Dale Hanks • Angela Hanson
Vera Harris • Mary Harris • Betty Hartung • Eric Hauwert • Cheryl Head • William Hearne • Thomas Hedegaard • Larry Hedstrup • Daniel Heggem • Roxie Helstad
Andrew Hennes • Shawn Heringer • Jerardo Herrera • Connie Heston • Lorain Hicks • Gar th Hill • Donald Hill • Kevin Hillyard • Greg Hilton • Ezequiel Hinojosa
Mary Hirsch • Betty Hodge • Cory Hoffman • Brian Holcomb • Rebecca Houghton • Cornell House • Randy House • Lorraine Huck • Donna Huddleston • Christopher Hunter
Carrie Hunter • Brian Huzzey • Robert Jackson • Joey Jafek • Toni Jarrett • LaKesha Jeffrey • Bridgett Jenefor • Jette Jenks • Jenny Jensen • John Jensen • T Hutch Jobe
Sharon Johnson • Debra Johnson • Deanna Johnson • James Johnston • Lisa Johnston • Joel Jones • Debra Jones • Kyle Jordison • Gail Joy • Alley Juma • Brandon Junker
Valeri Kaae • Patrick Kadel • Toni Karlin • Sherry Karst • Benjamin Kennedy • Robert Kessel • Kevin Kindrick • Johnathan King • Jill Klein • John Kluz • Stephen Knapp
Kenneth Knott • Janice Knotts • Daniel Koehling • Brady Kolb • Rebecca Kolsky • Jon Krystinik • Alicia Kucharek • Renee Kucharek • Sarah Lacey • Heidi Lafleur • Hung Lai
Twyla Lance • Regina Lanier • Jason Lara • Barbara Larson • Paul Larson • Kathr yn Leathers • Mildred Leblanc • Timothy Lechner • Barr y Lee • James Legare
10
Our people are a strength for St. Mary and as part of
our business plan we incorporate a specific “People
Strategy” to leverage their skills and commitment.
We wish to acknowledge the employees who make
St. Mary Land & Exploration Company the successful
company that it is. Listed below are our employees
as of December 31, 2008.
Myron Leintz • Gregory Leyendecker • Gregory Little • David Lofton • Carl Lothringer • Ryan Lowden • David Lustig • Mary Ellen Lutey • Dean Lutey • Robert Lynn
Candace Lyon • Patrick Lytle • Robyn Maez • Jennifer Major • Luke Malsam • Sarah Mann • Laurie Marcotte • Nathan Markham • Jesse Martin • Joanna Martin
Victoria Martinez • Danielle Maruna • Thomas Mathis • Curtis Matthews • Catherine Mayo • Kimberly McArthur • Derek McFarlane • Joseph McFerran • Dana McGoveran
Michael McGoveran • Joshua McIver • Dustin McLean • Kevin McMaster • Charles McNaney • Lavonne McNeil • Jennifer McQueen • John Mears • Robbin Mekelburg
Leonardo Mendez • Charles Mercer • Virginia Minturn • Jamie Mitzo • Matthew Modjeski • Shane Mogensen • John Monark • Shane Moran • Carol Moreno • Staci Morgan
Paul Morrison • Thomas Morrow • Bruce Mortenson • Mark Mount • Mark Mueller • Donald Mueller • Jennifer Mueller • Teresa Muhic • Chad Mulliniks • Macy Mullins
Ruben Munoz • Rober t Nail • Billy Neal • Justin Nelson • Pamela Nelson • Rodney Nelson • Roger Nelson • Gail Newsum • Lehman Newton • Van-Tuyet Nguyen
Casey Nichols • Stephanie Nicolarsen • John Nightengale • Nicholas Norberg • Elmer Nordsven • Robert Norman • Breanne Oakley • Tolulope Ogundare • Gordon Olson
Michelle O'Neil • Dusty Orchard • Freddie Otis • Jay Ottoson • Brenda Oyloe • Billie Ann Pagliasotti • Michael Pantalone • Guadalupe Parham • Donna Parker
Randall Parpart • Kimberly Paulson • Rory Pendleton • Gregory Pennington • Eric Percy • Saturnino Perez • Timothy Perkins • Brandy Perry • Randy Pester • Randy Pharo
Julie Pike • Austin Placek • Nancy Pochatko • Anita Pollock • David Ponto • Paul Porter • Charles Porter • Wesley Portra • Susan Potts • Robert Prescott • Billy Preston
Barbara Prestrud • Sheryl Price • Loren Prigan • Bonnie Pritchett • Sandra Puettman • Stephen Pugh • David Purcell • Matthew Purchase • Wade Pursell • Emilio Quintero
Amanda Rambur • Raul Ramos • John Ramsey • Lanette Rasmusson • Patricia Rau • Sarah Ray • Carolyn Reagin • Susan Reams • Bryant Reasnor • Carl Reece
Jeff Reeves • David Regan • Roger Rehbein • Gayle Richardson • Don Riggs • Ward Rikala • Rogelio Rincon • Michael Roach • Shawn Roach • Rebecca Roark • Ari Robert
Carol Roberts • James Robertson • Christopher Robinson • Dawn Rohrs • Jon Ruby • Robin Ryder • Jonathan Sachen • Steve Sadler • Israel Salazar • Ricardo Saldana
Greg Salveson • Pat Salwey • Karin Sanford • Ronald Santi • Joseph Scar farotti • Benjamin Schalk • Michael Schanck • Carol Schellhouse • Dinah Schlecht
Dennis Schmidt • Ashley Schneider • Brenda Schohn • Beverly Schreiner • Jeffrey Schurbon • Douglas Selvius • Karla Semm • James Shaffer • Edward Shannon
Tiffany Sharp • Michael Shaw • Kelly Shield • Brennan Short • Deborah Siegmund • Lilly Simpson • Payton Simpson • Eric Skaalure • Jared Slade • Michael Slay
Benjamin Smith • Jayme Smith • Craig Smith • Sabrina Smith • Karla Snedigar • Keith Soine • Mark Solomon • Diana Souders • Brian Southern • Roy Spann, Jr
Victoria Sparks • Robert Srader • Mary St. Germain • Andrea St. Peter • Charles Stanford • John Steele • Paul Steffen • Robert Stillwell • Amber Stockdale • Diane Stokes
Luke Studer • Peggy Sukut • Laura Sutfin • Bradford Sutton • Kelly Sutton • Pamela Sweet • Elizabeth Sylvan • Janice Tabbert • Elizabeth Taruscio • John Taylor • Sherri
Thibodeaux • Benjamin Thogerson • Estelle Thomas • Braden Thompson • Linda Thompson • Dave Thompson • Larkin Thompson • Connie Thunem • Kerin Todaro
Joy Torgerson • Staci Tribelhorn • Andrew Urie • Joseph Van • David Van Brunt • Kirk Vanderbeek • Charlotte Vangsnes • Rhonda Vardeman • Paul Veatch • Kathleen Vitas
Shari Vitt • Margaret Vogl • Kevin Wachtler • Charles Waelde • Kelli Wahrmund • Edwin Wakefield • Wilford Walker • Rhett Wallace • Vicky Wallace • Jamie Ward
Angela Watson • Galen Watt • Ann Watters • Lynette Watts • Cynthia Wedge • Charles Wedlund • Randall Weeks • Jon Weible • Daniel Wells • Marlon Wells • Dianna West
Margaret Whaley • Kari Wheeler • David Whitcomb • Lonnie Whitson • Shane Wiggins • Brian Wilbanks • Linda Wilkins • Jane Williams • Brandon Williams • John Williams
Kathy Willis • Jerry Willman • Stanley Wilson • Kelsey Wilson • Melissa Wittler • Terrence Wolf • Traci Woller • Celesta Worley • Roger Worrell • Jay Wright • Karin Writer
Brenda Young • William Zacek • Nate Zeigler • Clayton Ziler • Dennis Zubieta • Frances Zwick
11
EXECUTIVE
OFFICERS
INFORMATION ABOUT FORWARD
LOOKING STATEMENTS
Anthony J. Best
Chief Executive Officer and President
Javan D. Ottoson
Executive Vice President and
Chief Operating Officer
A. Wade Pursell
Executive Vice President and
Chief Financial Officer
Mark D. Mueller
Senior Vice President and
Regional Manager
Milam Randolph Pharo
Senior Vice President and
General Counsel
Paul M. Veatch
Senior Vice President and
Regional Manager
Stephen C. Pugh
Senior Vice President and
Regional Manager
Gregory T. Leyendecker
Vice President – Regional Manager
John R. Monark
Vice President – Human Resources
Lehman E. Newton, III
Vice President – Regional Manager
Kenneth J. Knott
Vice President – Business Development
and Land and Assistant Secretary
David J. Whitcomb
Vice President – Marketing
Dennis J. Zubieta
Vice President – Engineering
and Evaluation
Mark T. Solomon
Controller
This annual repor t contains for ward looking
statements within the meaning of securities laws,
including forecasts and projections for future
periods. The words “will,” “believe,” “anticipate,”
“budget,” “intend,” “estimate,” “forecast,” “plan,”
“expect,” and similar expressions are intended
to identify for ward looking statements. These
statements involve known and unknown risks,
which may cause St. Mary’s actual results to differ
materially from results expressed or implied by the
forward looking statements. These risks include
such factors as discussed in the “Risk Factors”
and “Cautionary Information about Forward Looking
Statements” sections of the accompanying 2008
Annual Report on Form 10-K. Although St. Mary
may from time to time voluntarily update its prior
for ward looking statements, it disclaims any
commitment to do so except as required by
securities laws.
GLOSSARY
Finding cost from drilling, excluding price and
per formance revisions. Expressed in dollars per
MCFE. This metric is calculated as a numerator
defined as the sum of development costs and
exploration costs divided by a denominator defined
as the sum of discoveries and extensions and
infill reser ves in an existing proved field during
the same period.
Reserve replacement from drilling, excluding
price and performance revisions. Calculated as a
numerator defined as the sum of discoveries and
extensions and infill reserves in an existing proved
field divided by production for the same period.
This is believed to be a useful non-GAAP measure
that is widely utilized within the exploration and
production industry as well as by investors. It is
an easily calculable number and is representative
of the relative success a company is having in
replacing its production through drilling activities.
For additional information about these and
similar metrics, see the “Glossary” section of the
accompanying 2008 Annual Report on Form 10-K.
DIRECTORS
Barbara M. Baumann (1),(4)
Denver, Colorado
President
Cross Creek Energy Corporation
Anthony J. Best (1)
Denver, Colorado
Chief Executive Officer and President
St. Mary Land & Exploration Company
Larry W. Bickle (2),(4)
Houston, Texas
Private Investor
William J. Gardiner (1),(3)
Houston, Texas
Vice President and Chief Financial Officer
King Ranch Inc.
Mark A. Hellerstein (1)
Denver, Colorado
Chairman and
Former Chief Executive Officer
St. Mary Land & Exploration Company
Julio M. Quintana (3)
Houston, Texas
President and Chief Executive Officer
TESCO Corporation
John M. Seidl (2),(3)
Houston, Texas
Chairman and Chief Executive Officer
EnviroFuels, LLC
William D. Sullivan (2),(4)
The Woodlands, Texas
Former Executive Vice President,
Exploration and Production
Anadarko Petroleum Corporation
(1) Executive Committee
(2) Nominating and Corporate
Governance Committee
(3) Audit Committee
(4) Compensation Committee
12
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2008
or
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission file number 001-31539
ST. MARY LAND & EXPLORATION 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.)
1776 Lincoln Street, Suite 700, 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 No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K.
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.
Large accelerated filer
Non-accelerated filer (Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
Accelerated filer
Smaller reporting company
The aggregate market value of the 61,794,217 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale
price of the common stock on June 30, 2008, the last business day of the registrant’s most recently completed second fiscal quarter, for
$64.64 per share as reported on the New York Stock Exchange was $3,994,378,187. 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
Company 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 17, 2009, the registrant had 62,305,557 shares of common stock outstanding, which is net of 176,987 treasury shares held
by the Company.
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 2009 annual meeting of stockholders to be filed within 120 days after December 31, 2008.
DOCUMENTS INCORPORATED BY REFERENCE
ITEM
TABLE OF CONTENTS
PART I
ITEMS 1. and 2. BUSINESS and PROPERTIES
General
Strategy
Significant Developments in 2008
Outlook for 2009
Assets
Reserves
Production
Productive Wells
Drilling Activity
Acreage
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 Natural Gas Terms
ITEM 1A.
ITEM 1B.
ITEM 3.
ITEM 4.
RISK FACTORS
UNRESOLVED STAFF COMMENTS
LEGAL PROCEEDINGS
SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS
ITEM 4A.
EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 5.
ITEM 6.
ITEM 7.
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
Overview of Liquidity and Capital Resources
Critical Accounting Policies and Estimates
Additional Comparative Data in Tabular Format
Comparison of Financial Results and Trends between
2008 and 2007
Comparison of Financial Results and Trends between
2007 and 2006
Other Liquidity and Capital Resources Information
Accounting Matters
Environmental
PAGE
1
1
1
1
4
4
8
10
10
11
12
12
12
13
13
13
13
15
16
17
21
31
31
31
32
35
38
40
40
51
62
65
66
69
72
72
72
ITEM
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
TABLE OF CONTENTS
(Continued)
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK (included with 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
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
PAGE
73
73
73
73
76
76
76
76
76
77
77
PART I
When we use the terms ―St. Mary,‖ ―the Company,‖ ―we,‖ ―us,‖ or ―our,‖ we are referring to St. Mary
Land & Exploration Company and its subsidiaries, unless the context otherwise requires. We have included
technical terms important to an understanding of our business under ―Glossary of Oil and Natural Gas Terms.‖
Throughout this document we make statements that are 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 oil and gas company engaged in the exploration, exploitation, development,
acquisition, and production of natural gas and crude oil in North America. We were founded in 1908 and
incorporated in Delaware in 1915. Our initial public offering of common stock took place in December 1992.
The common stock of the Company trades on the New York Stock Exchange under the ticker ―SM.‖
Our principal offices are located at 1776 Lincoln Street, Suite 700, Denver, Colorado 80203, and our
telephone number is (303) 861-8140.
Strategy
Our mission is to deliver outstanding net asset value per share growth to our investors via attractive oil
and gas investments. Historically, a key part of meeting the goal of building stockholder value was the successful
execution and integration of niche acquisitions at attractive costs. Recently we shifted the emphasis of our efforts
to focus on the exploration for and development of onshore resource plays in North America. This shift was due
to the fact that, as we grew, the universe of potential niche acquisition targets became smaller and less impactful
to the growth of the Company. Additionally, we believe that we will be able to create more long-term value for
our shareholders by building an asset base that is more predictable and does not rely solely on acquisitions to fuel
its growth. Our strategy is based on the following points:
Acquire significant leasehold positions in new and emerging resource plays
Leverage our core competencies in drilling and completions, as well as acquisitions
Exploit our significant legacy asset production and optimize our asset base through divestitures of
non-core assets when appropriate
Maintain a strong balance sheet while funding the growth of the enterprise.
Significant Developments in 2008
Broad Economic Downturn and Impacts on Capital Markets and Commodity Prices. During 2008
the global economy experienced a significant downturn. The crisis began over concerns related to the
U.S. financial system and quickly grew to impact a wide range of industries. There were two
significant ramifications to the exploration and production industry as the economy continued to
deteriorate. The first was that capital markets essentially froze. Equity, debt, and credit markets shut
down. We were able to weather this initial shock as a result of our strong liquidity position and
relatively limited capital commitments. The second impact to the industry was that fear of global
recession resulted in a significant decline in oil and gas prices. We have been able to cope with the
downturn in prices as a result of our ability to quickly scale down our activity and keep our capital
investments within cash flow. Our existing commodity hedge position provided a further backstop as
commodity prices continued to decline. We believe the environment in 2009 will continue to be
challenging with respect to financing and commodity pricing.
1
Significant Volatility in Commodity Prices. As mentioned above, 2008 saw the exploration and
production sector impacted by significant volatility in the prices for crude oil and natural gas. Our
operations and financial condition are significantly impacted by these prices. Our crude oil is sold on
contracts that pay us the average of posted prices for the period in which the crude oil is sold. The
spot price for NYMEX crude oil in 2008 ranged from a high of $145.29 per barrel in early July to a
low of $31.41 per barrel in late December. The average spot price for oil during the year was $99.92
per barrel. The volatility in oil prices during the year was a result of geopolitical unrest in various
producing regions overseas as well as domestic concerns about refinery utilization and petroleum
product inventories pushing prices up during the first half of the year. Global demand destruction
drove prices down as the economy weakened in the second half of 2008.
We sell the majority of our natural gas on contracts that are based on first of the month (also
frequently referred to as bid week) index pricing. The Inside FERC bid week price for Henry Hub, a
widely used industry measuring point, averaged $9.04 per MMBtu in 2008, with a high of $13.11 per
MMBtu in July and a low of $6.47 per MMBtu in November. Natural gas prices came under pressure
in the second half of the year as a result of lower domestic product demand that was caused by the
weakening economy and concerns over excess supply of natural gas due to high levels of drilling
activity. Some of the regional markets where we sell gas have seen increased downward pressures on
price as a result of high levels of activity in the region and either a lack of pipeline takeaway capacity
or local demand. This has been most pronounced in our Mid-Continent and Rocky Mountain regions.
Decrease in Year-End Reserves. Due in large part to the price declines in the second half of 2008
described above, proved reserves decreased 20 percent to 865.5 BCFE at December 31, 2008, from
1,086.5 BCFE at December 31, 2007. We added 170.1 BCFE from our drilling program and 29.1
BCFE from acquisitions during the year. During the year, 61.4 BCFE were sold in divestitures,
primarily in the Rocky Mountain and Mid-Continent regions. We had a negative revision of 244.2
BCFE that consisted of 44.5 BCFE in downward performance revisions and a downward pricing
revision of 199.7 BCFE due primarily to meaningfully lower commodity prices at the end of 2008.
The prices used for the 2008 year-end reserves decreased significantly from a year earlier. Oil prices
declined 54 percent from $95.98 per barrel to $44.60 per barrel while natural gas prices dropped 16
percent from $6.80 per MMBtu to $5.71 per MMBtu. Over half of the pricing revisions occurred in
the oil-weighted Rocky Mountain region, which saw its proved reserves adversely impacted by low
prices and wider differentials at the end of 2008. We also saw meaningful price and performance
revisions in the Gulf Coast region related primarily to our Olmos shallow gas properties in South
Texas. A large decline in the natural gas liquid fractionation spread year over year resulted in a
significantly lower price for natural gas in the determination of proved reserves for the region at year-
end. The performance revision is due to poorer reservoir performance then we had initially expected.
The reservoir is more compartmentalized then originally assumed and we have seen lower reserve
outcomes while attempting to infill parts of the field.
Impairment of Proved Properties. The low prices at year-end for oil and gas and the decrease in
proved reserves described above both contributed to a pre-tax non-cash impairment of proved
properties in the amount of $302.2 million in 2008. There was no impairment of proved properties in
2007. Approximately $154.0 million of the 2008 impairment was related to assets in South Texas
that were acquired in 2007. We also saw an impairment associated with proved properties in the Gulf
of Mexico, the Greater Green River Basin in Wyoming, and our coalbed methane project at Hanging
Woman Basin.
Abandonment and Impairment of Unproved Properties. During the year, we abandoned or impaired
$39.0 million related to unproved properties. Approximately $13.4 million was related to acreage to
which we had assigned value in 2007 acquisitions targeting the Olmos shallow gas. The remaining
write-offs were related to acreage we believe we will not be able to hold due to current limited capital
availability and to acreage that we do not believe is prospective.
2
Drilling Results. Reserve additions of 170.1 BCFE from drilling activities were driven primarily by
results in the Mid-Continent and Permian Basin regions, with those regions contributing 43 percent
and 22 percent, respectively, to our drilling additions. The ArkLaTex and Rocky Mountain regions
contributed 14 percent and 15 percent, respectively, to our drilling additions. The Mid-Continent
region had a very strong year. Additions in the Mid-Continent region were derived principally by
successful drilling by us and our operating partners in the horizontal Woodford shale formation in the
Arkoma Basin, as well as positive results from a program targeting the deep Springer interval in the
Anadarko Basin. In the Permian region, additions were the result of successful drilling in our
Wolfberry tight oil program. The ArkLaTex region added reserves from successful Cotton Valley
formation development drilling by us at Carthage Field and by an operating partner at Elm Grove
Field. Coalbed methane projects at Atlantic Rim and in Hanging Woman Basin accounted for the
majority of drilling additions in the Rocky Mountain Region.
Potential Resource Play Additions. In 2008 we established meaningful positions in several new
potential resource plays which emerged in the exploration and development industry, principally the
Haynesville shale, the Eagle Ford shale, and the Marcellus shale. Although no proved reserves have
been booked in any of these emerging resource plays at the end of 2008, each of these plays could
provide for significant future growth in reserves and production if development proves successful.
The Haynesville shale emerged early in 2008 in North Louisiana and East Texas and quickly became
the hottest resource play in the country. As a result of our previous Cotton Valley and James Lime
activity and the acquisition of additional properties in Panola County, Texas in early 2008, we now
have approximately 50,000 net acres that could be prospective for the Haynesville shale. Our Eagle
Ford shale position in the Maverick Basin in South Texas was seeded through two acquisitions in
2007 and then built through leasing efforts and a joint venture over the course of 2008. If we earn all
of the acreage available under the joint venture, St. Mary will control approximately 210,000 net
acres in this play. Lastly, late in 2008 we entered into two arrangements that allow us to earn up to
43,000 net acres in the Marcellus shale in north central Pennsylvania.
Divestiture of Non-Strategic Properties. In 2008 we sold a number of non-strategic properties in an
effort to optimize our portfolio. Prior to this year we had been a limited seller of assets. The primary
objectives of these sales were to dispose of properties with limited upside drilling potential and to
focus our employees on the core strategic assets that will help the Company grow in the future.
During 2008 we sold 61.4 BCFE of reserves, the vast majority of which were proved producing. The
sales occurred throughout the year and we received $178.9 million in proceeds from these sales. The
properties we sold were located primarily in the Rocky Mountain and Mid-Continent regions.
Senior Management Change. On March 21, 2008, David Honeyfield, Senior Vice President - Chief
Financial Officer and Secretary, resigned as an officer of St. Mary, to pursue an opportunity in an
unrelated industry. On September 8, 2008, A. Wade Pursell joined St. Mary as Executive Vice
President and Chief Financial Officer. Mr. Pursell was employed at Helix Energy Solutions as Chief
Financial Officer from 2000 until mid-2008 and as Vice President – Finance and Treasurer from 1997
through 2000. Prior to that, he spent nine years in the audit practice of Arthur Andersen in positions
of increasing responsibility.
Repurchase of Common Stock. During the first quarter of 2008, we repurchased a total of 2,135,600
shares of common stock in the open market for a weighted-average price of $36.13 per share,
including commissions. At the time we repurchased our shares, we entered into hedges for a
commensurate amount of our production that was represented by the share repurchase in order to lock
in the discounted price at which we believed our shares were trading. As of the date of this filing, we
are authorized by the Board to repurchase 3,072,184 additional shares under our share repurchase
program. The shares may be repurchased from time to time in open market transactions or in
privately negotiated transactions, subject to market conditions and other factors, including certain
provisions of our existing credit facility agreement and compliance with securities laws. Stock
repurchases may be funded with existing cash balances, internal cash flow, and/or borrowings under
3
the credit facility. Given current economic conditions, we do not currently anticipate that in the near
term we will be utilizing our liquidity and capital resources for capital investment to conduct stock
repurchases.
Outlook for 2009
As of the date of this report, indications are that the credit market is very tight and the capital markets are
still not widely accessible or at a minimum very expensive. Furthermore, commodity prices, both on a spot and
futures basis, have continued to be under downward pressure as a result of the continuing deterioration of the
economy. Given the uncertainty surrounding our ability to access the capital markets and the current low
commodity price environment, we are proceeding cautiously in 2009. We continue to maintain our financial and
operating flexibility, so we can accelerate activity should industry conditions improve or decelerate activity
should circumstances warrant. We have limited exposure to expiring leasehold and few long-term commitments
for rigs which allow us to slow down quickly if needed. Rather than set a specific capital expenditures budget for
2009, our plan is to invest capital at or within cash flows for the year. We have deliberately deferred development
projects into the second half of 2009, and perhaps beyond, to improve returns on invested capital with either
improved commodity prices and/or lower drilling and completion costs. Our focus in 2009 will be to test the
potential of three emerging resource plays to which we have exposure – the Haynesville shale in our ArkLaTex
region, the Eagle Ford shale in South Texas, and the Marcellus shale in Pennsylvania.
Our financial position entering 2009 is solid; we have no near-term maturities of debt, limited long-term
commitments, and significant availability under our current revolving credit facility. This credit facility expires in
early April of 2010, and we are currently in discussions with commercial lenders to replace it with a new facility.
We expect to have the new facility in place by the end of the first half of 2009. Our intent is to increase the
amount of commitments available to us in the new revolver. We believe that given current industry and macro
economic conditions, we could see some unique opportunities come to the market and we want to have the
financial capacity available to pursue those opportunities.
Assets
As of December 31, 2008, we had estimated proved reserves of 51.4 MMBbl of oil and 557.4 Bcf of
natural gas. Prices in effect on December 31, 2008, used to estimate proved reserves were $44.60 per barrel of oil
and $5.71 per MMBtu of gas, which were down 54 percent and 16 percent, respectively, from prices used to
estimate proved reserves as of December 31, 2007. On an equivalent basis, our proved reserves were 865.5
BCFE as of December 31, 2008, a decrease of 20 percent from 1,086.5 BCFE at the end of the prior year. The
decrease in proved reserves during the year was related to significant pricing and sizable performance revisions
and to property sales that occurred throughout the year, offset to some extent by acquisitions and additions from
drilling activity. On an equivalent basis, 83 percent of our proved reserves were classified as proved developed as
of year-end. Total proved oil and gas reserves had a before income tax PV-10 value of $1.3 billion and a
standardized measure value of $1.1 billion including the effect of income taxes. A reconciliation between these
two amounts is shown under the Reserves section in Part I, Items 1 and 2 of this report. During 2008 our average
daily production was 204.7 MMcf of gas and 18.1 MBbl of oil, for an average equivalent production rate of
313.1 MMCFE per day, which is a new annual record for us.
In 2008 we incurred costs of $856.7 million for drilling and exploration activities and acquisitions. This
was seven percent lower than the $926.1 million incurred in 2007. During 2008 we incurred costs of $678.8
million for exploration and development activities which compares to $702.5 million incurred in 2007. In 2008
we incurred costs of $126.4 million for leasehold, including costs attributable to unproved properties in
acquisitions compared to $61.9 million in 2007. The increase in leasehold incurred costs is a result of our shift in
strategy to a focus on acquiring productive leasehold earlier in its life cycle and benefiting from improved returns
of organic development. We incurred costs of $51.6 million for the acquisition of proved properties in 2008,
which is 68 percent less than the $161.7 million incurred in 2007.
4
Our operations are currently concentrated in five core operating areas in the United States. The following
table summarizes the production, proved reserves and PV-10 value of our core operating areas as of
December 31, 2008.
ArkLaTex
Mid-
Continent
Gulf
Coast
Permian
Rocky
Mountain
Total (1)
2008 Proved Reserves
Oil (MMBbl)
Gas (Bcf)
Equivalents (BCFE)
Relative percentage
Proved Developed %
0.5
167.1
170.0
20%
67%
1.1
227.8
234.5
27%
79%
0.7
39.4
43.8
5%
92%
19.8
37.1
155.9
18%
79%
29.2
86.0
261.4
30%
97%
51.4
557.4
865.5
100%
83%
PV-10 Value (in millions)
Relative percentage
$221.4
18%
$379.2
30%
$47.9
4%
$284.6
22%
$332.2
26%
$1,265.4
100%
2008 Production
Oil (MMBbl)
Gas (Bcf)
Equivalent (BCFE)
Avg. Daily Equivalents
(MMCFE/d)
Relative percentage
(1) Totals may not add due to rounding
0.2
17.6
18.6
50.7
16%
0.4
30.8
33.0
90.2
29%
0.2
12.9
14.3
39.0
12%
1.8
3.3
13.8
37.8
12%
4.1
10.3
34.9
95.4
31%
6.6
74.9
114.6
313.1
100%
ArkLaTex Region. St. Mary’s operations in the ArkLaTex region are managed from our office in
Shreveport, Louisiana. The ArkLaTex region was the first operating office for the Company, originating from an
acquisition in 1992. For years the activities of this region focused on the tight sandstone Cotton Valley, James
Lime, and Travis Peak formations in the region. In 2008 the Haynesville shale emerged as a new potential
resource play in East Texas and North Louisiana.
The ArkLaTex region incurred costs of $218.4 million in 2008 for exploration, development, and
acquisition activities, which is 46 percent higher than the $149.8 million spent in 2007. The primary driver of this
increase relates to acquisitions of operated Cotton Valley properties in East Texas for approximately $60 million.
St. Mary’s operated activity in the ArkLaTex region was primarily focused on drilling horizontal Cotton Valley
and James Lime wells. We had two operated rigs running throughout most of the year. In addition, we
participated in partner-operated development at Elm Grove. The region’s 2008 production increased 34 percent to
18.6 BCFE. Our 2008 year-end proved reserves were 170.0 BCFE, essentially flat with 2007 year-end proved
reserves of 170.1 BCFE. The slight decrease in proved reserves is the result of 18.6 BCFE of production and 31.3
BCFE of downward performance and pricing revisions negating 51.9 BCFE of drilling additions and acquisitions
that we had during the year. At year-end 2008 we have no proved reserves recorded for our potential in the
Haynesville shale.
The Elm Grove Field is the highest value field in the ArkLaTex region at year-end 2008, with proved
reserves of 77.1 BCFE and PV-10 value of $87.1 million. Elm Grove comprises roughly 39 percent of the
region’s PV-10 value and approximately seven percent of St. Mary’s entire PV-10 value. We own interests in
over 480 producing wells in the field and believe many of those wells have future uphole recompletion potential.
Our working interest in the field is as high as 37 percent; higher working interests are located in the southern
portion of the acreage where recent activity has been occurring. Reserves in this field are primarily natural gas.
Our plans for 2009 in the ArkLaTex region, subject to capital availability, include drilling several
operated horizontal Haynesville shale wells to test the resource potential of this emerging shale play on portions
of the 50,000 net acres we control that could be prospective for this formation. We also have plans to drill several
James Lime wells during 2009. Currently, we have no plans to drill any operated wells in the Cotton Valley
5
formation in 2009. We will participate with an operating partner in the drilling of Cotton Valley wells at Elm
Grove, as well as recompletions of the uphole Hosston formation.
Mid-Continent Region. St. Mary has been active in the Mid-Continent region since 1973. Operations for
the region are managed by our office in Tulsa, Oklahoma. We have been active in the Anadarko Basin of western
Oklahoma since our entry into the region. In recent years we have begun operating in the Arkoma Basin in
eastern Oklahoma where the current focus is on horizontal development of the Woodford shale. The Mid-
Continent region will also oversee our Marcellus shale activity in north central Pennsylvania.
In 2008 we incurred costs of $162.0 million in the Mid-Continent region for exploration, development,
and acquisition activity, which is 13 percent less than the $185.7 million deployed in 2007. Approximately
$31.0 million was incurred for non-producing leasehold in 2008, the bulk of which consists of upfront payments
related to our entry into the Marcellus shale. Our Mid-Continent activity during 2008 consisted of the continued
successful development of our Woodford shale assets in the Arkoma Basin and continued exploration success in
the Anadarko Basin drilling deep Springer wells. Mid-Continent production in 2008 was 33.0 BCFE, a decrease
of three percent from the 34.0 BCFE produced in 2007. The decrease in production is primarily attributable to the
divestment of non-core properties in January 2008. Excluding the impact of the sale of these assets, the Mid-
Continent region would have grown 0.5 BCFE, or 2%, from 2007 to 2008. Proved reserves at the end of 2008
were 234.4 BCFE, an increase of 16 percent from the 201.3 BCFE report for the prior year. The increase in
proved reserves was due to the performance of our horizontal Woodford shale program, where we have been
successful at adding and converting reserves, and the successful deep Springer drilling program in the Anadarko
Basin.
The Centrahoma Field in the Arkoma Basin is the highest value field in the Mid-Continent region with
proved reserves of 102.1 BCFE and a PV-10 value of $108.8 million. This field comprises 44 percent of the
region’s proved reserves and 29 percent of the region’s PV-10 value. At year-end, we have over 130 producing
wells in the field. We believe our acreage at year-end has approximately 30 proved undeveloped drilling
locations and numerous unproved drilling locations that have Woodford shale potential. Additionally, we believe
that there is future uphole development potential in the Cromwell and Wapanucka formations.
Our plans in the Mid-Continent region for 2009 will involve conducting our initial tests of the Marcellus
shale, where we currently plan to drill two operated wells to earn and test our acreage position. Additionally, we
plan to continue our successful drilling programs in the horizontal Woodford and deep Springer.
Gulf Coast Region. St. Mary’s presence in south Louisiana dates to the early 1900s when our founders
acquired our namesake property in St. Mary Parish, Louisiana abutting the Gulf of Mexico. These 24,914 acres
of fee land yielded $15.5 million of oil and gas royalty revenue in 2008. Our Gulf Coast regional presence
expanded as a result of the acquisition of King Ranch Energy, Inc. in 1999. In 2007, we made two acquisitions in
the Maverick Basin in South Texas that targeted Olmos shallow gas assets in South Texas and provided an entry
into this multi-pay basin. In 2008, we began testing the potential of two of the deeper horizons in the basin, the
Pearsall and Eagle Ford shales. The Gulf Coast region is managed from our office in Houston, Texas.
Our capital expenditures for exploration, development, and acquisition activity in the Gulf Coast region
decreased significantly from $278.5 million in 2007 to $120.9 million in 2008. The amount for 2007 includes
$178.2 million for the two acquisitions we made in the Maverick Basin. During 2008 we integrated these
acquired assets and continued developing the Olmos shallow gas assets. We also began developing an
understanding of the geology related to two formations that lie below the Olmos in the Maverick Basin - the Eagle
Ford and Pearsall shales. Results from the Olmos development did not meet our expectations, and midway
through 2008 we stopped development to conduct a technical review. While parts of the technical review are still
underway, the initial results have cast doubt on the viability of the Olmos development on the scale we originally
contemplated at the time these acquisitions were made. These findings, combined with lower natural gas prices at
year-end 2008, resulted in a meaningful downward proved reserve revision and a significant impairment of
proved properties and undeveloped leasehold at the end of 2008. While our results from the Olmos program were
disappointing, our activities targeting the deeper formations in the basin have been promising. We participated
during the year in a joint venture with two other exploration and production companies that allows us to earn
6
acreage in an area of the basin that has potential for both the Eagle Ford and Pearsall formations. We have been
encouraged by the early results of the four test wells drilled in the joint venture and have committed to the second
phase of that program. Concurrent with our joint venture activity, we began leasing acreage in 2008 in parts of
the basin that we believe will be prospective for the Eagle Ford shale. Recent offset activity targeting the Eagle
Ford shale is encouraging. We currently have exposure to approximately 210,000 and 160,000 net acres in the
Eagle Ford and Pearsall shales, respectively, assuming that we meet all obligations to earn the acreage.
While the focus of the region is on onshore resource plays, we did have some meaningful activity related
to Gulf Coast and Gulf of Mexico properties in 2008. During Hurricane Ike, our last operated production
platform in the Gulf of Mexico, Vermilion 281, was toppled and our production facilities in Galveston Bay were
damaged. We are in the process of assessing and remediating the damage related to the Vermilion 281 platform.
The damaged properties at Galveston Bay have been repaired and were brought back online in late 2008. The
estimated remediation costs for all of our assets damaged during Hurricane Ike are believed to exceed the
maximum insurance policy limit we have for this event by approximately $7 million. The partner-operated
intermediate deepwater Pegasus project came on production late in 2008. This project was the last of the
commitments we had in the Gulf of Mexico.
Production for the Gulf Coast region in 2008 was 14.3 BCFE, an increase of 39 percent from the
10.3 BCFE produced in 2007. The increase in production year over year is primarily attributable to a full year of
contribution from the South Texas properties acquired in 2007 along with first production from two discovery
wells brought on-line early in the year. Proved reserves at the end of 2008 were 43.8 BCFE, a decrease of 63
percent from the 116.8 BCFE reported in the prior year. The significant reduction in proved reserves is primarily
the result of negative performance and pricing revisions related to the Olmos shallow gas assets described above.
Despite the difficulties with the Olmos program, the properties associated with the Rockford acquisition
in South Texas in 2007 remain the most significant assets in the Gulf Coast region. There were 306 producing
wells associated with this acquisition as of year-end. At December 31, 2008, the Rockford assets had a PV-10
value of $23.9 million with 25.7 BCFE of proved reserves, which represent 50 percent and 59 percent of the
regional total for those respective metrics.
Our plans for 2009 in the Gulf Coast region focus exclusively on the Eagle Ford shale. We plan to
participate as a non-operating partner in four wells targeting this formation. Additionally, we plan to drill four
operated Eagle Ford wells on acreage outside that joint venture. We will continue to look for opportunities to
expand our leasehold position in the Maverick Basin in 2009.
Permian Basin Region. The Permian Basin area covers a significant portion of western Texas and
eastern New Mexico and is one of the major producing basins in the United States. Our holdings in the Permian
Basin began with a series of property acquisitions in 1996. In December 2006 we made a $240.6 million
acquisition of predominately oil properties in our Sweetie Peck project area. To manage the significant increase
in operated properties associated with the Sweetie Peck acquisition, we opened a regional office in Midland,
Texas in February 2007.
We incurred costs of $163.2 million in the region in 2008 compared to $135.1 million in 2007. The
majority of this capital was deployed to develop projects in the Wolfberry tight oil play, which targets the stacked
carbonate Wolfcamp and Spraberry formations found in the basin. We participated in two substantial Wolfberry
programs during 2008 – our operated Sweetie Peck program and the outside operated program at Halff East. We
began testing 40-acre infill locations in 2008, and the results to date indicate that these wells are performing
comparable to wells drilled on 80-acre spacing. This has the potential to allow for meaningful future proved
reserve additions. Production in the region increased 29 percent over the prior year, from 10.7 BCFE in 2007 to
13.8 BCFE in 2008. Proved reserves as of the end of 2008 were 155.9 BCFE, which is an increase of one percent
from 2007 year-end reserves of 154.7 BCFE. In spite of our generally successful drilling program in the region
during 2008, year-end oil prices used to determine our proved reserves negatively impacted our reported proved
reserves. We saw 17.8 BCFE in negative price revisions as of December 31, 2008.
7
As of the end of December 2008, the Sweetie Peck assets in the Permian Basin represented a PV-10 value
of $164.2 million with 91.8 BCFE of proved reserves. This accounts for approximately 13 percent of St. Mary’s
entire PV-10 value. The Sweetie Peck asset consisted of 153 producing wells and approximately 40 proved
undeveloped drilling locations as of the end of 2008. Additionally, we believe that we have a meaningful number
of unproved drilling locations.
As a result of the dramatic pull back in oil prices over the second half of 2008 and into 2009, we will have
a significantly lower activity level in 2009 in the Permian region. Given our current assumptions, we plan to drill
five operated wells at Sweetie Peck and participate only as required to hold critical acreage in other areas.
Rocky Mountain Region. St. Mary has conducted operations in the Williston Basin in eastern Montana
and western North Dakota since 1991. The region is managed by our office in Billings, Montana. In recent years,
we have expanded our operations into the Greater Green River, Powder River, Big Horn, and Wind River basins
of Wyoming through a series of acquisitions. The largest growth in the region came in late 2002 and early 2003
with significant property acquisitions from Choctaw, Burlington Resources, and Flying J. These transactions
brought with them a large acreage position that has precipitated additional growth in this region.
We incurred costs of $190.3 million in 2008 for exploration, development, and acquisitions in the Rocky
Mountain region, compared to $178.3 million in 2007. A significant portion of our 2008 program was operated
by others. In the Williston Basin, our investments focused primarily on the Bakken formation. In Wyoming, we
made investments to complete wells in the Hanging Woman Basin coalbed methane project. Proved reserves for
the Rocky Mountain region were 261.4 BCFE at year-end, down 41 percent from 443.6 BCFE as of the end of
2007. The significant decrease in proved reserves is the result of two items. First, we sold 38.4 BCFE of proved
reserves in the region throughout the year as part of a divestiture of non-strategic assets. Second, as a result of
lower prices for oil and wider than normal differentials at year-end, the region saw a negative price revision of
131.2 BCFE. Production in the Rocky Mountain region for 2008 was 34.9 BCFE. Total regional production was
down 10 percent from 38.7 BCFE in 2007. Adjusting for the effect of the divestitures, production in the region
would have declined 0.7 BCFE, or two percent, year over year.
The Elm Coulee Field is the highest value field in the region at year-end 2008, with proved reserves of
28.2 BCFE and a PV-10 value of $47.5 million. The reserves in this field are predominately oil and the Bakken is
the formation of primary interest. This field comprises approximately four percent of our entire PV-10 value.
We will invest significantly fewer dollars in the Rocky Mountain region in 2009. Current oil prices and
differentials do not support significant investment activity in the region and since we have limited long-term
commitments and no meaningful lease commitments, we have elected to slow down capital investment. We will
participate in a handful of horizontal Bakken wells, as well as conduct a few exploration tests during the year.
Reserves
The following table presents summary information with respect to the estimates of our proved oil and gas
reserves for each of the years in the three-year period ended December 31, 2008. For all years presented,
Netherland, Sewell and Associates, Inc. (―NSAI‖) prepared the reserve information for the Company’s coalbed
natural gas projects at Hanging Woman Basin in the northern Powder River Basin and St. Mary’s non-operated
coalbed methane interest in the Green River Basin. We engaged Ryder Scott Company, L.P. to review internal
engineering estimates for 80 percent of the PV-10 value of our proven conventional oil and gas reserves in 2008,
2007, and 2006. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of
all 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 new information becomes available in the
future. The PV-10 values shown in the following table are not intended to represent the current market value of
the estimated proved oil and gas reserves owned by St. Mary. Neither prices nor costs have been escalated. The
following table should be read along with the section entitled ―Risk Factors – Risks Related to Our Business –
The actual quantities and present values of our proved oil and natural gas 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
8
authority or agency, other than the Securities and Exchange Commission, since the beginning of the last fiscal
year.
The ability to replace the reserves produced is important to the sustainability of all exploration and
production companies. Our 2008 ratio of reserves replaced through drilling and acquisition activity was 174%.
The Mid-Continent, Permian, and ArkLaTex regions each were able to replace at least two MCFE of reserves for
every MCFE of production in 2008. The Gulf Coast and Rocky Mountain regions were not able to replace
production during the year. This metric is calculated using information from the Oil and Gas Reserve Quantities
section of Note 17 – Disclosures about Oil and Gas Producing Activities of Part IV, Item 15 of this report. The
numerator consists of the sum of discoveries and extensions and infill reserves in an existing proved field, which
is then divided by production. We believe the concept of reserve replacement as described above, as well as
permutations which may include other captions of the Oil and Gas Reserve Quantities section of Note 17 –
Disclosures about Oil and Gas Producing Activities of Part IV, Item 15 of this report, are widely understood by
those who make investment decisions related to the oil and gas exploration business. For additional information
about reserve replacement metrics, see the reserve replacement terms in the Glossary section of this report.
Proved Reserves Data:
Oil (MMBbl)
Gas (Bcf)
BCFE
Standardized measure of discounted
future cash flows (in thousands)
PV-10 value (in thousands)
Proved developed reserves
Reserve replacement – drilling and
acquisitions, excluding
performance and price revisions
2008
51.4
557.4
865.5
As of December 31,
2007
78.8
613.5
1,086.5
2006
74.2
482.5
927.6
$ 1,059,069
$ 1,265,385
83%
$
$
2,706,914
3,861,187
77%
$ 1,576,437
$ 2,157,449
78%
174%
(93)%
(39)%
7.6
211%
248%
249%
10.1
232%
244%
247%
10.0
All in – including sales of reserves
All in – excluding sales of reserves
Reserve life (years) (1)
(1) Reserve life represents the estimated proved reserves at the dates indicated divided by actual production for the preceding 12-month
period.
The following table reconciles the standardized measure of discounted future net cash flows to the PV-10
value. The difference has to do with 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.
2008
As of December 31,
2007
(In thousands)
2006
Standardized measure of discounted
future net cash flows
Add: 10 percent annual discount, net of
income taxes
Add: future income taxes
Undiscounted future net cash flows
Less: 10 percent annual discount without
tax effect
PV-10 value
$ 1,059,069
$
2,706,914
$ 1,576,437
724,840
419,544
2,321,983
2,316,637
1,238,308
1,125,955
$ 2,203,453
$
7,345,534
$ 3,940,700
(938,068)
(3,484,347)
(1,783,251)
$ 1,265,385
$
3,861,187
$ 2,157,449
9
Production
The following table summarizes the average volumes and realized prices, including and excluding the
effects of hedging, of oil and gas produced from properties in which St. Mary held an interest during the periods
indicated. Also presented is a production cost per MCFE summary for the Company.
Net production
Oil (MMBbl)
Gas (Bcf)
BCFE
Average net daily production
Oil (MBbl)
Gas (MMcf)
MMCFE
Average realized sales price, excluding
the effects of hedging
Oil (per Bbl)
Gas (per Mcf)
Per MCFE
Average realized sales price, including
the effects of hedging
Oil (per Bbl)
Gas (per Mcf)
Per MCFE
Production costs per MCFE
Lease operating expense
Transportation expense
Production taxes
$
$
$
$
$
$
$
$
$
Productive Wells
Years Ended December 31,
2007
2008
2006
6.6
74.9
114.6
18.1
204.7
313.1
6.9
66.1
107.5
18.9
181.0
294.5
6.1
56.4
92.8
16.6
154.7
254.2
92.99
8.60
10.99
$
$
$
67.56
6.74
8.48
$
$
$
59.33
6.58
7.88
75.59
8.79
10.11
1.46
0.19
0.71
$
$
$
$
$
$
62.60
7.63
8.71
1.31
0.14
0.58
$
$
$
$
$
$
56.60
7.37
8.18
1.25
0.12
0.54
As of December 31, 2008, St. Mary had working interests in 2,157 gross (1,057 net) productive oil wells
and 3,745 gross (1,510 net) productive gas wells. Productive wells are either producing wells or wells capable of
commercial production although currently shut-in. One or more 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 current
production.
10
Drilling Activity
All of our drilling activities are conducted on a contract basis with independent drilling contractors. We
do not own any drilling equipment. The following table sets forth the wells drilled and recompleted in which St.
Mary participated during each of the three years indicated:
2008
Years Ended December 31,
2007
2006
Gross
Net
Gross
Net
Gross
Net
221
559
25
805
2
10
1
13
7
825
81.46
205.18
13.70
300.34
0.40
2.75
0.76
3.91
-
304.25
164
518
30
712
3
9
5
17
1
730
77.91
204.62
13.18
295.71
81
446
31
558
1.92
4.01
2.58
8.51
10
15
8
33
-
304.22
2
593
35.32
178.97
10.65
224.94
5.53
3.68
1.81
11.02
-
235.96
Development:
Oil
Gas
Non-productive
Exploratory:
Oil
Gas
Non-productive
Farmout or non-consent
Total (1)
(1) Does not include three gross wells completed on St. Mary’s fee lands during 2006, in which we have only a royalty interest.
11
Acreage
The following table sets forth the gross and net acres of developed and undeveloped oil and gas leases,
fee properties, mineral servitudes, and lease options held by St. Mary as of December 31, 2008. Undeveloped
acreage includes leasehold interests that may already have been classified as containing proved undeveloped
reserves.
Arkansas
Colorado
Kansas
Louisiana
Mississippi
Montana
Nevada
New Mexico
North Dakota
Oklahoma
Texas
Utah
Wyoming
Louisiana Fee Properties
Louisiana Mineral Servitudes
Total
Developed Acres (1)
Net
Gross
Undeveloped Acres (2)
Net
Gross
Total
Gross
Net
1,434
1,646
-
121,688
4,329
59,535
-
5,026
125,104
250,915
233,201
-
127,443
930,321
10,499
7,653
18,152
948,473
182
1,455
-
44,831
1,069
39,985
-
2,561
86,104
78,571
112,387
-
87,223
454,368
10,499
4,404
14,903
469,271
147
6,663
2,240
39,146
103,609
430,981
243,147
3,033
219,674
110,121
490,081
3,328
397,361
2,049,531
14,415
4,622
19,037
2,068,568
60
5,225
560
7,462
41,843
287,836
243,147
2,343
126,153
53,864
230,856
591
228,070
1,228,010
14,415
4,260
18,675
1,246,685
1,581
8,309
2,240
160,834
107,938
490,516
243,147
8,059
344,778
361,036
723,282
3,328
524,804
2,979,852
24,914
12,275
37,189
3,017,041
242
6,680
560
52,293
42,912
327,821
243,147
4,904
212,257
132,435
343,243
591
315,293
1,682,378
24,914
8,664
33,578
1,715,956
(1) Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation. Developed acreage of St.
Mary’s properties that include multiple formations with different well spacing requirements may be considered undeveloped for
certain formations, but have only been included as developed acreage in the presentation above.
(2) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production
of commercial quantities of oil and gas, regardless of whether such acreage contains estimated reserves.
Major Customers
During 2008, 2007 and 2006, no customer individually accounted for ten percent or more of the
Company’s total oil and gas production revenue.
Employees and Office Space
As of February 17, 2009, we had 560 full-time employees. Our 2008 business plan involved a change in
operations philosophy to utilize more St. Mary employed lease operators as opposed to contracting lease
operators. None of our employees are subject to a collective bargaining agreement and we consider our relations
with our employees to be good. We lease approximately 78,000 square feet of office space in Denver, Colorado
for our executive and administrative offices, of which approximately 9,000 square feet is subleased. We lease
approximately 22,000 square feet of office space in Tulsa, Oklahoma; approximately 21,000 square feet in
Shreveport, Louisiana; approximately 20,000 square feet in Houston, Texas; approximately 12,000 square feet in
Midland, Texas; approximately 36,000 square feet in Billings, Montana; approximately 9,000 square feet in
Williston, North Dakota; approximately 5,000 square feet in Sheridan, Wyoming; and approximately 2,000 square
feet in Casper, Wyoming.
12
Title to Properties
Substantially all of our working interests are held pursuant to leases from third parties. A title opinion is
usually obtained prior to the commencement of drilling operations. We have obtained title opinions or have
conducted a thorough 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.
The majority of the value of our properties is subject to a mortgage under our credit facility, customary 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 perform only a minimal title investigation before acquiring undeveloped
leasehold.
Seasonality
Generally, but not always, the demand and price levels for natural gas increase during the colder winter
months and decrease during the warmer 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, increasing summertime
demand for electricity is beginning to place an increasing demand on storage volumes. Crude oil and the demand
for heating oil are also impacted by generally higher prices in the winter – although oil is much more driven by
global supply and demand. Seasonal anomalies such as mild winters sometimes lessen these fluctuations. The
impact of seasonality has somewhat been exacerbated by the overall supply and demand economics related to
crude oil because there is a narrow margin of production capacity in excess of existing worldwide demand.
Competition
The oil and gas industry is intensely competitive. This is particularly true in the competition for
acquisitions of prospective oil and natural gas properties and oil and gas reserves. We believe that our leasehold
position provides a sound foundation for a solid drilling program. Our competitive position also depends on our
geological, geophysical, and engineering expertise, and our financial resources. We believe that the location of
our leasehold acreage, our exploration, drilling, and production expertise, and the experience and knowledge of
our management and industry partners enable us to compete effectively in our core operating areas.
Notwithstanding our talents and assets, we still face stiff competition from a substantial number of major and
independent oil and gas companies that 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 generate electricity. We also compete with other oil and natural gas companies in attempting to secure
drilling rigs and other equipment necessary for the drilling and completion of wells. Consequently, drilling
equipment may be in short supply from time to time. Currently, access to incremental drilling equipment in
certain regions is difficult but is not anticipated to have any material negative impact on our ability to deploy our
drilling capital budget for 2009. We are seeing signs of loosening rig availability, although it is quite specific by
region. Finally, we also compete for people. Throughout the industry, the need for talented people has grown at a
time when the number of people available is constrained. We are not insulated from this resource constraint, and
we must be willing to compete in this market in order to be successful.
Government Regulations
Our business is extensively regulated by numerous federal, state, and local laws and government
regulations. These laws and regulations may be changed from time to time in response to economic or political
conditions, and our regulatory burden may increase in the future. Laws and regulations increase our cost of doing
business and, consequently, 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 crude oil and natural gas, including laws and
regulations requiring permits for the drilling of wells, imposing bonding requirements in order to drill or operate
13
wells, and governing the 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 which may be drilled in an area, the spacing of wells, and the
unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws sometimes
establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or
flaring of natural 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) or the Minerals Management Service (MMS). These leases contain
relatively standardized terms and require compliance with detailed regulations and orders, which are subject to
change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the
BLM or MMS before drilling and comply with regulations governing, among other things, engineering and
construction specifications for production facilities, safety procedures, plugging and abandonment of offshore
Gulf of Mexico wells, 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 or the MMS, as
applicable, may require our operations on federal leases to be suspended or terminated.
Our sales of natural gas are affected by the availability, terms, and cost of natural gas pipeline
transportation. The Federal Energy Regulatory Commission (FERC) has jurisdiction over the transportation and
sale for resale of natural gas in interstate commerce. The 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
recently pursued by the FERC and the U.S. Congress may not continue indefinitely.
Environmental Regulations. Our operations are subject to stringent federal, state, and local laws and
regulations relating to environmental protection. These laws and regulations may require that permits be obtained
before drilling commences, restrict the types, quantities, and concentration of various substances that can be
released into the environment in connection with drilling and production activities, govern the handling and
disposal of waste material, and limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands, and other protected areas, including areas containing endangered animal species. As a result, these laws
and regulations may substantially increase the costs of exploring for, developing, or producing oil and gas and
may prevent or delay the commencement or continuation of certain projects. In addition, these laws and
regulations may impose substantial clean-up, remediation, and other obligations in the event of any discharges or
emissions in violation of these laws and regulations.
Our coalbed methane gas production requires state permits for the use of well-site pits and infiltration
ponds for the disposal of the water produced from the coalbed methane wells. Groundwater produced from the
coal seams can generally be discharged into certain areas without a permit if it does not exceed surface discharge
permit levels, and meets state and federal primary drinking water standards. The disposal options require an
extensive third-party water sampling and laboratory analysis program to ensure compliance with state permit
standards. Where water of lesser quality is involved or the wells produce water in excess of the applicable
volumetric permit limits, additional disposal wells may have to be drilled to re-inject the produced water back into
underground rock formations.
To date we have not experienced any materially adverse effect on our operations from obligations under
environmental laws and regulations. We believe that we are in substantial compliance with currently applicable
environmental laws and regulations, and that continued compliance with existing requirements would not have a
materially adverse impact on us.
14
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
Reserve estimates and the estimates of both future net revenues and the present value of future net
revenues that are included in their calculation
Future oil and natural gas production estimates
Our outlook on future oil and natural gas prices 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
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 Form 10-K.
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 in Item 1A of this Form 10-K, and include such factors as:
The volatility and level of realized oil and natural gas prices
A contraction in demand for oil and natural gas as a result of adverse general economic conditions
The availability of economically attractive exploration, development, and property acquisition
opportunities and any necessary financing, including constraints on the availability of opportunities
and financing due to currently distressed capital and credit market conditions
Our ability to replace reserves and sustain production
Unexpected drilling conditions and results
Unsuccessful exploration and development drilling
15
The risks of hedging strategies
The uncertain nature of the expected benefits from acquisitions and divestitures of oil and natural gas
properties, including uncertainties in evaluating oil and natural gas reserves of acquired properties
and associated potential liabilities
The imprecise nature of oil and natural gas reserve estimates
Uncertainties inherent in projecting future rates of production from drilling activities and acquisitions
Declines in the values of our oil and natural gas properties resulting in write-downs
The ability of purchasers of production to pay for amounts purchased
Drilling and operating service availability
Uncertainties in cash flow
The financial strength of hedge contract counterparties and credit facility participants, and the risk
that one or more of those parties may not satisfy their contractual commitments
The negative impact that lower oil and natural gas prices could have on our ability to borrow and fund
capital expenditures
The potential effects of increased levels of debt financing
Our ability to compete effectively against other independent and major oil and natural gas companies
Litigation, environmental matters, the potential impact of government regulations, and the use of
management estimates.
We caution 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. 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 http://www.stmaryland.com. We routinely post important information for
investors on our website. Within our website’s financial information section we make available free of charge our
annual reports 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, and the Charters for our Board of Directors’ Audit Committee,
Compensation Committee, Executive Committee, and Nominating and Corporate Governance Committee. These
documents are also available in print to any stockholder who requests them. Requests for these documents may
be submitted to:
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St. Mary Land & Exploration Company
Investor Relations
1776 Lincoln Street, Suite 700
Denver, Colorado 80203
Telephone: (303) 863-4322
http://www.stmaryland.com
Information on our website is not incorporated by reference into this Form 10-K and should not be
considered part of this document.
Glossary of Oil and Natural Gas Terms
The oil and natural gas terms defined in this section are used throughout this Form 10-K. The definitions
of the terms exploratory well, field, proved developed reserves, proved reserves, and proved undeveloped reserves
have been abbreviated from the respective definitions under Rule 4-10(a) of Regulation S-X promulgated by the
SEC. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the
SEC’s website at http://www.sec.gov.
Bbl. One stock tank barrel, or 42 U.S. gallons 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 (including natural gas liquids) to one Bbl of oil.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas
(including natural gas liquids) to one Bbl of oil.
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 or natural gas in sufficient commercial quantities.
Exploratory well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new
reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a
known reservoir.
Farmout. An assignment of an interest in a drilling location and related acreage conditioned upon the drilling of a
well on that location.
Fee land. 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 cost. Expressed in dollars per MCFE. Finding 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 Note 16 – Oil and Gas
Activities and Note 17 – Disclosures about Oil and Gas Producing Activities of the Notes to Consolidated
Financial Statements included in this report. It should be noted that finding 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
17
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 cost metrics are explained below.
Finding cost – Drilling, excluding performance and price revisions. Calculated by dividing the amount
of total capital expenditures for oil and natural gas activities, including the effect of asset retirement
obligations, by the amount of estimated net proved reserves added through discoveries, extensions, and
infill drilling, during the same period.
Finding cost – Drilling and acquisitions, excluding performance and price revisions. Calculated by
dividing the amount of total capital expenditures for oil and natural gas activities, including the effect of
asset retirement obligations, by the amount of estimated net proved reserves added through discoveries,
extensions, infill drilling and acquisitions during the same period.
Finding cost – All in, excluding sales of reserves. Calculated by dividing the amount of total capital
expenditures for oil and natural gas activities, including the effect of asset retirement obligations, by the
amount of estimated net proved reserves added through discoveries, extensions, infill drilling,
acquisitions, and revisions of pricing and previous estimates during the same period.
Finding cost –All in, including sales of reserves. Calculated by dividing the amount of total capital
expenditures for oil and natural gas activities, including the effect of asset retirement obligations, by the
amount of estimated net proved reserves added through discoveries, extensions, infill drilling,
acquisitions, and revisions of pricing and 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 which are drilled at angles greater than 70 degrees from vertical.
Lease operating expenses. The expenses of lifting oil or natural gas 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, short-lived assets, maintenance, allocated overhead costs, and other expenses
incidental to production, but not including lease acquisition or drilling or completion expenses.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of
natural gas (including natural gas liquids) to one Bbl of oil.
MMBOE. One million barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of
natural gas (including natural gas liquids) to one Bbl of oil.
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 (including natural gas liquids) to one Bbl of oil.
MMcf. One million cubic feet, used in reference to natural gas.
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MMCFE. One million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio
of six Mcf of natural gas (including natural gas liquids) to one Bbl of oil.
MMBtu. One million British Thermal Units. A British Thermal Unit is the amount of heat required to raise the
temperature of a one-pound mass of water by one degree Fahrenheit.
Net acres or net wells. The 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.
NYMEX. New York Mercantile Exchange.
Play. A term used to describe a portion of the exploration and production cycle following the identification by
geologists and geophysicists of areas with potential oil and natural gas reserves.
PV-10 value. 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, using prices and costs in
effect as of the date indicated (unless such prices or 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 and future income tax expenses or to depreciation, depletion, and amortization, discounted using an
annual discount rate of ten percent. While this measure does not include the effect of income taxes as it would in
the use of the standardized measure 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.
Productive well. A well that is producing oil or natural gas or that is capable of commercial production.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved 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.
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 Note 17 – Disclosures about Oil and Gas Producing
Activities of the Notes to Consolidated Financial Statements included in 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, since 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.
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Reserve replacement – Drilling, excluding performance and price 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 of time. Sales from reserves should be included in the
numerator to consider the impact any divestitures of proved reserves would have on this metric in the
respective period. This metric is an indicator of the relative success a company is having in replacing its
production through drilling activity.
Reserve replacement – Drilling and acquisitions, excluding performance and price revisions. Calculated
as a numerator comprised of the sum of reserve acquisitions and reserve extensions and discoveries and
infill reserves in an existing proved field divided by production for that same period of time. Sales from
reserves should be included in the numerator to consider the impact any divestitures of proved reserves
would have on this metric in the respective 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 percentage – All in, excluding sales of reserves. The sum of 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 of time.
Reserve replacement percentage –All in, including sales of reserves. The sum of sales of reserves,
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 of time.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil
and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other
reservoirs.
Resource play. A term used to describe an accumulation of oil and/or natural gas known to exist over a large area
expanse and/or thick vertical section, which when compared to a conventional play typically has a lower expected
geological and/or commercial development risk and a lower expected average decline rate.
Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage of gross income from
oil and natural gas 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 oil and natural gas
production free of costs of exploration, development, and production operations.
Seismic. An exploration method of sending energy waves or sound waves into the earth and recording the wave
reflections to indicate the type, size, shape and depth of subsurface rock formations.
Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to
proved reserves based on year-end prices, costs, and statutory tax rates, and a ten percent annual discount rate.
The information for this calculation is included in the note regarding disclosures about oil and gas producing
activities contained in the Notes to Consolidated Financial Statements included in this Form 10-K.
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 or natural gas, regardless of whether such acreage contains
estimated net proved reserves.
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.
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ITEM 1A.
RISK FACTORS
In addition to the other information included in this Form 10-K, the following risk factors should be
carefully considered when evaluating St. Mary.
Risks Related to Our Business
Oil and natural gas 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 oil and natural gas sales. Oil and natural gas
prices also affect our cash flows available for capital expenditures and other items, our borrowing capacity, and
the amount and value of our oil and natural gas reserves. For example, the amount of our borrowing base under
our credit facility is subject to periodic redeterminations based on oil and natural gas prices specified by our bank
group at the time of redetermination. In addition, we may have oil and natural gas property write-downs if prices
fall significantly, as has been the case in the past several months.
Historically, the markets for oil and natural gas have been volatile and they are likely to continue to be
volatile. Wide fluctuations in oil and natural gas prices may result from relatively minor changes in the supply of
and demand for oil and natural gas, market uncertainty, and other factors that are beyond our control, including:
Global and domestic supplies of oil and natural gas, and the productive capacity of the industry as a
whole
The level of consumer demand for oil and natural gas
Overall global and domestic economic conditions
Weather conditions
The availability and capacity of transportation or refining facilities in regional or localized areas that
may affect the realized price for oil or natural gas
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 affecting energy consumption
The ability of the members of the Organization of Petroleum Exporting Countries to agree to and
maintain oil price and production controls
Political instability or armed conflict in oil or natural gas producing regions
Governmental regulations and taxes.
These factors and the volatility of oil and natural gas markets make it extremely difficult to predict future
oil and natural gas price movements with any certainty. Declines in oil or natural gas prices would reduce our
revenues and could also reduce the amount of oil and natural gas that we can produce economically, which could
have a materially adverse effect on us.
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The current economic and financial crisis may have impacts on our business that we cannot predict.
The continued economic and credit crisis and related turmoil in the global and domestic financial systems
may continue to have an impact on our business, and we may face challenges if economic and credit conditions
do not improve. The recent general economic slowdown has affected the demand for oil and natural gas, and
recent significant declines in oil and natural gas prices from the highs of June and early July of 2008 have reduced
our operating cash flows and may ultimately affect our access to the capital markets. Although we currently
believe that our liquidity and available capital resources through operating cash flows and our existing credit
facility with ten participating banks are sufficient to fund our ongoing operational obligations and anticipated
capital expenditures for the foreseeable future, continued distressed capital and credit market conditions and
decreased oil and natural gas prices could ultimately limit our access to capital and have a materially adverse
effect on our liquidity, financial condition, results of operations, and cash flows. The current economic situation
could also adversely affect the collectability of our trade receivables and cause our commodity hedging
arrangements to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy
protection. In addition, the current economic situation could lead to further reductions in the demand for oil and
natural gas, and lower prices for oil and natural gas, or both, which could have a materially adverse effect on our
revenues, results of operations, cash flows, liquidity, and financial condition.
If we are not able to replace reserves, we will not be able to sustain production.
Our future operations depend on our ability to find, develop, or acquire oil and natural gas reserves that
are economically recoverable. Our properties produce oil and natural gas at a declining rate over time. In order to
maintain current production rates, we must locate and develop or acquire new oil and natural gas reserves to
replace those being depleted by production. In addition, competition for the acquisition of producing oil and
natural gas properties is intense and many of our competitors have financial and other resources needed to
evaluate and integrate acquisitions that are substantially greater than those available to us. Therefore, we may not
be able to acquire oil and natural gas properties that contain economically recoverable reserves, or we may not be
able to acquire such properties at prices acceptable to us. Without successful drilling or acquisition activities, our
reserves, production, and revenues will decline over time.
Substantial capital is required to replace our reserves.
We must make substantial capital expenditures to find, acquire, develop, and produce oil and natural gas
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 oil and natural gas sales, our success in locating and
acquiring new reserves, and the orderly functioning of credit and capital markets. As we currently note, when oil
or natural gas 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.
When our revenues decrease due to lower oil or natural gas prices, decreased production, or other reasons,
and if we cannot obtain capital through our revolving credit facility, other acceptable debt or equity financing
arrangements, or the sale of non-core assets, our ability to execute development plans, replace our reserves, or
maintain production levels could be greatly limited.
The debt and equity financing markets are currently very constrained due to the global and domestic
economic and financial crisis, and it is possible that circumstances may arise where one or more of the ten
participating banks in our credit facility, at some point, will not be able to fulfill their portion of the lending
commitments to us under the facility. Continued adverse conditions in the credit markets may increase the cost of
borrowings and decrease our ability to access new sources of capital.
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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 companies, independent oil and natural gas exploration and
production companies, financial buyers, and institutional and individual investors who seek oil and natural gas
property investments throughout the world, as well as the equipment, expertise, labor, and materials required to
operate oil and natural gas properties. Many of our competitors have financial, technical, and other resources
vastly exceeding those available to us, and many 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 people available has been constrained.
The actual quantities and present values of our proved oil and natural gas reserves may be less than we have
estimated.
This Form 10-K and other SEC filings by us contain estimates of our proved oil and natural gas 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 oil and natural gas prices, drilling and operating expenses,
capital expenditures, taxes, timing of operations, and availability of funds. The process of estimating oil and
natural gas 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 these variables evolve. Therefore, these
estimates are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, production taxes, development
expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will most likely vary
from those estimated. Any significant variance could materially affect the estimated quantities of and present
values related to proved reserves disclosed by us, and the actual quantities and present values may be less than we
have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history,
results of exploration and development activity, prevailing oil and natural gas 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 by operators on adjacent properties.
As of December 31, 2008, approximately 17 percent, or 149.7 BCFE, of our estimated proved reserves
were proved undeveloped, and approximately 12 percent, or 104.5 BCFE, were proved developed non-producing.
Estimates of proved undeveloped reserves and proved developed non-producing reserves are nearly always based
on volumetric calculations rather than the performance data used to estimate producing reserves. In order to
develop our proved undeveloped reserves, an estimated $281 million 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 bring production on-line for our proved developed non-
producing reserves, we estimate capital expenditures of $61 million will be deployed in future years. Although
we have estimated our reserves and the costs associated with these 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. The balance of our currently anticipated capital expenditures for 2009 is directed towards projects that
are not yet classified within the construct of proved reserves as defined by Regulation S-X promulgated by the
SEC.
You should not assume that the PV-10 value and standardized measure of discounted future net cash
flows included in this Form 10-K represent the current market value of our estimated proved oil and natural gas
reserves. Management has based the estimated discounted future net cash flows from proved reserves on prices
23
and costs as of the date of the estimate, in accordance with current SEC requirements, whereas actual future prices
and costs may be materially higher or lower. For example, values of our reserves as of December 31, 2008, were
estimated using a calculated sales price of $5.71 per MMBtu of natural gas (NYMEX Henry Hub spot price) and
$44.60 per Bbl of oil (NYMEX West Texas Intermediate spot price). We then adjust these base prices to reflect
appropriate basis, quality, and location differentials as of that date in estimating our proved reserves. During
2008, our monthly average realized natural gas prices, excluding the effect of hedging, were as high as $12.65 per
Mcf and as low as $4.61 per Mcf. For the same period, our monthly average realized oil prices before hedging
were as high as $129.40 per Bbl and as low as $32.42 per Bbl. Many other factors will affect actual future net
cash flows, including:
Amount and timing of actual production
Supply and demand for oil and natural gas
Curtailments or increases in consumption by oil purchasers and natural gas pipelines
Changes in government regulations or 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 PV-10 values. In addition,
the ten percent discount factor required by the SEC to be used to calculate PV-10 values 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 beyond our control. These
factors include exploration potential, future oil and natural gas 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 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.
Exploration and development drilling may not result in commercially productive reserves.
Oil and natural gas drilling and production activities are subject to numerous risks, including the risk that
no commercially productive oil or natural gas will be found. The cost of drilling and completing wells is often
24
uncertain, and oil and natural gas 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
Pressure or geologic irregularities in formations
Equipment failures or accidents
Hurricanes or other adverse weather conditions
Compliance with environmental and other governmental requirements
Shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture
stimulation crews and equipment, chemicals, and supplies.
The prevailing prices of oil and natural gas affect the cost of and the demand for drilling rigs, production
equipment, and related services. However, changes in costs may not occur simultaneously with corresponding
changes in 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 current economic and financial crisis 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 which 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 oil or natural gas is present, or whether it 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 initial drilling and completion costs.
Drilling results in our newer shale plays, such as the Eagle Ford, Haynesville, Marcellus, and Pearsall
shales, may be more uncertain than in shale plays that are more developed and have longer established production
histories. For example, our experience with horizontal drilling in these shales, as well as the industry’s drilling
and production history, is more limited than in the Woodford shale play. 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 drilling location inventories for
multi-year programs scheduled out over several years. Such multi-year drilling inventories can be more
susceptible to long-term horizon 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, or if we will be able to produce oil or natural gas from these or any other potential drilling
locations.
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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. Although we have identified numerous potential drilling
locations, we may not be able to economically produce oil or natural gas from all of them.
Our hedging activities may result in financial losses or may limit the prices that we receive for oil and natural gas
sales.
To manage our exposure to price risks in the sale of our oil and natural gas production, we enter into
commodity price risk management arrangements periodically with respect to a portion of our current or future
production. We have hedged a significant portion of anticipated future production from our currently producing
properties using zero-cost collars and swaps. As of December 31, 2008, we were in a net accrued asset position
of approximately $105.3 million with respect to our oil and natural gas hedging 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 hedge contracts default on their contractual obligations
There is a widening of price differentials between delivery points for our production and the delivery
point assumed in the hedge arrangement.
The risk that one or more counterparties may default on their obligations is heightened by the recent
global and domestic economic and financial crisis affecting many banks and other financial institutions, including
our counterparties or their affiliates. These circumstances may adversely affect the ability of the counterparties to
meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when
we are also receiving a lower price for our natural gas and oil sales, which triggered the hedge payment
obligations by the counterparties. As a result, our financial condition, results of operations, and cash flows could
be materially adversely affected if our counterparties default on their contractual obligations under our hedge
contracts.
In addition, commodity price hedging may limit the prices that we receive for our oil and natural gas sales
if oil or natural gas prices rise substantially over the price established by the hedge. Some of our hedging
agreements may also require us to furnish cash collateral, letters of credit, or other forms of performance
assurance in the event that mark-to-market calculations result in settlement obligations by us to the counterparties,
which could impact our liquidity and capital resources. In addition, some of our hedging transactions use
derivative instruments that may involve basis risk. Basis risk in a hedging contract occurs when the index upon
which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby
making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production
may have more or less variability than the regional price index used for the sale of that production.
The inability of one or more of our customers to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to
third parties in the energy industry. This concentration of customers and joint interest owners may impact our
overall credit risk in that these entities may be similarly affected by various economic and other conditions,
including the current global and domestic economic and financial crisis.
Future oil and natural gas 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 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 proved reserves are not discovered with an
exploratory well, the costs of drilling the well are expensed.
26
The capitalized costs of our oil and natural gas properties, on a field basis, cannot exceed the estimated
undiscounted future net cash flows of that field. If net capitalized costs exceed undiscounted future net revenues,
we must write down the costs of each such field to our estimate of its fair market value. Unproved properties are
evaluated at the lower of cost or fair market value. Oil and natural gas prices declined significantly throughout
the second half of 2008. Prices in effect on December 31, 2008, used to estimate proved reserves were $44.60 per
barrel and $5.71 per MMBtu of gas. As a result of these price declines, we incurred impairment of proved
property write-downs, impairment of unproved properties, and goodwill impairment totaling $302.2 million,
$39.0 million, and $9.5 million, respectively, during 2008. Significant further declines in oil or natural gas 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 quarterly based on 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
oil or natural gas prices increase.
Lower oil or natural gas prices could limit our ability to borrow under our revolving credit facility.
Our revolving credit facility has a maximum commitment amount of $500 million, subject to a borrowing
base that the lenders periodically redetermine based on the bank group’s assessment of the value of our oil and
natural gas properties, which in turn is based in part on oil and natural gas prices. The current borrowing base
under our credit facility is $1.4 billion, which was determined as of October 1, 2008. Oil and natural gas prices
have declined since October 1, 2008, and unless prices increase, we currently expect that the borrowing base will
be lower at the next scheduled redetermination date of April 1, 2009. Further declines in oil or natural gas prices
in the future could limit our borrowing base and reduce our ability to borrow under the credit facility.
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, 2008, we had $287.5 million of total long-term senior unsecured debt outstanding
under our 3.50% Senior Convertible Notes due 2027, and $300.0 million of secured debt outstanding under our
revolving credit facility. As of February 17, 2009, we had an outstanding balance of $318.5 million drawn
against our revolving credit facility, resulting in $181.5 million of available debt capacity under our revolving
credit facility assuming the borrowing conditions of this facility were met. Our long-term debt represented 34
percent of our total book capitalization as of December 31, 2008.
Our amount of debt 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, creating liens on our properties, making acquisitions, and
paying dividends
Placing us at a competitive disadvantage compared to our competitors that have less debt
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,
27
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
revolving 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, sell 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. The
indenture for our 3.50% Senior Convertible Notes due 2027 provides that under certain circumstances we have
the option to settle our obligations under these notes through the issuance of shares of our common stock if we so
elect.
Our debt instruments, including our revolving credit facility agreement, also permit us to incur additional
debt in the future. In addition, the entities we may acquire in the future could have significant amounts of debt
outstanding which we could be required to assume in connection with the acquisition, or we may incur our own
significant indebtedness to consummate an acquisition.
As discussed above, our revolving 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.
We are subject to operating and environmental risks and hazards that could result in substantial losses.
Oil and natural gas operations are subject to many risks, including well blowouts, craterings, explosions,
uncontrollable flows of oil, natural gas, or well fluids, fires, adverse weather such as hurricanes in the Gulf Coast
region, freezing conditions, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of
toxic gas, and other environmental risks and hazards. If any of these types of events occurs, we could sustain
substantial losses.
Under certain limited circumstances we may be liable for environmental damage caused by previous
owners or operators of properties that we own, lease, or operate. 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 damages. We do not believe that insurance coverage for the full
potential liability that could be caused by sudden environmental damages 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 presented.
Accordingly, we may be subject to liability or may lose substantial portions of certain properties 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 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, 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
28
changes that may affect, among other things, the pricing or marketing of oil and natural gas production.
Noncompliance with statutes and regulations may lead to substantial penalties and the overall regulatory burden
on the industry increases the cost of doing business and, in turn, decreases profitability.
Governmental authorities regulate various aspects of oil and natural gas drilling and production, including
the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of
interests in oil and natural gas properties, environmental matters, safety standards, the sharing of markets,
production limitations, plugging and abandonment standards, and restoration. To cover the various obligations of
leaseholders of offshore interests in federal waters, federal authorities generally require that leaseholders have
substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of
these bonds or other assurances can be substantial, and we may not be able to obtain bonds or other assurances for
Gulf Coast operations in all cases. Under limited circumstances, federal authorities 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, and local governmental authorities in jurisdictions where we are engaged in exploration
or production operations. New laws or regulations, or changes to current requirements, 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 face significant liability to governmental
authorities and third parties, including joint and several as well as strict liability, for discharges of oil, natural gas,
or other pollutants into the air, soil, or water, and we could be required to spend substantial amounts on
investigations, litigation, and remediation. 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.
Possible regulations related to global warming and climate change could have an adverse effect on our
operations and the demand for oil and natural gas.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as
―greenhouse gases,‖ may be contributing to the warming of the Earth’s atmosphere. Methane, a primary
component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas,
are examples of greenhouse gases. The U.S. Congress is considering climate-related legislation to reduce
emissions of greenhouse gases. In addition, at least nine states in the Northeast and five states in the West have
developed initiatives to regulate emissions of greenhouse gases, primarily through the planned development of
greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. The U.S.
Environmental Protection Agency is separately considering whether it will regulate greenhouse gases as ―air
pollutants‖ under the existing federal Clean Air Act. Passage of climate change legislation or other regulatory
initiatives by Congress or various states or the adoption of regulations by the EPA or analogous state agencies that
regulate or restrict emissions of greenhouse gases, including methane or carbon dioxide, in areas in which we
conduct business could have an adverse effect our operations and the demand for oil and natural gas.
We depend on transportation facilities owned by others.
The marketability of our oil and natural gas production depends in part on the availability, proximity, and
capacity of pipeline transportation systems owned by third parties. The lack of available transportation capacity
on these systems and facilities could result in the shutting-in of producing wells, the delay or discontinuance of
development plans for properties, or lower price realizations. Although we have some contractual control over
the transportation of our production, material changes in these business relationships could materially affect our
operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy
policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, and general
economic conditions could adversely affect our ability to produce, gather, and transport oil and natural gas.
29
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, 2008 to February 17, 2009, the closing daily sales price of our common stock as reported
by the New York Stock Exchange ranged from a low of $15.31 per share to a high of $64.64 per share. 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 oil or natural gas prices
Variations in quarterly drilling, recompletions, acquisitions, and operating results
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
Changes in the national and global economic outlook.
We may fail to meet 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 and with the shareholder rights plan described below, 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.
Under our shareholder rights plan, if the Board of Directors determines that the terms of a potential
acquisition do not reflect the long-term value of St. Mary, the Board of Directors could allow the holder of each
outstanding share of our common stock other than those held by the potential acquirer to purchase one additional
share of our common stock with a market value of twice the exercise price. This prospective dilution to a
potential acquirer would make the acquisition impracticable unless the terms were improved to the satisfaction of
the Board of Directors. The existence of the plan may impede a takeover not supported by our Board, even
though such takeover may be desired by a majority of our stockholders or may involve a premium over the
prevailing stock price.
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 17, 2009, 62,189,800 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 1,494,208 shares of our common stock were outstanding,
of which all were exercisable. These options are exercisable at prices ranging from $6.19 to $20.87 per share. In
addition, restricted stock units providing for the issuance of up to a total of 396,241 shares of our common stock
30
and 458,480 performance share awards were outstanding. The PSAs represent the right to receive, upon
settlement of the PSAs 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 PSAs granted, depending on the extent to which
the underlying performance criteria have been achieved and the extent to which the PSAs have vested. As of
February 17, 2009, there were 62,305,557 shares of common stock outstanding, which is net of 176,987 treasury
shares.
We may not always pay dividends on our common stock.
The payment of future dividends remains at the discretion of the 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 covenants in our credit facility, including a covenant regarding the level of our current ratio
of current assets to current liabilities and a limit on the annual dividend rate that we may pay to no more than
$0.25 per share. The 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
St. Mary has no unresolved comments from the SEC staff regarding its 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 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.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of our security holders during the fourth quarter of 2008.
31
ITEM 4A.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth the names, ages and positions held by St. Mary’s executive officers. The
age of the executive officers is as of February 17, 2009.
Chief Executive Officer and President
Executive Vice President and Chief Operating Officer
Executive Vice President and Chief Financial Officer
Senior Vice President and Regional Manager
Senior Vice President and General Counsel
Senior Vice President and Regional Manager
Senior Vice President and Regional Manager
Age Position
Name
59
Anthony J. Best
50
Javan D. Ottoson
43
A. Wade Pursell
Mark D. Mueller
44
Milam Randolph Pharo 56
42
Paul M. Veatch
Stephen C. Pugh
50
Gregory T. Leyendecker 51 Vice President – Regional Manager
John R. Monark
Lehman E. Newton, III
Kenneth J. Knott
David J. Whitcomb
Dennis A. Zubieta
Mark T. Solomon
56 Vice President – Human Resources and Administration
53 Vice President – Regional Manager
44 Vice President – Business Development and Land and Assistant Secretary
46 Vice President – Marketing
42 Vice President – Engineering and Evaluation
40
Controller
Each executive officer has held his respective position during the past five years, except as follows:
Anthony J. Best joined St. Mary in June 2006 as President and Chief Operating Officer. In December
2006 Mr. Best relinquished his position as Chief Operating Officer when Javan D. Ottoson was elected to that
office. Mr. Best was elected Chief Executive Officer of St. Mary in February 2007, when Mark Hellerstein
retired from that position. From November 2005 to June 2006, Mr. Best was developing a business plan and
raising capital for a start-up 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 U.S. 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 a period as President - ARCO
Permian, President - ARCO Latin America, Field Manager for Prudhoe Bay and VP - External Affairs for ARCO
Alaska.
Javan D. Ottoson joined St. Mary in December 2006 as Executive Vice President and Chief Operating
Officer. Mr. Ottoson has been in the oil and gas industry for over 25 years. From April 2006 until he joined St.
Mary 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. These roles
included President of ARCO China, Commercial Director of ARCO British, and Vice President of Operations and
Development, ARCO Permian.
A. Wade Pursell joined St. Mary 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 1997 he was with Arthur Andersen LLP, lastly as an
Experienced Manager specializing in the offshore services industry.
32
Mark D. Mueller joined St. Mary 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 22 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; 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.
Milam Randolph Pharo was appointed Senior Vice President and General Counsel in August 2008. He
served as Vice President – Land and Legal and Assistant Secretary from 1996 to August 2008. Prior to joining St.
Mary, Mr. Pharo served in private practice as an attorney specializing in oil and gas matters since 1979.
Paul M. Veatch was appointed Senior Vice President and Regional Manager in March 2006. Mr. Veatch
joined St. Mary in April 2001 as Regional A & D Engineer. He was Vice President – General Manager,
ArkLaTex from August 2004 to March 2006 and Manager of Engineering for the ArkLaTex Region from April
2003 to August 2004.
Stephen C. Pugh joined St. Mary as Senior Vice President – Regional Manager of the ArkLaTex Region
in July 2007. Mr. Pugh has over 27 years of experience in the oil and gas industry. Prior to joining St. Mary, Mr.
Pugh was Managing Director for Scotia Waterous, a global leader in oil and gas merger and acquisition advisory
services. Mr. Pugh was responsible for new business development, managing client relationships and providing
merger and acquisition advice, including transaction execution to clients in the energy sector. Mr. Pugh held this
position from July 2006 to July 2007. Prior to joining Scotia Waterous, Mr. Pugh had over 17 years of experience
in A&D, operations and engineering with Burlington Resources, Inc., and its successor-by-merger,
ConocoPhillips. His most recent position with Burlington Resources, Inc. and ConocoPhillips was General
Manager, Engineering and Operations – Gulf Coast, a position he held from May 2004 to June 2006. Prior to
that, he was Vice President - Acquisitions and Divestitures for Burlington Resources Canada. He held that
position from May 2000 to May 2004. Mr. Pugh began his career with Superior Oil (subsequently Mobil Oil) in
Lafayette, Louisiana, where he worked in production, drilling, and reservoir engineering.
Gregory T. Leyendecker was appointed Vice President - Regional Manager in July 2007. Mr.
Leyendecker joined St. Mary in December 2006 as Operations Manager for the Gulf Coast Region in Houston.
Mr. Leyendecker has worked for 28 years 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 this time 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 St. Mary, Mr. Leyendecker was Vice President of Drilling
Management Services for Enventure Global Technology, the industry’s leading provider of solid expandable
tubular technology, a position he held from February 2006 to November 2006.
John R. Monark was appointed Vice President – Human Resources in July 2008. Mr. Monark joined St.
Mary in May of 2008 as Director of Human Resources. Mr. Monark was Director – Human Resources for JF
Shea Corporation, a leading construction and homebuilding company, from 2004 to July 2008. He served as Vice
President – Human Resources for Pameco Corporation, a distributor of HVAC systems and equipment and
refrigeration products, from 2000 to 2004. From 1996 to 2000 he served as Vice President – Human Resources
for CH2M HILL.
33
Lehman E. Newton, III joined St. Mary in December 2006 as General Manager for the Midland office and
was appointed to Vice President, Permian Region, in June 2007. Mr. Newton has over 27 years of E&P
experience in engineering, operations, and business development. 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 E&P firm, from
June 2000 to January 2003. Prior to that, Mr. Newton spent 21 years with ARCO in various engineering,
operations and management roles. These assignments included Asset Manager, ARCO’s East Texas operations,
Vice President, Business Development, ARCO Permian, and Vice President of Operations and Development,
ARCO Permian.
Kenneth J. Knott was appointed Vice President – Business Development and Land and Assistant
Secretary in August 2008. Mr. Knott joined St. Mary in November 2000 as Senior Landman for the Gulf Coast
Region in Lafayette, LA and later assumed the position of Gulf Coast Regional Land Manager when the office
was moved to Houston in March 2004. Mr. Knott has worked for 21 years in the energy industry holding various
Land and Business Development positions with ARCO, Vastar Resources and BP Amoco. Between 1987 and
1993, Mr. Knott worked for ARCO in a land capacity handling land and business development responsibilities in
several geographic areas, such as Permian, Mid-Continent, Michigan and California. Upon ARCO’s spin-off of
Vastar Resources in 1993, he joined Vastar Resources as a Senior Landman working the Gulf Coast and Gulf of
Mexico Regions until 1999, at which time he assumed the role of Director of Business Development for the Gulf
Coast Region. He remained in that capacity until the merger of Vastar Resources into BP Amoco in September
2000, whereby he assumed a Senior Landman position working the Gulf Coast Region.
David J. Whitcomb was appointed Vice President – Marketing in August 2008. Mr. Whitcomb joined St.
Mary 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 – Director of Marketing. From 1991 until the time of his employment
with St. Mary, Mr. Whitcomb worked for Anderman/Smith Operating Company as a Gas Contract Analyst during
which time his primary responsibility was to resolve take-or-pay gas contract disputes. Mr. Whitcomb began his
career in the industry in 1986 with Apache Corporation where he worked as an internal auditor for several years
and then moved into marketing where he worked as a Gas Controller and Gas Contracts Analyst.
Dennis A. Zubieta was appointed Vice President – Engineering and Evaluation in August 2008. Mr.
Zubieta joined St. Mary 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 Oil & Gas Company (formerly known as Meridian Oil, Inc.) from June 1988 to May
2000 in various operations and reservoir engineering capacities.
Mark T. Solomon was appointed Controller in January 2007. Mr. Solomon was also appointed Acting
Principal Financial Officer from April 30, 2008 to September 8, 2008, which was during the period of time that
the Company’s Chief Financial Officer position was vacant. Mr. Solomon joined St. Mary 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 St. Mary, Mr. Solomon was an auditor with Ernst & Young.
34
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information. St. Mary’s common stock is currently traded on the New York Stock Exchange
under the symbol SM. The range of high and low sales prices for the quarterly periods in 2008 and 2007, as
reported by the New York Stock Exchange:
Quarter Ended
December 31, 2008
September 30, 2008
June 30, 2008
March 31, 2008
December 31, 2007
September 30, 2007
June 30, 2007
March 31, 2007
High
$ 35.81
65.58
65.00
39.95
$ 44.50
37.15
40.19
38.20
Low
$ 14.76
32.53
37.73
31.70
$ 35.40
31.20
34.91
33.55
35
PERFORMANCE GRAPH
The following performance graph compares the cumulative total stockholder return on St. Mary’s
common stock for the period beginning December 31, 2003 and ending on December 31, 2008, with the
cumulative total returns of the Dow Jones U.S. Exploration and Production Board Index, and the Standard &
Poor’s 500 Stock Index.
COMPARE 5-YEAR CUMULATIVE TOTAL RETURN
AMONG ST. MARY LAND & EXPLORATION COMPANY
$400.00
$350.00
$300.00
$250.00
$200.00
$150.00
$100.00
$50.00
$-
12/31/2003
12/31/2004
12/31/2005
12/31/2006
12/31/2007
12/31/2008
SM
DJUSOS
SPX
The preceding information under the captions ―Performance Graph‖ shall be deemed to be ―furnished‖
but not ―filed‖ with the Securities and Exchange Commission.
Holders. As of February 17, 2009, the number of record holders of St. Mary’s common stock was 105.
Based on inquiry, management believes that the number of beneficial owners of our common stock is
approximately 24,300.
Dividends. St. Mary has paid cash dividends to 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 2008. 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, capital requirements, financial
condition, and other factors. In addition, the payment of dividends is subject to covenants in our credit facility,
including the requirement that we maintain certain levels of stockholders’ equity and the limitation of our annual
dividend rate to no more than $0.25 per share per year. Dividends are currently paid on a semi-annual basis.
Dividends paid totaled $6.2 million in 2008 and $6.3 million in 2007.
Restricted Shares. Aside from Rule 144 restrictions on shares for insiders, shares are subject to transfer
restrictions under the provisions of the Employee Stock Purchase Plan, restricted shares issued to directors under
the Non-Employee Director Stock Compensation Plan, and shares issued to directors under the 2006 Equity
Incentive Compensation Plan (the ―2006 Equity Plan‖). St. Mary has no restricted shares outstanding as of
December 31, 2008.
36
Equity Compensation Plans. St. Mary has the 2006 Equity Plan under which options and shares of
St. Mary 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 in the Notes to Consolidated Financial Statements included in Part IV, Item 15 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, 2008:
(a)
Number of
securities to be
issued upon
exercise of
outstanding
options,
warrants, and
rights
(b)
Weighted-average
exercise price of
outstanding
options, warrants,
and rights
(c)
Number of
securities remaining
available for future
issuance under
equity compensation
plans (excluding
securities reflected in
column (a))
1,509,710
409,388
464,333
2,383,431
-
-
$
$
$
12.69
-
26.48
15.93
-
-
-
-
1,529,140
1,529,140
1,554,583
-
Plan category
Equity compensation plans approved by
security holders:
2006 Equity Incentive Compensation Plan
Stock options and incentive stock
options (1)
Restricted stock (1)
Performance share awards (1)
Total for 2006 Equity Incentive
Compensation Plan
Employee Stock Purchase Plan (2)
Equity compensation plans not approved
by security holders
Total for all plans
2,383,431
$
15.93
3,083,723
(1) In May 2006 the stockholders approved the 2006 Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-
qualified stock options, incentive stock options, stock appreciation rights, and stock-based awards to key employees, consultants, and
members of the Board of Directors of St. Mary or any affiliate of St. Mary. The 2006 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 St. Mary Land & Exploration Company Restricted Stock Plan, and the St. Mary Land & Exploration Company Non-Employee
Director Stock Compensation Plan (collectively referred to as the ―Predecessor Plans‖). All grants of equity are now made out of the
2006 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 2006 Equity Plan continues to be governed solely by the terms and conditions of the
instruments evidencing such grants or issuances. In late 2007, St. Mary transitioned to PSA grants as the primary form of long-term
equity incentive compensation for eligible employees in place of grants of RSUs. The Company’s Board of Directors approved an
amendment and restatement of the 2006 Equity Incentive Compensation Plan on March 28, 2008, and the amended plan was approved
by stockholders at the Company’s annual stockholders’ meeting May 21, 2008. Awards granted in 2008, 2007, and 2006 under the
2006 Equity Plan and the Predecessor Plans were 932,767, 135,138, and 547,678, respectively.
(2) Under the St. Mary Land & Exploration Company Employee Stock Purchase Plan (the ―ESPP‖), eligible employees may purchase
shares of the Company’s 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 purchase period, and
shares issued under the ESPP are restricted for a period of 18 months from the date issued. The ESPP is intended to qualify under
Section 423 of the Internal Revenue Code. Shares issued under the ESPP totaled 45,228, 29,534, and 26,046 in 2008, 2007, and 2006,
respectively.
37
Issuer Purchases of Equity Securities. St. Mary repurchased a total of 2,135,600 shares of its common stock
during 2008. St. Mary did not repurchase any shares of its common stock during the fourth quarter of 2008.
ITEM 6.
SELECTED FINANCIAL DATA
The following table sets forth supplemental selected financial and operating data for St. Mary as of the
dates and periods indicated. The financial data for each of the five years presented were derived from the
consolidated financial statements of St. Mary. The following data should be read in conjunction with
―Management’s Discussion and Analysis of Financial Condition and Results of Operations,‖ which includes a
discussion of factors materially affecting the comparability of the information presented, and in conjunction with
St. Mary’s consolidated financial statements included in this report. In March 2005 the Company’s Board of
Directors approved a two-for-one stock split in the form of a stock dividend whereby one additional share of
common stock was distributed for each common share outstanding. The stock dividend was distributed on
March 31, 2005, to shareholders of record as of the close of business on March 21, 2005. All share and per share
amounts for all prior periods presented herein have been reclassified to reflect this stock split.
2008
Years Ended December 31,
2006
(In thousands, except per share data)
2007
2005
2004
Total operating revenues
$ 1,301,301
$ 990,094
$ 787,701
$ 739,590
$ 433,099
Net income
$
91,553
$ 189,712
$ 190,015
$ 151,936
$ 92,479
Net income per share:
Basic
Diluted
$
$
1.47
1.45
$
$
3.07
2.94
$
$
3.38
2.94
$
$
2.67
2.33
$
$
1.60
1.44
Total assets at year end
$ 2,695,016
$2,571,680
$1,899,097
$ 1,268,747
$ 945,460
Long-term obligations:
Line of credit
Senior convertible notes
Cash dividends declared and
paid per common share
$ 300,000
$ 287,500
$ 285,000
$ 287,500
$ 334,000
$ 99,980
$
0.10
$
0.10
$
0.10
$
$
$
-
99,885
$ 37,000
$ 99,791
0.10
$
0.05
38
Supplemental Selected Financial and Operations Data
2008
2007
Years Ended December 31,
2005
2006
(In thousands, except per share data)
2004
Balance Sheet Data
Total working capital (deficit)
Total stockholders’ equity
$
15,193
$ 1,127,485
$ (92,604)
$ 863,345
$ 22,870
$ 743,374
$
4,937
$ 569,320
$
$
12,035
484,455
Weighted-average shares
outstanding
Basic
Diluted
Reserves
Oil (MMBbl)
Gas (Mcf)
MCFE
Production and Operational:
Oil and gas production revenues,
including hedging
Oil and gas production expenses
DD&A
General and administrative
Production Volumes:
Oil (MMBbl)
Gas (Bcf)
BCFE
Realized price – pre hedging:
Per Bbl
Per Mcf
Realized price – net of hedging:
Per Bbl
Per Mcf
Expense per MCFE:
LOE
Transportation
Production taxes
DD&A
General and administrative
Cash Flow:
62,243
63,133
51.4
557.4
865.5
61,852
64,850
78.8
613.5
1,086.5
56,291
65,962
74.2
482.5
927.6
56,907
66,894
62.9
417.1
794.5
57,702
66,894
56.6
319.2
658.6
$ 1,158,304
$ 271,355
$ 314,330
79,503
$
$ 936,577
$ 218,208
$ 227,596
60,149
$
$ 758,913
$ 176,590
$ 154,522
38,873
$
$ 711,005
$ 142,873
$ 132,758
32,756
$
$
$
$
$
413,318
95,518
92,223
22,004
6.6
74.9
114.6
92.99
8.60
75.59
8.79
1.46
0.19
0.71
2.74
0.69
$
$
$
$
$
$
$
$
$
6.9
66.1
107.5
6.1
56.4
92.8
5.9
51.8
87.4
$
$
$
$
$
$
$
$
$
67.56
6.74
$
$
59.33
6.58
$
$
53.18
8.08
$
$
62.60
7.63
$
$
56.60
7.37
$
$
50.93
7.90
$
$
1.31
0.14
0.58
2.12
0.56
$
$
$
$
$
1.25
0.12
0.54
1.67
0.42
$
$
$
$
$
0.99
0.09
0.56
1.52
0.37
$
$
$
$
$
4.8
46.6
75.4
39.77
5.85
32.53
5.52
0.81
0.10
0.36
1.22
0.29
Provided by operations
Used in investing
Provided by (used in) financing
$ 678,221
$ (672,785)
$ (42,815)
$ 630,792
$ (803,872)
$ 215,126
$ 467,700
$ (724,719)
$ 243,558
$ 409,379
$
$ (339,779) $
(61,093) $
$
237,162
(247,006)
1,435
39
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 Form 10-K for important information about these
types of statements.
Overview of the Company
General Overview
We are an independent energy company focused on the development, exploration, exploitation,
acquisition, and production of natural gas and crude oil in North America. We generate nearly all our revenues
and cash flows from the sale of produced natural gas and crude oil. Our oil and gas reserves and operations are
concentrated primarily in various Rocky Mountain basins, including the Williston, Big Horn, Wind River, Powder
River and Greater Green River basins; the Mid-Continent Anadarko and Arkoma basins; the Permian Basin; the
tight sandstone reservoirs of East Texas and North Louisiana; the Maverick Basin in South Texas; and the
onshore Gulf Coast and offshore Gulf of Mexico. We have developed a balanced and diverse portfolio of proved
reserves, development drilling opportunities, and unconventional resource prospects.
Our mission is to economically grow our production and proved reserves, which we believe builds
stockholder value over the long-term. Historically, we have relied on a strategy of growing through niche
acquisitions focused in the continental United States. Over the last few years, we have shifted our strategy to
focus more on capturing potential resource plays earlier and at lower cost. We believe that this shift will allow for
more stable and predictable production and proved reserves growth. Going forward, we will focus on continuing
to acquire significant leasehold positions in existing and emerging resource plays in North America.
In 2008 we achieved the following financial and operational results:
Average daily gas production of 204.7 MMcf per day was up 13 percent from 2007. Average daily
oil production of 18.1 MBbl per day was down 4 percent from 2007. Average total equivalent daily
production was 313.1 MMCFE which was an annual record for the Company.
Estimated proved reserves of 51.4 MMBbls of oil and 557.4 Bcf of natural gas, or 865.5 BCFE, as of
December 31, 2008. This was a decrease of 20 percent from year-end 2007 proved reserves of
1,086.5 BCFE and reflects the divestiture of 61.4 BCFE of non-strategic properties, 44.5 BCFE in
downward performance revisions, and 199.7 BCFE of negative price revisions.
Diluted earnings per share for 2008 were $1.45 on net income of $91.6 million. This reflects a
decrease in net income when compared to 2007.
Cash flow from operating activities of $678.2 million, an increase of eight percent from 2007.
Our operations are generally funded first through cash flows from operating activities and then through
borrowings under our existing credit facility. Acquisitions may be funded with proceeds from sales of public or
private debt and equity, borrowings under our existing facility, property sales, and cash flow from operating
activities. In 2008 we invested $745.6 million for development and exploration and invested $81.8 million for
acquisitions of oil and gas properties.
A major determination of the value of our Company is the value of our proved reserves. At year-end
2008 we had proved reserves of 865.5 BCFE of which 64 percent were natural gas and 83 percent were
characterized as proved developed. Base oil and gas prices used for our SEC proved reserves were significantly
lower at year-end 2008 compared to the prior year. Additionally, we saw wider than normal differentials at year-
end, particularly for oil in the Rocky Mountain region. We used significantly lower prices at year-end to
determine our proved reserves; these adjusted year-end prices were $5.71 per MMBtu and $44.60 per Bbl, which
40
are down 16 percent and 54 percent, respectively, from the prior year. As a result, we had 199.7 BCFE in
negative pricing revisions at the end of 2008. The majority of these pricing revisions relate to the oil-dominated
Rocky Mountain region, which was impacted by lower oil prices and wider product differentials. These
differentials for oil have improved significantly since year-end. Additionally, we had pricing revisions related to
properties in South Texas as pricing for natural gas liquids deteriorated significantly year over year. We had 44.5
BCFE of negative performance revisions. The majority of our performance revisions relate to Olmos shallow gas
assets in South Texas that were acquired in 2007. The Olmos reservoir is demonstrating poorer reservoir
performance then was originally modeled. The reservoir is more compartmentalized then we initially thought and
we have seen lower reserve outcomes while attempting to infill parts of the field. Our additions through the drill-
bit were 170.1 BCFE, 78 percent, of which was natural gas. We added 29.1 BCFE of proved reserves through
acquisitions in 2008, 93 percent of which was natural gas and 59 percent of which was proved undeveloped.
Throughout 2008, we divested 61.4 BCFE of proved reserves associated with non-core properties. The SEC has
adopted new rules that will be effective at the end of 2009 that change certain factors regarding the calculation of
proved reserves, including changes regarding prices to be used. Under the new rules, which will use an average
price throughout the year rather than a year-end price, we believe the negative pricing revision would have been
less severe and our proved reserves would have been meaningfully higher.
The before income tax PV-10 value of our proved reserves was $1.3 billion as of December 31, 2008.
The after tax value of $1.1 billion as represented by the standardized measure calculation is presented in Note 17
– Disclosures about Oil and Gas Producing Activities of Part IV, Item 15 of this report. A reconciliation between
these two amounts is shown under Reserves in Part I, Items 1 and 2 of this report.
Reserve Replacement, Finding Costs, and Growth
Like all oil and gas exploration and production companies, we face the challenge of declining oil and
natural gas reserves. An oil and gas exploration and production company depletes part of its asset base with each
unit of oil and gas it produces. Historically, we have been able to grow our production despite this natural decline
by adding more reserves through acquisitions and drilling activities than we produce. Future growth will depend
on our ability to economically continue adding reserves in excess of production.
The following table provides various reserve replacement and finding cost metrics for the year ended
December 31, 2008:
Drilling, excluding performance and
price revisions
Drilling, including performance revisions
Drilling and acquisitions, excluding
performance and price revisions
Drilling and acquisitions, including
performance revisions
Acquisitions
All-in, excluding price revisions
All-in, including performance and price
Reserve Replacement
Percentage
Finding Cost per MCFE
Excluding
sales
Including
sales
Excluding
sales
Including
sales
148%
110%
174%
135%
25%
135%
95%
56%
$
$
3.99
5.40
6.25
$
$ 10.57
120%
$
3.67
$
5.30
81%
N/A
81%
$
$
$
4.72
1.77
5.54
$
$
7.83
N/A
9.18
revisions
(39)%
(93)%
$ (19.04)
$
(8.05)
41
The following table provides three-year average reserve replacement and finding cost metrics for the
years ended December 31, 2008, 2007, and 2006:
Reserve Replacement
Percentage
Finding Cost per MCFE
Excluding
sales
Including
sales
Excluding
sales
Including
sales
Drilling, excluding performance and
price revisions
Drilling, including performance revisions
Drilling and acquisitions, excluding
performance and price revisions
Drilling and acquisitions, including
performance revisions
Acquisitions
All-in, excluding price revisions
All-in, including performance and price
revisions
133%
142%
204%
213%
71%
213%
144%
112%
121%
$
$
4.48
4.20
$
$
5.32
4.93
183%
$
3.63
$
4.05
192%
N/A
192%
$
$
$
3.48
2.03
3.87
$
$
3.86
N/A
4.29
123%
$
5.73
$
6.71
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 economically replace at least 200
percent of annual production with new reserves and to grow production greater than ten percent per year. We
believe annual reserve replacement percentage and finding cost amounts 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 that aberrations,
causing both relatively good and bad results, will occur over short intervals of time. The information used to
calculate the above reserve replacement and finding cost metrics is included in Note 16 – Oil and Gas Activities
and Note 17 – Disclosures about Oil and Gas Producing Activities of the Notes to Consolidated Financial
Statements included in part IV, Item 15 of this report. For additional information about these metrics, see the
reserve replacement and finding cost terms in the Glossary at the end of Part I, Items 1 and 2 of this report.
Financial Standing and Liquidity
During and subsequent to the third quarter of 2008, specific issues related to the financial sector have
rippled through the broader economy. The failure or takeover of several large financial institutions has adversely
impacted the wider equity, debt, and credit markets. Financial standing and liquidity have become increasingly
important as concerns have been raised regarding the pace of drilling activity in the exploration and production
industry and the ability of companies to fund their planned activity. In addition, fears of global recession have
resulted in a significant decline in oil and natural gas demand and consequently prices. Our exploration and
development program at the beginning of 2008 was designed to stay within generated cash flow. We met this
goal with our investment of $745.6 million during the year. In addition to exploration and development activities,
we spent $81.8 million on acquisitions and $77.2 million for share repurchases in 2008. These two expenditures
were offset by the divestiture of non-strategic properties that provided $178.9 million.
We continue to believe we have adequate liquidity available to us through our credit facility. On
October 1, 2008, the lending group redetermined our reserve-backed borrowing base under the credit facility at an
amount of $1.4 billion. Based on our expected requirements, we currently have a $500 million commitment
amount in place. We had $300.0 million and $318.5 million drawn on the credit facility at December 31, 2008,
and February 17, 2009, respectively. Management believes the current commitment is sufficient and that if
necessary we could request a higher commitment amount from the lending group, although it would likely be at
different terms and interest rates than are currently in place. To date, we have experienced no issues drawing
upon our credit facility, and all ten participating banks have continued to fund. Except for Wells Fargo Bank,
N.A., who recently merged with Wachovia Bank, National Association and represents 22 percent of the lending
commitment, no individual bank participating in the credit facility represents more than 11 percent of the lending
42
commitments under the credit facility. The existing credit facility expires in April of 2010, and we have begun
discussions with the banks within the existing bank group, as well as banks not in the existing facility, about a
new credit facility. With commodity prices currently significantly lower than those used at our last determination,
we believe that our borrowing base will be lower than the $1.4 billion calculated in October 2008, but still above
the current $500 million commitment amount. We may increase the commitment amount available to us under
the new facility from the $500 million we currently have committed. Given current market conditions, we
anticipate higher pricing and more fees on the new facility. Our intention is to have a new credit facility in place
during the first half of 2009.
Oil and Gas Prices
Oil and natural gas prices increased significantly during the first half of 2008, reaching all time highs in
June and early July, and have declined even more significantly since that time. The results of our operations and
financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate
dramatically. We sell a majority of our natural gas under contracts that use first of the month index pricing,
which means that gas produced in that month is sold at the first of the month price regardless of the spot price on
the day the gas is produced. Our crude oil is sold using contracts that pay us the average of either the NYMEX
West Texas Intermediate daily settlement price or the average of alternative posted prices for the periods in which
the crude oil is produced, adjusted for quality, transportation, and location differentials. The following table is a
summary of commodity price data for the years ended December 31, 2008, 2007, and 2006.
Crude Oil (per Bbl):
NYMEX price
Realized price, before the effects of hedging
Net realized price, including the effects of hedging
Natural Gas (per Mcf):
NYMEX price
Realized price, before the effects of hedging
Net realized price, including the effects of hedging
For the Years Ended December 31,
2007
2008
2006
$
$
$
$
$
$
99.65
92.99
75.59
8.95
8.60
8.79
$
$
$
$
$
$
72.34
67.56
62.60
6.92
6.74
7.63
$
$
$
$
$
$
66.22
59.33
56.60
7.26
6.58
7.37
Average quarterly NYMEX crude oil prices increased 38 percent to $99.65 per barrel for the year ended
December 31, 2008, compared to $72.34 per barrel for 2007. The price of crude oil has been pressured downward
as a result of a forecasted decrease in global demand, which is a consequence of the broad economic slowdown.
The 36-month forward strip price for crude oil as of December 31, 2008, was $62.15 per barrel. On February 17,
2009, the 36-month forward contract had decreased from year-end by an additional 15 percent to $52.82 per
barrel. The near month price for crude oil as of December 31, 2008, was $44.60 per barrel. On February 17,
2009, the near month price had decreased from year-end by an additional 22 percent to $34.93 per barrel.
Average quarterly NYMEX natural gas prices increased 29 percent to $8.95 per Mcf for the year ended
December 31, 2008, compared to $6.92 per Mcf for 2007. Natural gas prices have been pressured downward in
recent months as a result of a forecasted decrease in global demand and over concerns of forecasted excess gas
supply that will be generated from the ramp up in the number of horizontal wells planned in a number of new
shale plays across the United States. The 36-month forward strip price for natural gas as of December 31, 2008,
was $6.90 per Mcf. On February 17, 2009, the 36-month forward contract had decreased from year-end by an
additional 12 percent to $6.07 per Mcf. The near month price for natural gas as of December 31, 2008, was $5.62
per Mcf. On February 17, 2009, the near month price had decreased from year-end by an additional 25 percent to
$4.20 per Mcf.
While changes in quoted NYMEX oil and Henry Hub natural gas prices are generally used as a basis for
comparison within our industry, the price we receive for oil and natural gas is affected by quality, energy content,
location, and transportation differentials for these products. We refer to this price as our realized price, which
43
excludes the effects of hedging. We are beginning to see wider differentials for both oil and natural gas in recent
months in regions that have high levels of industry activity. In particular, differentials for oil in the Williston
Basin have been pressured as activity in the area has accelerated in recent months and differentials for natural gas
in the Mid-Continent have widened as regional demand has not kept pace with the growth in supply generated by
several successful shale plays in the general vicinity. Our realized price is further impacted by the result of our
hedging contracts that are settled in the respective periods. We refer to this price as our net realized price. Our
net natural gas price realization for year ended December 31, 2008, was positively impacted by $14.0 million of
realized hedge gains and our net oil price realization was negatively impacted by $115.1 million of realized hedge
losses. On a percentage basis, we currently have hedged more forecasted crude oil production than forecasted
natural gas production using a combination of swaps and costless collars.
Hedging Activities
Hedging is an important part of our financial risk management program. The amount of production we
hedge is driven by the amount of debt on our consolidated balance sheet and the level of capital commitments we
have in place. In the case of a significant acquisition of producing properties, we will hedge in order to lock in a
portion of the economics assumed in the acquisition. Taking into account all oil and gas production hedge
contracts in place at December 31, 2008, we have hedged anticipated future production of approximately 8
million Bbls of oil, 54 million MMBtu of natural gas, and 1 million Bbl of natural gas liquids through the year
2011. We believe we have established an economic base for our future operations, and the spread between the
price floors and ceilings on our collars allows us to continue to participate in a higher oil and gas price
environment. Please see Note 10 – Derivative Financial Instruments of Part IV, Item 15 of this report for
additional information regarding our oil and gas hedges, and see the caption, Summary of Oil and Gas Production
Hedges in Place, later in this section.
Net Profits Plan
Payments made from the Net Profits Plan have been expensed as compensation costs in the amounts of
$51.5 million, $31.9 million, and $26.1 million for the years ended December 31, 2008, 2007, and 2006,
respectively. The actual cash payments we make are dependent on actual production, realized prices, and
operating and capital costs associated with the properties in each individual pool. Actual cash payments will be
inherently different from the estimated liability amounts. More detailed discussion is included in the analysis in
the Comparison of Financial Results and Trends sections below and in Note 11 – Fair Value Measurements in
Part IV, Item 15. An increasing percentage of the costs associated with the payments for the Net Profits Plan are
attributable to general and administrative expense as compared to exploration expense. This is a function of the
normal departure of employees who previously contributed to exploration efforts. We determined that because of
the change in circumstances, a greater percentage of the payments should be recorded as general and
administrative expense beginning in 2007. In December 2007, our Board approved an incentive compensation
plan restructuring, whereby the Net Profits Plan was replaced with a long-term incentive program utilizing
performance shares in 2008. As a result, the 2007 Net Profits Plan pool was the last pool established.
The calculation of the estimated liability for the Net Profits Plan is highly sensitive to our price estimates
and discount rate assumptions. For example, if we changed the commodity prices in our calculation by five
percent, the liability recorded on the balance sheet at December 31, 2008, would differ by approximately
$14 million. A one percentage point decrease in the discount rate would result in an increase to the liability of
approximately $9 million, while a one percentage point increase in the discount rate would result in a decrease to
the liability of approximately $8 million. We frequently re-evaluate the assumptions used in our calculations and
consider the possible impacts stemming from the current market environment including current and future oil and
gas prices, discount rates, and overall market conditions.
44
The table below provides information regarding selected production and financial information for the
quarter ended December 31, 2008, and the immediately preceding three quarters. Additional details of per MCFE
costs are contained later in this section.
December 31,
2008
For the Three Months Ended
June 30,
2008
September 30,
2008
March 31,
2008
(In millions, except production sales data)
30.0
27.7
28.6
28.3
$ 190.5
$ 44.8
$ 47.7
$
6.1
$ 11.8
$ 95.1
$ 17.7
$ 292.1
$ 34.7
$
9.5
$ 12.4
$ (126.0)
8%
(47)%
(184)%
9%
(8)%
(48)%
31%
65%
58320%
2792%
N/A
(49)%
(243)%
$ 358.5
$ (53.5)
43.6
$
6.6
$
22.5
$
72.4
$
10.7
$
0.5
$
$
$
$
$
1.2
-
24.1
88.0
(3)%
(10)%
(22)%
6%
18%
(17)%
(5)%
(39)%
(95)%
(43)%
N/A
10%
162%
$ 400.0
$ (68.4)
$ 41.0
$
5.6
$ 27.0
$ 76.4
$ 17.4
9.6
$
2.1
-
$
$
$ 21.9
$ 33.6
1%
29%
185%
17%
44%
32%
9%
22%
N/A
110%
N/A
4%
(65)%
$ 310.4
$ (24.0)
$ 35.1
$
3.9
$ 20.5
$ 70.4
$ 14.3
$
-
1.0
-
$
$
$ 21.1
$ 96.0
(1)%
13%
105%
(7)%
3%
7%
8%
(11)%
N/A
11%
N/A
39%
192%
Production (BCFE)
Oil and gas production revenue excluding
the effects of hedging
Realized oil and gas hedge gain (loss)
Lease operating expense
Transportation costs
Production taxes
DD&A
Exploration
Impairment of proved properties
Abandonment and impairment of unproved
properties
Impairment of goodwill
General and administrative expense
Net income
Percentage change from previous quarter:
Production (BCFE)
Oil and gas production revenue excluding
the effects of hedging
Realized oil and gas hedge gain (loss)
Lease operating expense
Transportation costs
Production taxes
DD&A
Exploration
Impairment of proved properties
Abandonment and impairment of unproved
properties
Impairment of goodwill
General and administrative expense
Net income
2008 Highlights
Emerging resource play potential. Throughout 2008 several new potential resource plays emerged in the
exploration and development industry, namely the Haynesville shale, the Eagle Ford shale, and the Marcellus
shale. We have exposure to each of these plays, which if successful could provide for significant future growth in
reserves and production. The Haynesville shale emerged early in 2008 in northern Louisiana and East Texas and
quickly became the hottest resource play in the country. As a result of our previous Cotton Valley and James
Lime activity, we already had an established acreage position in the area and now estimate that we have
approximately 50,000 net acres that may be prospective for the Haynesville shale. Our Eagle Ford shale position
in the Maverick Basin in South Texas was built through leasing efforts and a joint venture over the course of
2008. If we earn all of the acreage potential under the joint venture, St. Mary would control roughly 210,000 net
45
acres in this play. Lastly, late in 2008 we entered into two arrangements that could allow us to access 43,000 net
acres in the Marcellus shale in north central Pennsylvania.
Acquisitions and divestitures. We continue to optimize our portfolio of assets as part of our overall
strategic goals and objectives. As part of this strategy, on January 31, 2008, we completed the divestiture of
certain non-strategic oil and gas properties located primarily in the Rocky Mountain and Mid-Continent regions to
Abraxas Petroleum Corporation and Abraxas Operating, LLC. The cash received at closing was $129.6 million,
net of commission costs. The economics of the transaction were further enhanced by utilizing a tax-advantaged
exchange structure that will allow us to defer most of the gain on the sale. In June 2008 the Company completed
the divestiture of certain non-strategic oil and gas properties located in the Greater Green River Basin. We also
utilized a tax-advantaged exchange structure for this divestiture. The cash received at closing, net of all
commission costs, was $21.7 million. The final sale price is subject to normal post-closing adjustments and is
expected to be finalized during the first quarter of 2009. During 2008 we recorded a $63.6 million gain on the
sale of proved properties, which included the gain from the Abraxas and Greater Green River divestitures, as well
as other smaller divestitures.
On March 21, 2008, we closed on the acquisition of predominantly natural gas properties located in the
Carthage Field in Panola County, Texas. Total cash paid for the acquisition was $49.2 million, net of customary
closing adjustments. The acquisition was funded with cash on hand and borrowings under our existing revolving
credit facility. At the acquisition date, we estimated proved reserves associated with this acquisition of
approximately 25 BCFE. This acquisition was structured to qualify as the first step of a reverse like-kind
exchange. The second step of the like-kind exchange was partially completed in conjunction with the divestiture
of certain non-core oil and gas properties located in the Greater Green River Basin.
On December 31, 2008, we closed on a transaction whereby we received an increased interest in our
operated tight oil assets at Sweetie Peck in West Texas and approximately $17.6 million of cash in exchange for
our interests in the Judge Digby Field in Pointe Coupee Parish, Louisiana. The Sweetie Peck tight oil program
has a multi-year drilling inventory, with potential for increased density drilling, which we plan to exploit over the
coming years.
Effects of Hurricanes Gustav and Ike. During the third quarter of 2008, assets in which we have an
interest were impacted by Hurricanes Gustav and Ike. The most impactful damage caused by the storms was to
power and processing facilities and infrastructure in the Gulf Coast area, causing us to shut-in production
throughout our Gulf Coast region. We lost the Vermilion 281 producing platform in the Gulf of Mexico and
incurred damage to our Goat Island production facilities in Galveston Bay during Hurricane Ike. We are in the
process of assessing and remediating the damage related to the Vermilion 281 platform. Most of this expense will
be covered by insurance as noted below. The damage to two wells and our production facilities located at Goat
Island in Galveston Bay have been repaired and these wells were back on production by year-end 2008.
We also incurred minor damage to outside-operated properties from the hurricanes. Restoration of the
remaining shut-in production is largely dependent on repairs to transportation and processing facilities which are
owned and operated by others.
We maintain insurance that we expect to utilize with regard to the lost platform and repairs to various
other properties. Due to the severe damage caused by the hurricane, we currently expect that the remediation
costs related to the platform and the repairs to various other properties will exceed the maximum insurance policy
limit. We wrote off the carrying value of the Vermilion 281 platform, as well as the carrying value associated
with the Goat Island production facility assets. Additionally, we established an accrual for our estimate of the
remediation and various other property damage repair costs we expect to incur in excess of our maximum
insurance policy limit. As a result, we recorded a $7.0 million loss, which is included in other expense in the
accompanying consolidated statement of operations. Any variation between actual and estimated remediation and
damage repair costs will impact the final determination of the loss.
Repurchase of common stock. Throughout the first quarter of 2008, we repurchased a total of 2,135,600
shares of our common stock in the open market. The shares were repurchased at a weighted-average cost of
46
$36.13 per share, including commissions, using cash on hand and borrowings under our revolving credit facility.
These shares were purchased under a share repurchase program approved by the Board. At the time we
repurchased our shares, we entered into hedges for a commensurate amount of our production represented by the
share repurchase in order to lock in the discounted price at which our shares were trading. As of the date of this
filing, we are authorized to repurchase an additional 3,072,184 shares under this program.
SemGroup Bankruptcy. On July 22, 2008, SemGroup filed voluntary petitions for reorganization under
Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of
Delaware. Certain SemGroup entities purchased a portion of our crude oil production prior to their petition for
bankruptcy protection. As a result of the SemGroup bankruptcy filing, we recorded an allowance for doubtful
accounts and bad debt expense of $9.9 million in the second quarter of 2008 and increased the allowance and the
expense to $16.6 million during the third quarter of 2008. We believe we have fully allowed for all potential
uncollectible amounts and believe that we have no remaining exposure resulting from this bankruptcy. In an
effort to maximize our recovery, we have filed the appropriate pleadings and are party to certain adversary
proceedings in the SemGroup bankruptcy case to establish our secured and priority claims. This matter does not
have a materially adverse effect on our liquidity or overall financial position.
Senior management change. On March 21, 2008, David W. Honeyfield, Senior Vice President – Chief
Financial Officer and Secretary resigned as an officer. On September 8, 2008, A. Wade Pursell commenced
employment as Executive Vice President and Chief Financial Officer.
Performance share plan. During the fourth quarter of 2007 we decided to grant performance share
awards as the primary form of long-term equity incentive compensation for certain employees. Our Board of
Directors approved an amendment and restatement of the 2006 Equity Incentive Compensation Plan on
March 28, 2008, and the amended plan was approved by stockholders at our annual stockholders’ meeting on
May 21, 2008. We granted the first award of performance shares on August 1, 2008. The fair value associated
with this grant equaled $12.3 million. PSAs provide target awards that are earned over a three-year performance
period. We believe this new long-term equity incentive plan is more transparent than our previous long-term
incentive plans and will be more widely understood by our employees and our stockholders. Target awards will
be made at the beginning of the performance measurement period and will have a back-end weighted vesting
schedule and a multiplier factor based on total stockholder return and performance relative to our peers. At the
conclusion of the three-year performance measurement period, our TSR will be measured and compared against a
pre-established performance index consisting of companies similar to us. Depending on the results of that
measurement, the actual award made to a participant will be between zero and two times the target award. The
only market or performance condition that may result in an early payout determination is a change of control.
This plan and the cash bonus plan will be widely utilized within the organization, ensuring that the performance
of all eligible employees and executives is measured against consistent performance conditions.
Financial and production results. Our net income for the year ended December 31, 2008, was $91.6
million or $1.45 per diluted share compared to 2007 results of $189.7 million or $2.94 per diluted share. We
discuss these financial results and trends in more detail below.
47
The table below details the regional breakdown of our 2008 production.
ArkLaTex
Mid-
Continent
Gulf
Coast
2008 Production:
Oil (MBbl)
Gas (MMcf)
Equivalent (MMCFE)
Avg. Daily Equivalents
(MMCFE/per day)
Relative percentage
(1) Totals may not add due to rounding
159
17,599
18,554
50.7
16%
367
30,825
33,026
90.2
29%
230
12,886
14,270
39.0
12%
Permian
1,753
3,325
13,841
37.8
12%
Rocky
Mountain
Total(1)
4,106
10,275
34,910
95.4
31%
6,615
74,910
114,601
313.1
100%
In 2008 we experienced record production and strong operating cash flows. Our record production is a
realization of operational and investment decisions made in prior years as well as the current period. Our
operating margins remained strong in 2008 despite increasing operating costs. Our 2008 operating margin was
$7.75 per MCFE compared to $6.68 per MCFE in 2007.
Net cash provided by operating activities was $678.2 million, up eight percent from 2007. Average daily
production for the year increased six percent to a record 313.1 MMCFE. Our average net realized price increased
$1.40 to $10.11 per MCFE. Unit cost increased for the period as lease operating expenses increased $0.15 to
$1.46 per MCFE. While general industry costs associated with drilling and completing wells are flat or declining
year over year, costs related to the ongoing operation of oil and gas properties continue to experience upward
pressure. This increase over last year’s comparable period is driven by continued pressure on costs related to the
servicing of wells, such as disposal and trucking, as well as workover and labor costs. As a company with a
significant oil component in our production mix, our property base inherently requires more labor than operations
that are dominated by natural gas production. Labor costs continue to be a significant driver of our lease
operating expense. In addition to the higher costs we are incurring on our base activity, we have been actively
incurring workover expense to restore or increase production in the Gulf Coast and Rocky Mountain regions.
Transportation costs increased $0.05 per MCFE, or 36 percent to $0.19 per MCFE as compared to a year ago.
The increase is due to newly drilled wells with higher transportation costs. Production taxes increased $0.13 per
MCFE to $0.71 per MCFE and are a reflection of higher average commodity prices.
Depletion, depreciation, and amortization, including asset retirement obligation accretion expense,
increased $0.62 to $2.74 per MCFE. The depletion, depreciation, and amortization increase is reflective of higher
costs on a per MCFE basis for new reserve additions relative to the base cost of our oil and gas properties.
General and administrative expense increased $0.13 per MCFE to $0.69 per MCFE. The increase in general and
administrative expenses is driven by our growing employee base and higher payments from the Net Profits Plan.
Exploration expense for 2008 was $60.1 million, which was $1.4 million higher than the $58.7 million incurred
during 2007 due to an increase in exploration overhead offset by decreases in exploratory dry hole expense.
Impairment of proved properties for the year ended December 31, 2008, totaled $302.2 million. There
was no impairment of proved properties in 2007. The decrease in proved reserves described above caused the
majority of this pre-tax non-cash impairment of proved properties. The largest portion of the impairment was
$154.0 million related to assets in South Texas that were acquired in 2007. We also saw an impairment
associated with proved properties in the Gulf of Mexico, the greater Green River Basin in Wyoming, and our
coalbed methane project at Hanging Woman Basin. We discuss these financial results and trends in more detail
below.
Outlook for 2009
Unlike prior years, we enter 2009 without a firm dollar amount budgeted for exploration and production
activities. Our plan is to spend at or within cash flow for exploration and development activities in 2009. Given
the volatility of commodity prices in recent months, we have established a flexible program to deploy capital
48
rather than set a fixed number. Our first priority in 2009 is to test the potential of several of the emerging
resource plays where we have gained exposure in the past year. We plan to test wells in the Haynesville shale in
East Texas and northern Louisiana, the Marcellus shale in Pennsylvania, and the Eagle Ford shale in South Texas.
This testing is critical to growing the long-term value of the company and is likely to proceed unless we see
significant declines in commodity prices from current levels. Our second priority is rational development of
existing assets. We believe that with the significant decline in commodity prices, the exploration and production
industry will slow its level of activity which in turn will lead to a decline in the cost of services provided by the
oilfield service industry. We believe the prices for drilling and completion services will continue to decline
throughout 2009 as a result of continued decreasing rig utilization. Accordingly, we have chosen to defer much
of our capital investment with the goal of improving our returns on invested capital. With limited exceptions, we
do not have any significant long-term rig commitment or any meaningful issues with potential leasehold
expirations. As such, we believe we can be more patient than many of our competitors in choosing when to invest
capital. Most of our existing rig commitments will expire in the first half of 2009, and we will use very short-
term rig contracts to operate a significantly smaller rig fleet throughout 2009 than we used in 2008. We are
striving to maintain a high degree of flexibility in the current environment. Our objective is to be able to slow
down should economic conditions continue to warrant while preserving the ability to ramp up activity quickly
when industry conditions improve or with near term success from our multiple resource play tests this year.
49
A year to year overview of selected reserve, production and financial information, including trends:
$ 500,062
658,242
$1,158,304
$ 432,375
504,202
$ 936,577
$ 342,810
416,103
$ 758,913
24%
23%
As of and for the Years Ended December 31,
2007
2006
2008
Selected Operations Data (In Thousands, Except Price, Volume, and Per MCFE Amounts)
Total proved reserves
Oil (MMBbl)
Natural gas (Bcf)
BCFE
78.8
613.5
1,086.5
51.4
557.4
865.5
74.2
482.5
927.6
Net production volumes
Oil (MMBbl)
Natural gas (Bcf)
BCFE
Average daily production
Oil (MBbl)
Natural gas (MMcf)
MMCFE
Oil & gas production revenues
Oil production, including hedging
Gas production, including hedging
Total
Oil & gas production costs
Lease operating expenses
Transportation costs
Production taxes
Total
Average net realized sales price (1)
Oil (per Bbl)
Natural gas (per Mcf)
Per MCFE data
Average net realized price (1)
Lease operating expense
Transportation costs
Production taxes
General and administrative
Operating profit
Depletion, depreciation and amortization
6.6
74.9
114.6
18.1
204.7
313.1
6.9
66.1
107.5
18.9
181.0
294.5
6.1
56.4
92.8
16.6
154.7
254.2
$ 167,384
22,205
81,766
$ 271,355
$ 140,389
15,529
62,290
$ 218,208
$ 115,896
10,999
49,695
$ 176,590
$
$
75.59
8.79
$ 62.60
7.63
$
$
$
$
10.11
(1.46)
(0.19)
(0.71)
(0.69)
7.06
2.74
$
$
$
8.71
(1.31)
(0.14)
(0.58)
(0.56)
6.12
2.12
$
$
$
$
$
56.60
7.37
8.18
(1.25)
(0.12)
(0.54)
(0.42)
5.85
1.67
Financial information (In Thousands, Except Per Share Amounts):
Working capital (deficit)
Long-term debt
Stockholders’ equity
Net income
$
15,193
$ 587,500
$ 1,127,485
91,553
$
$ (92,604)
$ 572,500
$ 863,345
$ 189,712
Basic net income per common share
Diluted net income per common share
$
$
Basic weighted-average shares outstanding
Diluted weighted-average shares outstanding
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing
1.47
1.45
62,243
63,133
$
$
3.07
2.94
61,852
64,850
$ 22,870
$ 433,980
$ 743,374
$ 190,015
$
$
3.38
2.94
56,291
65,962
$ 678,221
$ (672,785)
$ 630,792
$ (803,872)
$ 467,700
$ (724,719)
Percent Change Between
2007/2006
2008/2007
(20)%
17%
7%
16%
6%
16%
24%
21%
15%
16%
11%
36%
22%
23%
15%
29%
116%
3%
31%
(52)%
(52)%
(51)%
1%
(3)%
8%
(16)%
24%
11%
4%
6%
5%
17%
7%
33%
5%
27%
(505)%
32%
16%
-%
(9)%
-%
10%
(2)%
35%
11%
activities
$
(42,815)
$ 215,126
$ 243,558
(120)%
(12)%
(1)
Includes the effects of our hedging activities.
We present this table as a summary of information relating to key indicators of financial condition and
operating performance that we believe are important.
50
Proved reserves decreased 20 percent to 865.5 BCFE at December 31, 2008, from 1,086.5 BCFE at
December 31, 2007. Please see Note 17 – Disclosures about Oil and Gas Producing Activities of Part IV, Item 15
of this report and the above discussion under the caption General Overview for additional details and discussion
on the individual components of the change. Over time, our ability to economically replace volumes produced
annually has proven to be a key factor that determines whether we are successful in achieving our goal of
increasing net asset value per share. The measure of our success will vary year-to-year due to changes in these
factors.
Changes in production volumes, oil and gas production revenues, and costs generally reflect the cyclical
and highly volatile nature of our industry. We present per MCFE information because we use this information to
evaluate our performance relative to our peers and to identify and measure trends that we believe require analysis.
We anticipate that oil and gas production expenses will decrease in 2009 due to our internal focus on managing
these costs and due to the effects that declining commodity prices are anticipated to have on direct costs of
services used to produce oil and natural gas. Additionally, many exploration and production companies have
begun to slow their activity, which should have a moderating impact on the upward cost pressure we have seen in
recent quarters. Production taxes are largely dependent on the prices we receive for oil and natural gas, in the
current environment we would expect them to decrease. Depreciation, depletion, and amortization generally has
been pressured upward in recent years as production related to higher cost properties acquired or developed
became a larger percentage of our production mix. However, as a result of our impairment of proved properties in
2008 we could see a decline in DD&A rate in 2009. Our general and administrative expense will be impacted by
cash payments made under the Net Profits Plan, which are impacted by realized prices. Part of executing our
business plan in 2008 consisted of adding employees, particularly lease operators who manage our operations in
the field. The increase in personnel would be expected to drive general and administrative costs higher in 2009.
Additionally, competition for personnel in the exploration and production industry remains aggressive, and we
have seen the cost to hire and retain personnel increase significantly.
We have in-the-money stock options, unvested RSUs, and PSAs that may be potentially dilutive
securities. These dilutive securities affect our earnings per share. Both basic and diluted earnings per share are
presented in the table above. We account for our 3.50% Senior Convertible Notes under the treasury stock
method. There is no impact on the diluted share calculation for the periods presented since the Company’s
average stock price for the relevant reporting periods has not exceeded the conversion price. The 3.50% Senior
Convertible Notes were issued April 4, 2007, and have not been dilutive for a reporting period since their
issuance. There were no potentially dilutive shares related to the PSAs included in the diluted earnings per share
calculation for the year ended December 31, 2008. A detailed explanation is presented under the caption
Earnings per Share included in Note 1 – Summary of Significant Accounting Policies, in Part IV, Item 15 of this
report.
Basic and diluted weighted-average common shares outstanding used in our 2008, 2007, and 2006
earnings per share calculations reflect our stock repurchases, offset by increases in outstanding shares related to
stock option exercises, ESPP shares issued, and vested RSUs. We issued 868,372 shares of common stock in
2008, 733,650 shares in 2007, and 1,489,636 shares in 2006 as a result of stock option exercises. These share
issuances were offset by the repurchase of 2,135,600 shares of common stock in 2008, 792,216 shares in 2007,
and 3,319,300 shares in 2006 through our stock repurchase plan. Additionally, the number of RSUs that vested in
2008, 2007, and 2006 were 291,659, 268,123, and 298,352, respectively.
Overview of Liquidity and Capital Resources
In order to maintain our current size or to meet our projected growth targets, we will have to effectively
invest capital into new projects and acquisitions. The following analysis and discussion includes our assessment
of market risk and possible effects of inflation and changing prices.
51
Sources of cash
Based on our current outlook, we expect our exploration and development budget to be at or within our
generated cash flow from operations in 2009. Accordingly, we do not expect to access the capital markets in
2009. Throughout 2008, we divested of non-core oil and gas properties. Net cash proceeds from these
transactions, after commission costs, were $178.9 million. We anticipate that we will continue to evaluate our
property base for the divestiture of properties that we consider non-core to our strategic goals. We currently have
identified assets that we intend to market for sale in 2009, however given our strong financial position we will not
be forced to sell these properties unless we receive appropriate value.
Our primary sources of liquidity are the cash provided by operating activities, debt financing, sales of
non-core properties, and access to capital markets. All of these sources can be impacted by the general condition
of the broad economy, our industry and by significant fluctuations in oil and gas prices, operating costs, and
volumes produced. We have no control over the market prices for oil and natural gas, although we are able to
influence the amount of our net realized revenues related to oil and gas sales through the use of derivative
contracts. A decrease in market prices would reduce expected cash flow from operating activities and could
reduce the borrowing base of our credit facility as well as the value of non-strategic properties we might consider
selling. Historically, decreases in market prices have limited our industry’s access to the capital markets. The
public debt markets for energy companies appear to be opening up in recent weeks after several months of being
closed as a result of broader issues in the financial markets caused by widely reported sub-prime and leveraged
loan market issues. Credit spreads have increased materially and the volume of transactions being placed in the
market are down dramatically. Equity and convertible debt financings are still an available alternative. This is a
result of the general strength reflected in the balance sheets of the companies in this industry as well as the
historically low credit defaults of energy companies. We do not anticipate any need to raise either public debt or
equity financing in the foreseeable future. We intend to rely on our credit facility for borrowings. However, a
significant transaction could necessitate raising additional public debt or equity financing.
Current credit facility
We have a revolving credit facility agreement with ten participating banks. Except for Wells Fargo Bank,
N.A., who recently merged with Wachovia Bank, National Association and represents 22 percent of the lending
commitment, no individual bank participating in the credit facility represents more than 11 percent of the lending
commitments under the credit facility. On October 1, 2008, the lending group redetermined our reserve-based
borrowing base under the credit facility at the previous amount of $1.4 billion. We have elected a commitment
amount of $500.0 million. We believe this commitment level is adequate for our near-term liquidity
requirements. The existing credit facility expires in April of 2010, and we have begun discussions with the banks
within the existing bank group, as well as banks not in the existing facility, about a new credit facility. Our
intention is to have a new credit facility in place during the first half of 2009.
As of February 17, 2009, we had $181.5 million of available borrowing capacity under this facility.
Interest and commitment fees are accrued based on the borrowing base utilization percentage. Euro-dollar loans
accrue interest at LIBOR plus the applicable margin from the utilization table located in Note 5 of Part IV, Item
15 of this report, and Alternate Base Rate loans accrue interest at Prime plus the applicable margin from the
utilization table. This reduces the amount available under the commitment amount on a dollar-for-dollar basis.
Borrowings under the facility are secured by mortgages on the majority of our oil and gas properties and pledge of
the common stock of our material subsidiary companies.
Our weighted-average interest rate paid in 2008 was 4.4 percent and included fees paid on the unused
portion of the credit facility aggregate commitment amount, amortization of deferred financing costs, and the
effects of interest rate swaps. We increased our net borrowings from the previous year by $15.0 million when
comparing the ending 2008 and 2007 balance sheet amounts. An increase in the average outstanding credit
facility balance throughout 2008, offset by a decrease in interest rates and a decrease in the amount of capitalized
interest of $1.7 million, resulted in higher interest expense of $20.3 million in 2008 compared with $19.9 million
in 2007.
52
We are subject to customary financial and non-financial covenants under our credit facility, including
limitations on dividend payments and requirements to maintain certain financial ratios, which include debt to
earnings before interest, taxes, depreciation, and amortization of less than 3.5 to 1.0 and a current ratio as defined
by our credit agreement of not less than 1.0. As of December 31, 2008, our debt to EBITDA ratio and current
ratio as defined by our credit agreement, were 0.75 and 1.73, respectively. We are in compliance with all
financial and non-financial covenants under this credit facility and expect to be in compliance for the foreseeable
future.
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.
Uses of cash
We use cash for the acquisition, exploration, and development of oil and gas properties, and for the
payment of debt obligations, trade payables, income taxes, common stock repurchases, and stockholder dividends.
During 2008 we spent $745.6 million of cash on capital development and $81.8 million of cash for property
acquisitions. These amounts differ from the cost incurred amounts based on the timing of cash payments
associated with these activities as compared to the accrual based activity upon which the costs incurred amounts
are presented. These cash flows were funded using cash inflows from operations, proceeds from the sale of
assets, and available borrowing capacity under our revolving credit facility.
Expenditures for exploration and development of oil and gas properties and acquisitions are the primary
use of our capital resources. We expect that our capital and exploration expenditures in 2009 will be within
operating cash flows. The amount and allocation of future capital expenditures will depend upon a number of
factors including the number and size of available economic acquisitions and drilling opportunities, our cash
flows from operating and financing activities, and our ability to assimilate acquisitions. Also the impact of oil
and gas prices on investment opportunities, the availability of capital and borrowing facilities, and the success of
our development and exploratory activities could 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,
acquisition opportunities, debt requirements, and other factors.
The current portion of our income tax expense was 32 percent of our total income tax expense for 2008.
We made estimated payments during the calendar year, and as of December 31, 2008, we anticipate an income tax
refund of $13.2 million will be due to the Company.
During 2008 we purchased 2,135,600 shares of our common stock in the open market at a weighted-
average price of $36.13, including commissions, for a total of $77.2 million. As of this filing date we have Board
authorization to repurchase up to an additional 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 existing bank credit
facility agreement, compliance with securities laws, and the terms and provisions of our stock repurchase
program.
In 2008 we paid $6.2 million in dividends to our stockholders. Our intention is to continue to make these
dividend payments for the foreseeable future subject to our future earnings, our financial condition, possible credit
facility covenants, and other currently unexpected factors which could arise.
53
The following table presents amounts and percentage changes between years in net cash flows from our
operating, investing, and financing activities. The analysis following the table should be read in conjunction with
our consolidated statements of cash flows in Part IV, Item 15 of this report.
Net Cash Provided By Operating Activities
Net Cash Provided By Investing Activities
Net Cash Provided By (Used In) Financing Activities
Amount of Changes Between
2007/2006
2008/2007
$ 163,092
$ 47,429
$ (79,153)
$ 131,087
$ (28,432)
$(257,941)
Percent of Change
Between
2008/2007
8%
(16)%
(120)%
2007/2006
35%
11%
(12)%
Analysis of cash flow changes between 2008 and 2007
Operating activities. Cash received from oil and gas production revenues, net of the realized effects of
hedging, increased $265.2 million to $1.2 billion for the year ended December 31, 2008. The increase was the
result of a seven percent increase in production and a 16 percent increase in our net realized price after hedging,
resulting in a 24 percent increase in production revenue. Included in the oil and gas production revenue amounts
is $101.1 million of net realized hedging losses. Net cash payments made for income taxes increased
$18.5 million due to fluctuating oil and gas prices which increased our estimated quarterly income tax payments
in 2008.
Investing activities. Total cash outflow for 2008 capital expenditures for leasehold and drilling activities
increased $107.9 million or 17 percent to $745.6 million. Total cash outflow for 2008 related to the acquisition of
oil and gas properties decreased $101.1 million or 55 percent to $81.8 million. Cash received from the sale of oil
and gas properties increased $178.4 million and deposits to restricted cash increased $14.4 million for the period
ended December 31, 2008, as compared to the same period in 2007.
Financing activities. Net repayments to our credit facility decreased $64.0 million for the period ended
December 31, 2008, compared to 2007. We received $280.7 million less during 2008, compared to the same
period in 2007, from the issuance of senior convertible debt. Our income tax benefit attributable to the exercise of
stock options increased $3.9 million to $13.9 million for the year ended December 31, 2008, compared with the
same period in 2007. We received $1.9 million more proceeds from the sale of common stock in 2008, compared
to 2007. Additionally, we invested $51.3 million more to repurchase shares of our common stock during 2008,
compared to 2007.
We had $6.1 million in cash and cash equivalents and working capital of $15.2 million as of
December 31, 2008, compared to $43.5 million in cash and cash equivalents and a working capital deficit of
$92.6 million as of December 31, 2007.
Analysis of cash flow changes between 2007 and 2006
Operating activities. Cash received from oil and gas production revenues, net of the realized effects of
hedging, increased $123.0 million to $925.1 million for the year ended December 31, 2007. Included in the oil
and gas production revenue amounts is $24.5 million of net realized hedging gains. The increase was the result of
a 16 percent increase in production and a six percent increase in our net realized price after hedging, resulting in a
23 percent increase in production revenue. Net cash payments made from income taxes decreased $26.7 million
relative to the prior year and the Company was able to deduct a larger amount of intangible drilling costs due to
the expanded 2007 capital program.
Investing activities. Net cash proceeds from an insurance settlement related to Hurricane Rita totaled
$5.9 million for the period ended December 31, 2007. Total cash outflow for 2007 capital expenditures for
leasehold and drilling activities increased $182.7 million or 40 percent to $637.7 million. Total cash outflow for
2007 related to the acquisition of oil and gas properties decreased $87.8 million or 32 percent to $182.9 million.
Cash received from short-term investments increased $1.4 million and deposits to short-term investments
54
increased $1.2 million for the period ended December 31, 2007, as compared to the same period in 2006. Cash
received from other sources for the period ended December 31, 2007 included a deposit of $10 million related to
the divestiture of non-core oil and gas assets that was completed on January 31, 2008.
Financing activities. Net repayments to our credit facility increased $383 million and payments to our
short-term note payable increased $4.5 million for the period ended December 31, 2007, compared to 2006. In
March 2007, we received $280.7 million, net of $6.8 million of deferred financing costs, from the issuance of the
3.50% Senior Convertible Notes. Our income tax benefit attributable to the exercise of stock options decreased
$6.2 million to $9.9 million for the year ended December 31, 2007. We received $7.7 million less from the sale
of common stock related to stock option exercises and issuances under the employee stock purchase plan in 2007,
compared to 2006. Additionally, we invested $97.2 million less to repurchase shares of our common stock during
2007, compared to the same period in 2006.
We had $43.5 million in cash and cash equivalents and had a working deficit of $92.6 million as of
December 31, 2007, compared to $1.5 million in cash and cash equivalents and working capital of $22.9 million
as of December 31, 2006. The large increase in the cash balance as of the end of 2007 compared to prior periods
was a reflection of timing of maturities of the LIBOR denominated tranches on our credit facility.
Capital Expenditures
The following table sets forth certain historical information regarding the costs incurred by us in our oil
and gas activities.
Development costs (1)
Exploration costs
Acquisitions
Proved properties
Unproved properties – acquisitions of
proved properties (2)
Unproved properties - other
2008
For the Years Ended December 31,
2007
(In thousands)
$ 591,013
111,470
$ 367,546
126,220
2006
$ 586,579
92,199
51,567
161,665
238,400
43,274
83,078
$ 856,697
23,495
38,436
$ 926,079
44,472
28,816
$ 805,454
Total, including asset retirement obligations (3)
(1) Includes capitalized interest of $3.7 million, $5.4 million, and $3.5 million in 2008, 2007, and 2006, respectively.
(2) Represents a portion of the allocated purchase price of unproved properties acquired as part of the acquisition of proved properties.
Refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale in Part IV, Item 15 of this report for additional information.
(3) Includes amounts relating to estimated asset retirement obligations of $15.4 million, $27.6 million, and $7.8 million in 2008, 2007,
and 2006, respectively.
Commodity Price Risk and Interest Rate Risk
We are exposed to market risk, including the effects of changes in oil and gas commodity prices and
changes in interest rates as discussed below under the caption “Summary of Interest Rate Hedges in Place.”
Changes in interest rates can affect the amount of interest we earn on our cash, cash equivalents, and short-term
investments and the amount of interest we pay on borrowings under our revolving credit facility. Changes in
interest rates do not affect the amount of interest we pay on our fixed-rate 3.50% Senior Convertible Notes, but do
affect their fair market value.
Since we produce and sell natural gas and crude oil, our financial results are affected when prices for
these commodities fluctuate. The following table reflects our estimate of the effect on net cash flows from
operations of a ten percent change in our average realized sales price, inclusive of the impact of hedging, for
natural gas, for oil, and in combination for the years presented. These amounts have been reduced by the effective
income tax rate applicable to each period since a reduction in revenue would reduce cash requirements to pay
55
income taxes. General and administrative expenses have not been adjusted. To fund the capital expenditures we
incurred in those years we would have been required to utilize amounts under our credit facility as a source of
funds. In each of these years we would have had sufficient borrowing base available under our credit facility to
meet this contingency without reducing or eliminating expenditures or altering our growth strategy.
Pro forma effect on net cash flow from
operations of a ten percent change
in average realized sales price:
2008
For the Years Ended December 31,
2007
(In thousands)
2006
Oil
Natural Gas
Total
$ 27,818
37,288
$ 65,106
$ 25,248
29,998
$ 55,246
$ 20,496
25,117
$ 45,613
We enter into hedging transactions in order to reduce the impact of fluctuations in commodity prices.
Note 10 – Derivative Financial Instruments of Part IV, Item 15 of this report contains important information about
our oil and gas derivative contracts, and additional information is below under the caption Summary of Oil and
Gas Production Hedges in Place. We do not anticipate significant changes in existing hedge contracts or
derivative contract transactions.
Summary of Oil and Gas Production Hedges in Place
Our oil and natural gas derivative contracts include swap and costless collar arrangements. All contracts
are entered into for other-than-trading purposes. Please refer to Note 10 – Derivative Financial Instruments in
Part IV, Item 15 of this report for additional information regarding accounting for our derivative transactions.
Our net realized oil and gas prices are impacted by hedges we have placed on future forecasted
production. We have historically entered into hedges of existing production around the time we make
acquisitions of producing oil and gas properties. Our intent has been to lock in a significant portion of an
equivalent amount of existing production to the prices we used to evaluate the risked economics of our
acquisitions. We have also hedged a portion of our forecasted production on a discretionary basis. As of
December 31, 2008, and through the date of this filing our hedged positions of anticipated production through
2011 totaled approximately 8 million Bbls of oil, 54 million MMBtu of natural gas, and 1 million Bbls of natural
gas liquids.
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 per unit of production 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.
56
The following table describes the volumes, average contract prices, and fair value of contracts we have in
place as of December 31, 2008. We seek to minimize basis risk and index the majority of our oil contracts to
NYMEX prices and our gas contracts to various regional index prices associated with pipelines in proximity to
our areas of gas production.
Oil contracts
Oil Swaps
Contract Period
Volumes
(Bbl)
Weighted-
Average
Contract
Price
(per Bbl)
Fair Value at
December 31, 2008
Asset/(Liability)
(in thousands)
411,000
$
71.66
$
9,344
First quarter 2009 -
NYMEX WTI
Second quarter 2009 -
NYMEX WTI
Third quarter 2009 -
NYMEX WTI
Fourth quarter 2009 -
NYMEX WTI
2010
401,000
$
71.65
389,000
$
71.59
369,000
$
71.67
7,131
5,673
4,535
3,430
NYMEX WTI
1,239,000
$
66.47
2011
NYMEX WTI
1,032,000
$
65.36
All oil swap contracts
3,841,000
(2,779)
$
27,334
Oil Collars
Contract Period
First quarter 2009
Second quarter 2009
Third quarter 2009
Fourth quarter 2009
2010
2011
All oil collars
NYMEX WTI
Volumes
(Bbl)
376,500
380,500
384,500
384,500
1,367,500
1,236,000
4,129,500
Weighted-
Average
Floor
Price
(per Bbl)
$
$
$
$
$
$
50.00
50.00
50.00
50.00
50.00
50.00
Weighted-
Average
Ceiling
Price
(per Bbl)
$ 67.31
$ 67.31
$ 67.31
$ 67.31
$ 64.91
$ 63.70
Fair Value at
December 31, 2008
Asset/(Liability)
(in thousands)
$
$
1,869
1,041
268
(475)
(8,067)
(12,338)
(17,702)
57
Gas Contracts
Gas Swaps
Contract Period
First quarter 2009
IF ANR OK
IF CIG
IF EL PASO
IF HSC
IF NGPL
IF PEPL
NYMEX Henry Hub
Second quarter 2009
IF ANR OK
IF CIG
IF EL PASO
IF HSC
IF NGPL
IF PEPL
NYMEX Henry Hub
Third quarter 2009
IF ANR OK
IF CIG
IF EL PASO
IF HSC
IF NGPL
IF PEPL
NYMEX Henry Hub
Fourth quarter 2009
IF ANR OK
IF CIG
IF EL PASO
IF HSC
IF NGPL
NYMEX Henry Hub
2010
IF ANR OK
IF EL PASO
IF HSC
IF NGPL
NYMEX Henry Hub
2011
IF EL PASO
IF HSC
Weighted-
Average
Contract
Price
(per MMBtu)
Fair Value at
December 31, 2008
Asset/(Liability)
(in thousands)
Volumes
(MMBtu)
580,000
930,000
300,000
2,490,000
130,000
1,500,000
300,000
570,000
930,000
300,000
2,700,000
120,000
1,500,000
300,000
100,000
300,000
300,000
2,680,000
100,000
360,000
330,000
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
8.96
8.72
7.85
9.41
7.71
9.10
10.13
7.47
7.11
6.64
8.09
6.63
7.17
8.47
7.11
6.64
6.94
8.25
6.86
7.47
8.59
90,000
150,000
300,000
2,620,000
90,000
350,000
$
$
$
$
$
$
$
7.43
7.42
7.01
8.60
7.14
8.98
8.25
60,000
1,090,000
6,080,000
60,000
1,440,000
880,000
360,000
$
$
$
$
$
$
$
7.98
6.79
8.40
7.60
8.66
6.34
9.01
2,594
4,220
938
10,222
418
7,072
1,292
1,458
3,103
537
6,744
258
4,121
785
213
695
458
6,032
159
821
796
151
437
376
5,935
129
761
89
563
9,377
66
2,062
(131)
478
All gas swap contracts
30,390,000
$
73,229
58
Gas Collars
Contract Period
Volumes
(MMBtu)
First quarter 2009
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
Second quarter 2009
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
Third quarter 2009
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
Fourth quarter 2009
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
2010
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
2011
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
All gas collars
600,000
210,000
1,365,000
90,000
600,000
210,000
1,375,000
90,000
600,000
210,000
1,385,000
90,000
600,000
210,000
1,385,000
90,000
2,040,000
600,000
4,945,000
240,000
1,800,000
480,000
4,225,000
120,000
23,560,000
Weighted-
Average
Floor
Price
(per MMBtu)
Weighted-
Average
Ceiling
Price
(per MMBtu)
Fair Value at
December 31, 2008
Asset/(Liability)
(in thousands)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
8.82
9.49
9.25
10.35
8.82
9.49
9.25
10.35
8.82
9.49
9.25
10.35
8.82
9.49
9.25
10.35
7.08
7.88
7.61
8.38
6.32
6.77
6.51
7.25
$
398
105
1,347
44
688
124
1,535
65
517
102
1,003
59
520
73
736
35
841
(154)
(15)
(42)
86
(398)
(2,237)
(81)
$
5,351
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
4.75
5.57
5.30
6.00
4.75
5.57
5.30
6.00
4.75
5.57
5.30
6.00
4.75
5.57
5.30
6.00
4.85
5.57
5.31
6.00
5.00
5.57
5.31
6.00
59
Natural Gas Liquid Contracts
Natural Gas Liquid Swaps
First quarter 2009
Second quarter 2009
Third quarter 2009
Fourth quarter 2009
2010
2011
All natural gas liquid swaps
Volumes
(Bbls)
264,000
262,000
218,000
70,000
140,000
20,000
974,000
Weighted-
Average
Contract
Price
(per Bbl)
$
$
$
$
$
$
41.47
41.53
41.46
45.95
49.59
49.01
Fair Value at
December 31, 2008
(in thousands)
$
4,570
4,410
3,370
1,335
2,998
375
$
17,058
Please see Note 10 – Derivative Financial Instruments in Part IV, Item 15 of this report for additional
information regarding our oil and gas hedges.
Summary of Interest Rate Hedges in Place
Effective September 13, 2007, we entered into a one year floating-to-fixed interest rate derivative contract
for a notional amount of $75 million. Under the agreement, we paid a fixed rate of 4.90 percent and were paid a
variable rate equal to the one-month LIBOR rate. This contract expired during the third quarter of 2008.
In relation to our 5.75% Senior Convertible Notes we entered into fixed-to-floating interest rate swaps on
$50 million of principal in October 2003. Due to an increase in interest rates, we entered into a floating-to-fixed
interest rate swap in April 2005 through the redemption date of the notes on March 20, 2007, for this same
notional amount of $50 million in order to effectively offset our fixed-to-floating interest rate swaps. Under the
floating-to-fixed interest rate swap, we were paid a variable interest rate of 235 basis points above the six-month
LIBOR rate as determined on the semi-annual settlement date and paid a fixed interest rate of 6.85 percent. The
impact of this instrument, when combined with the other interest rate swaps, was that we fixed the net liability
related to the interest rate swaps, and paid a 1.1 percent interest rate on $50 million of notional debt through
March 2007. The payment dates of the swap matched exactly with the interest payment dates of the 5.75% Senior
Convertible Notes and the fixed-to-floating interest rate swaps. All of the interest rate hedges related to the
5.75% Senior Convertible Notes expired in March 2007.
Market risk is estimated as the potential change in fair value resulting from an immediate hypothetical
one percentage point parallel shift in the yield curve. For fixed-rate debt, interest changes affect the fair market
value but do not impact results of operations or cash flows. Conversely, interest rate changes for floating-rate
debt generally do not affect the fair market value but do impact future results of operations and cash flows,
assuming other factors are held constant. The carrying amount of our floating-rate debt typically approximates its
fair value. We had $300 million of floating-rate debt outstanding as of December 31, 2008. Our fixed-rate debt
outstanding at this same date was $287.5 million.
Please see Note 10 – Derivative Financial Instruments in Part IV, Item 15 of this report for additional
information regarding our interest rate swaps.
60
Schedule of contractual obligations
The following table summarizes our future estimated principal payments and minimum lease payments
for the periods specified (in millions):
Contractual Obligations
Total
Less than
1 year
1-3 years
3-5 years
More than
5 years
Long-Term Debt
Operating Leases
Other Long-Term Liabilities
$ 620.2
46.2
257.6
$ 10.1
33.3
60.1
$ 320.1
10.5
111.5
$ 290.0
2.2
59.7
$
-
0.2
26.3
Total
$ 924.0
$ 103.5
$ 442.1
$ 351.9
$ 26.5
This table includes our 2008 minimum pension contribution of $395,000 expected to be paid in the
second quarter of 2009. The table also includes the remaining unfunded portion of our estimated pension liability
of $8.2 million even though we recognize that we cannot determine with accuracy the timing of future payments.
We made payments of $2.5 million, $2.2 million, and $1.3 million in 2008, 2007, and 2006, respectively, towards
the pension liability. We have included $178.8 million in other long-term liabilities, which represents six years of
undiscounted forecasted payments for the Net Profits Plan. Payments are expected to be similar on an annual
basis for the years beyond what is shown in this table. The amounts recorded on the consolidated balance sheets
reflect the impact of discounting and therefore differ 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 that we cannot control. The components of the operating leases are discussed in more detail in Note 6 –
Commitments and Contingencies of Part IV, Item 15 of this report.
The scheduled repayment of the long-term credit facility is 2010. Accordingly, it has been disclosed in
the table as such. Since this is a revolving credit facility, the actual payments will vary significantly. We
anticipate refinancing this obligation. For purposes of this table, we assume we will net share settle the 3.50%
Senior Convertible Notes. Accordingly, $32.7 million of interest payments related to the 3.50% Senior
Convertible Notes are included in the table above. We have excluded asset retirement obligations because we are
not able to accurately predict the precise timing of these amounts. Pension liabilities and asset retirement
obligations are discussed in Note 8 – Pension Benefits and Note 9 – Asset Retirement Obligations of Part IV, Item
15, respectively, and the Net Profits Plan is discussed in Note 7 – Compensation Plans of Part IV, Item 15 of this
report.
This table also includes estimated oil and natural gas derivative payments of $54.9 million based on
future market prices as of December 31, 2008. This amount represents only the cash outflows; it does not include
oil and gas receipts of $163.0 million that would be paid based on December 31, 2008, market prices. The net of
$108.1 million represents cash flows from the intrinsic value of our swap and collar arrangements and differs in
amount from our recorded fair value, which as of December 31, 2008, was a net asset of $105.3 million. The fair
value considers time value, volatility and the risk of non-performance for the Company and for the Company’s
counterparties. Both the intrinsic value and fair value will change as oil and natural gas commodity prices
change. Please refer to the discussion above under the caption Summary of Oil and Gas Production Hedges in
Place in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations
and to Note 10 – Derivative Financial Instruments in Part IV, Item 15 of this report for additional information
regarding our oil and gas hedges.
We believe that we will continue to pay annual dividends of $0.10 per share. We anticipate making cash
payments for income taxes, dependent on net income and capital spending.
61
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, 2008, we have not been involved in any
unconsolidated SPE 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
We are engaged in the exploration, exploitation, development, acquisition, and production of natural gas
and crude oil. 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
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 decisions affecting the estimates we use on historical experience and various other sources that are
believed to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due
to changes in business conditions or unexpected circumstances. Policies we believe are critical to understanding
our business operations and results of operations are detailed below. For additional information on our significant
accounting policies refer to Note 1 – Summary of Significant Accounting Policies, Note 9 – Asset Retirement
Obligations, and Note 17 – Disclosures About Oil and Gas Producing Activities in Part IV, Item 15 of this report.
Oil and gas reserve quantities. Estimated reserve quantities and the related estimates of future net cash
flows are critical estimates for an exploration and production company because they affect the perceived value of
our Company, are used in comparative financial analysis ratios and are used as the basis for the most significant
accounting estimates in our financial statements. The significant accounting estimates include the periodic
calculations of depletion, depreciation, and impairment of our proved oil and gas properties and the estimates of
our liability for future payments under the Net Profits Plan. Future cash inflows and future production and
development costs are determined by applying benchmark prices and costs, including transportation, quality, and
basis differentials, in effect at the end of each period to the estimated quantities of oil and gas remaining to be
produced as of the end of that period. Expected cash flows are reduced to present value using a discount rate that
depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure
calculations required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities, requires a ten 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 or as oil and gas prices and operating and capital costs change. We evaluate and estimate our
oil and gas reserves at December 31 and June 30 of each year. For purposes of depletion, depreciation, and
impairment, reserve quantities are adjusted at all interim periods for the estimated impact of additions and
dispositions. Changes in depletion, depreciation, or impairment calculations caused by changes in reserve
quantities or net cash flows are recorded in the period that the reserve estimates change.
62
The following table presents information regarding reserve changes from period to period that reflect
changes from items we do not control, such as price, and from changes resulting from better information 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,
2007
2008
BCFE
BCFE
Change
Change
2006
BCFE
Change
Revisions resulting from price changes
Revisions resulting from performance
Total
(199.7)
(44.5)
(244.2)
34.5
6.4
40.9
(52.2)
66.3
14.1
Over the three-year period, excluding divestitures, we have added 451.8 BCFE of reserves. Of these,
28.2 BCFE, or six percent, was a result of changes in estimates based on the performance of our oil and gas
properties. A 217.4 BCFE decrease in reserves was a result of price changes. As previously noted, oil and gas
prices are volatile, and estimates of reserves are inherently imprecise. Consequently, we anticipate we will
continue to experience these types of changes.
The following table reflects the estimated BCFE change and percentage change to our total reported
reserve volumes from the described hypothetical changes:
2008
For the Years Ended December 31,
2007
2006
BCFE
Change
Percentage
Change
BCFE
Change
Percentage
Change
BCFE
Change
Percentage
Change
A 10% decrease in pricing
A 10% decrease in proved
(120.8)
(14)%
(16.3)
(2)%
undeveloped reserves
(15.0)
(2)%
(25.0)
(2)%
(28.2)
(20.0)
(3)%
(2)%
Additional reserve information can be found in the reserve table and discussion included in Item 2 of Part
I of this report.
Successful efforts method of accounting. Generally accepted accounting principles provide 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, and a detailed description is included in Note 1 of
Part IV, Item 15 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 natural gas and crude oil. 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 ten percent change in our year-end revenue accrual would have
impacted net income before tax by $8.5 million in 2008.
63
Crude oil and natural gas hedging. Our crude oil and natural gas hedging contracts are intended and
usually qualify for cash flow deferral hedge accounting under SFAS No. 133. Under this accounting
pronouncement a majority of the gain or loss from a contract qualifying as a cash flow hedge is deferred as to
statement of operations recognition. The position reflected in the statement of operations is based on actual
settlements. If our natural gas and crude oil hedge contracts did not qualify for hedge accounting treatment or we
chose not to use this hedge accounting methodology, our periodic consolidated statements of operations could
include significant changes in the estimate of non-cash derivative gain or loss due to swings in the value of these
contracts. Consequently, we would report a different amount of oil and gas hedge loss in our statements of
operations. These fluctuations could be especially significant in a volatile pricing environment such as what we
have encountered over the last three years. The amounts recorded to accumulated other comprehensive income
(loss) of $223.5 million of income, $170.0 million of loss, and $69.0 million of income for 2008, 2007, and 2006
respectively, would have increased or decreased net income after tax if our hedges did not qualify as cash flow
deferral hedges under SFAS No. 133.
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 oil
and gas reserves, recurring and workover lease operating expense, production and ad valorem tax rates, present
value discount factors, and pricing assumptions. Additional discussion is included in the analysis in the above
section titled Overview of the Company, under the heading Net Profits Plan. In December 2007 our Board
approved an incentive compensation plan restructuring whereby the Net Profits Plan was replaced with a long-
term incentive program utilizing performance shares. As a result, the 2007 Net Profits Plan pool was the last pool
established.
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 rate to use. The impact to the consolidated statement of operations from these estimates is
reflected in our depreciation, depletion, and amortization calculations and occurs over the remaining life of our oil
and gas properties.
Valuation of long-lived and intangible assets. Our property and equipment are recorded at cost. 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. We evaluate the realizability of our proved properties and
other long-lived assets whenever events or changes in circumstances indicate that impairment may be appropriate.
Our impairment test compares the expected undiscounted future net revenues from property, using escalated
pricing, with the related net capitalized cost of the property at the end of each period. When the net capitalized
costs exceed the undiscounted future net revenue of a property, the cost of the property is written down to our
estimate of fair value, which is determined by applying a discount rate that we believe is indicative of the current
market. Our criteria for an acceptable internal rate of return are subject to change over time. Different pricing
assumptions or discount rates could result in a different calculated impairment. We recorded a $302.2 million
impairment of proved oil and gas properties in 2008. This impairment was primarily due to downward price
adjustments to reserves and declining performance for properties primarily located in the Gulf Coast and in South
Texas, as well as for gas properties in the Rocky Mountain region.
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 in accordance with SFAS No. 109. 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 determining 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 used and actual amounts we report are recorded in the periods in which we file our income tax
64
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 change in our effective tax rate would have changed our
calculated income tax expense by $1.5 million for the year ended December 31, 2008.
Additional Comparative Data in Tabular Format:
Oil and Gas Production Revenues:
Increase in oil and gas production revenues, net of hedging
Change Between Years
2008 and 2007
2007 and 2006
(in thousands)
$
221,727
$
177,664
Components of Revenue Increases (Decreases):
Oil
Realized price change per Bbl, net of hedging
Realized price percent change
Production change (MBbl)
Production percentage change
Natural Gas
Realized price change per Mcf, net of hedging
Realized price percentage change
Production change (MMcf)
Production percentage change
$
$
$
$
12.99
21%
(292)
(4)%
1.16
15%
8,849
13%
6.00
11%
851
14%
0.26
4%
9,613
17%
Our product mix as a percentage of total oil and gas revenue and production:
Revenue
Oil
Natural Gas
Production
Oil
Natural Gas
Years Ended December 31,
2007
46%
54%
2008
43%
57%
2006
45%
55%
35%
65%
39%
61%
39%
61%
65
Information regarding the effects of oil and gas hedging activity:
Years Ended December 31,
2007
2006
2008
Oil Hedging
Percentage of oil production hedged
Oil volumes hedged (MBbl)
Decrease in oil revenue
Average realized oil price per Bbl before hedging
Average realized oil price per Bbl after hedging
61%
4,022
$(115.1 million)
92.99
$
75.59
$
66%
4,565
$(34.3 million)
67.56
$
62.60
$
66%
4,021
$(16.6 million)
59.33
$
56.60
$
Natural Gas Hedging
Percentage of gas production hedged
Natural gas volumes hedged (MMBtu)
Increase in gas revenue
Average realized gas price per Mcf before hedging $
$
Average realized price per Mcf after hedging
46%
36.4 million
$ 14.0 million
8.60
8.79
46%
32.5 million
$ 58.7 million
6.74
$
7.63
$
40%
24.2 million
$ 44.7 million
6.58
$
7.37
$
Information regarding the components of exploration expense:
Summary of Exploration Expense (in millions)
Geological and geophysical expenses
Exploratory dry holes
Overhead and other expenses
Total
$
$
Years Ended December 31,
2007
2006
2008
14.2
6.8
39.1
60.1
$
$
17.0
14.4
27.3
58.7
$
$
9.5
10.2
32.2
51.9
Comparison of Financial Results and Trends between 2008 and 2007
Oil and gas production revenue. Production increased seven percent to 114.6 BCFE for the year ended
December 31, 2008, compared with 107.5 BCFE for the year ended December 31, 2007. Production for the year
ended December 31, 2007, includes approximately 6.8 BCFE related to non-core properties divested throughout
2008. The following table presents the regional changes in our production and oil and gas revenues and costs
between the two years:
Average Net Daily
Production
Added/(Lost)
(MMCFE)
12.8
(2.8)
10.8
8.5
(10.7)
18.6
ArkLaTex
Mid-Continent
Gulf Coast
Permian
Rocky Mountain
Total
$
Pre-Hedge
Oil and Gas
Revenue Added
(In millions)
76.1
30.4
75.4
85.6
79.8
347.3
$
$
Production
Costs Increase
(In millions)
8.3
3.9
17.5
11.5
11.9
53.1
$
We grew daily production by approximately 18.6 MMCFE during 2008 compared to 2007. The largest
regional increase occurred in the ArkLaTex region as a result of the success in the Cotton Valley and James Lime
programs. Production in the Gulf Coast region increased as a result of two acquisitions of properties targeting the
shallow Olmos gas formation that were made in the second half of 2007 as well as several successful offshore
wells. The production growth in the Permian region is the result of continued development of the Wolfberry
66
assets at Sweetie Peck and Halff East. The declines in production in the Mid-Continent and Rocky Mountain
regions are the result of the divestiture of non-core properties in these regions, which resulted in a smaller
production base for 2008.
Oil and gas realized hedge gain (loss). We recorded a realized hedge loss of $101.1 million for the year
ended December 31, 2008, mainly related to settlements on oil hedges. For the year ended December 31, 2007,
we recorded a realized hedge gain of $24.5 million mainly due to favorable settlements on natural gas hedges.
Marketed gas system revenue and expense. Marketed gas system revenue increased $32.2 million to
$77.4 million for the year ended December 31, 2008, compared with $45.1 million for the comparable period of
2007. Concurrent with the increase in marketed gas system revenue, marketed gas system expense increased
$29.7 million to $72.2 million for the year ended December 31, 2008, compared with $42.5 million for the
comparable period of 2007. The net margin has stayed consistent with historical performance. We expect that
marketed gas system revenue and expense will continue to coincide with increases and decreases in production and
our net realized price.
Other revenues. Other revenues decreased $6.6 million to $2.1 million for the year ended
December 31, 2008, compared with $8.7 for 2007. The decrease is due primarily to a $5.2 million gain
recognized in 2007 associated with a global insurance settlement attributed to Hurricane Rita. As of December
31, 2008, all Hurricane Rita plugging and abandonment activities have been completed.
Gain on sale of proved properties. We recorded a gain on sale of proved properties of $63.6 million for
the year ended December 31, 2008, mainly related to the Abraxas divestiture in January of 2008. The final gain
on sale of proved properties will be adjusted for normal post-closing adjustments and is expected to be finalized
during the first quarter of 2009. We expect to continue to evaluate potential divestitures of non-strategic
properties.
Oil and gas production expenses. Total production costs increased $53.1 million or 24 percent to
$271.4 million for 2008, from $218.2 million in 2007. Total oil and gas production costs per MCFE increased
$0.33 to $2.36 for 2008, compared with $2.03 for 2007. This increase is comprised of the following:
A $0.05 increase in overall transportation cost on a per MCFE basis was driven by the addition of
Olmos shallow gas assets in the Maverick Basin that were acquired in the fourth quarter of 2007, as
well as recently completed wells which have higher transportation costs
A $0.13 increase in production taxes on a per MCFE basis due to the increase in realized prices
between periods, particularly in the oil-weighted Rocky Mountain and Permian regions
A $0.10 increase in recurring lease operating expense on a per MCFE basis is related to higher costs,
particularly in oil-weighted regions, for items such as fuel and fluid disposal and an increase in the
Gulf Coast region due to wells acquired and developed in South Texas during the fourth quarter of
2007
A $0.05 overall increase in workover lease operating expense on a per MCFE basis relating to
workover charges in the Mid-Continent and Gulf Coast regions.
Depletion, depreciation, amortization and asset retirement obligation liability accretion. DD&A
increased $86.7 million, or 38 percent, to $314.3 million in 2008 compared with $227.6 million in 2007. DD&A
expense per MCFE increased 29 percent to $2.74 in 2008 compared to $2.12 in 2007. This increase is due to a
higher per unit rate associated with our acquisition and drilling costs in 2008 and 2007 caused by overall upward
cost pressure in the industry in recent years. Additionally, this increase reflects the costs of production facilities in
the offshore Gulf Coast that have increased significantly in recent years and that are now impacting our DD&A
rate as those projects begin production. The DD&A per MCFE rate was further affected by downward revisions
of 244.2 BCFE of proved reserves due to pricing and performance between December 31, 2008, and
December 31, 2007, causing a general increase in DD&A.
67
Exploration expense. Exploration expense increased $1.4 million or two percent to $60.1 million in 2008
compared with $58.7 million for 2007. The increase is due to a $2.8 million increase in drilling arrangements and
a $9.0 million increase in exploration overhead. These increases were offset by a $2.8 million decrease in
geological and geophysical expense as well as a $7.6 million decrease related to exploratory dry hole expense due
to fewer and less expensive dry holes.
Impairment of proved properties. We recorded a $302.2 million impairment of proved oil and gas
properties in 2008 compared to no impairment in 2007. This impairment was primarily due to downward price
adjustments to reserves and declining performance for properties primarily located in the Gulf Coast and in South
Texas, as well as for gas properties in the Rocky Mountain region. Further decreases in oil and gas commodity
prices could cause additional impairments of proved properties.
Impairment of Goodwill. We recorded a $9.5 million impairment of goodwill in 2008. The goodwill was
the result of our purchase of Agate Petroleum, Inc. in January 2005. The impairment was a result of downward
price adjustments to reserves for properties located in our Mid-Continent and Rocky Mountain regions and
represented our entire goodwill balance.
Abandonment and impairment of unproved properties. During the year, we abandoned or impaired
$39.0 million of unproved properties. Approximately $13.4 million related to acreage to which we had assigned
value in 2007 acquisitions targeting the Olmos shallow gas formation. The remaining write-offs relate to acreage
that we believe we either will not be able to hold in the current period of limited capital availability or to acreage
that we do not believe will be prospective. If commodity prices continue to decline we could see additional
abandonments and impairments of unproved property as we have less capital to invest for exploration and
development activities.
General and administrative. General and administrative expenses increased $19.4 million or 32 percent
to $79.5 million for 2008, compared with $60.1 million for 2007. G&A increased $0.13 to $0.69 per MCFE for
2008 compared to $0.56 per MCFE for the same period in 2007 as G&A grew at a faster rate than the seven
percent increase in production. A significant increase in employee count has resulted in an increase in base
employee compensation, including taxes and benefits, of approximately $23.9 million between 2008 and 2007. A
significant driver of this headcount increase has been the conversion from contract lease operators to internal lease
operators.
An increase in 2008 oil and gas commodity prices triggered additional Net Profits Plan. Additionally, an
increased percentage of the distribution dollars under the Net Profits Plan associated with general and
administrative expense contributed to the current period realized expense associated with the Net Profits Plan
increase by $4.4 million in 2008 compared with the same period in 2007. In the current commodity price
environment, we do not expect this trend to continue in 2009.
Cash bonus and long-term incentive compensation expense increased by $8.4 million for the year ended
December 31, 2008, compared with the same period in 2007. The increase results from the application of the
Cash Bonus Plan as amended on March 28, 2008 and an increase in our employee count.
The amounts described above were offset by a $9.1 million increase in the amount of G&A that was
allocated to exploration expense and an $8.2 million increase in COPAS overhead reimbursements. COPAS
overhead reimbursements from operations increased due to an increase in our operated well count from our
drilling program.
Change in Net Profits Plan liability. For the year ended December 31, 2008, this non-cash item was a
benefit of $34.0 million compared to an expense of $50.8 million for the same period in 2007. Significant
decreases in oil and gas commodity prices during the last half of 2008 and payments out of the plan have
decreased the estimated liability for the future amounts to be paid to plan participants. This liability is a
significant management estimate. Adjustments to the liability are subject to estimation and may change
dramatically from period to period based on assumptions used for production rates, reserve quantities, commodity
pricing, discount rates, tax rates, and production costs.
68
Bad debt expense. We recorded $16.7 million of bad debt expense in 2008, of which $16.6 million was a
result of SemGroup, L.P. and certain of its North American subsidiaries filing for bankruptcy protection. Certain
SemGroup entities had purchased a portion of our crude oil production. This amount related to oil produced in
June and July of 2008 that was fully reserved in the year ended December 31, 2008.
Interest expense. Interest expense increased by $380,000 to $20.3 million for 2008 compared to
$19.9 million for 2007. The increase reflects an increase in our average outstanding borrowings offset by lower
interest rates in 2008 compared with 2007. We also capitalized $3.7 million of interest in 2008 compared to
$5.4 million in 2007.
Income tax expense. Income tax expense totaled $59.9 million for 2008 and $110.6 million for 2007,
resulting in effective tax rates of 39.5 percent and 36.8 percent, respectively. The effective rate change from 2007
was primarily due to the impact of goodwill impairment, changes in the mix of the highest marginal state tax
rates, and also reflects other permanent differences including differing estimated effects between years of the
domestic production activities deduction.
The current portion of income tax expense in 2008 is $19.2 million compared to $17.6 million in 2007.
These amounts are 32 percent and 16 percent of the total income tax expense for the respective periods.
Comparison of Financial Results and Trends between 2007 and 2006
Oil and gas production revenue. Production increased 16 percent to 107.5 BCFE for the year ended
December 31, 2007, compared with 92.8 BCFE for the year ended December 31, 2006. The following table
presents the regional changes in our production and oil and gas revenues and costs between the two years:
Average Net Daily
Production
Added/(Lost)
(MMCFE)
8.9
11.3
1.6
20.7
(2.2)
40.3
$
Pre-Hedge
Oil and Gas
Revenue Added
(In millions)
27.2
40.1
8.7
91.7
13.7
$ 181.4
ArkLaTex
Mid-Continent
Gulf Coast
Permian
Rocky Mountain
Total
$
Production
Costs Increase
(In millions)
2.8
4.7
5.0
15.3
13.8
41.6
$
The revenue increase in this table also reflects the difference in oil and gas prices received between the
comparable periods. The production increases are offset by natural declines in production from older properties
to result in the net increase in production between the years presented. Additional production costs reflect
increases resulting from inflation and competition for resources.
Oil and gas realized hedge gain (loss). The 13 percent decrease in total oil and gas hedge gain to
$24.5 million was caused by a change in the composition of our hedge position and changes in oil and gas
commodity prices.
Marketed gas system revenue and expense. Marketed gas system revenue increased $24.2 million to
$45.1 million for the year ended December 31, 2007, compared with $20.9 million for the comparable period of
2006. The increase is due to the addition of a new marketed gas system in western Oklahoma that increased the
number of wells for which we currently market gas, as well as increased production in the Woodford shale
formation located in Coal County, Oklahoma. Concurrent with the increase in marketed gas system revenue,
marketed gas system expense increased $24.0 million to $42.5 million for the year ended December 31, 2007,
compared with $18.5 million for the comparable period of 2006.
69
Other revenues. Other revenues increased $7.8 million to $8.7 million for the year ended
December 31, 2007, compared with $942,000 for the comparable period of 2006. The increase is due primarily to
a $5.2 million gain associated with a global insurance settlement attributable to Hurricane Rita. The gain
calculation is net of approximately $12.1 million of costs associated with the plugging and abandonment of one
offshore platform.
Oil and gas production expenses. Total production costs increased $41.6 million or 24 percent to
$218.2 million for 2007, from $176.6 million in 2006. Our 2007 and 2006 acquisition of properties added
$13.6 million of incremental production costs, and other wells completed in 2006 and 2007 added $13.7 million
of incremental production costs in 2007 that were not reflected in 2006. The production cost increases are offset
by natural declines in production costs from older properties to result in the net increase in production costs
between the years presented. We experienced an increase in production taxes consistent with the increase in
revenue from higher realized prices.
Total oil and gas production costs per MCFE increased $0.12 to $2.03 for 2007, compared with $1.91 for
2006. This increase is comprised of the following:
A $0.02 increase in overall transportation cost due to an increase in the Rocky Mountain region
resulting from a change in the sale measurement point, as well as newly drilled wells with higher
transportation costs
An $0.11 increase in recurring lease operating expense related to continued cost pressure from the oil
and gas service sector
A $0.05 overall decrease in lease operating expense relating to workover expense, primarily in the
Rockies
A $0.04 increase in production taxes related to increased production in the Permian region.
Depletion, depreciation, amortization and asset retirement obligation liability accretion. DD&A
increased $73.1 million, or 47 percent, to $227.6 million in 2007 compared with $154.5 million in 2006. DD&A
expense per MCFE increased 27 percent to $2.12 in 2007 compared to $1.67 in 2006. The increase reflects
overall upward cost pressure in the industry and specifically our drilling in 2007 and 2006 that added costs at a
higher per unit rate relative to the prior year’s base. The DD&A per MCFE rate was further affected by upward
adjustments to reserves due to pricing differences between December 31, 2007, and December 31, 2006 although
this had the impact of lowering DD&A.
Exploration expense. Exploration expense increased $6.8 million or 13 percent to $58.7 million in 2007
compared with $51.9 million for 2006. This increase is due to a $7.5 million increase in geologic and geophysical
expense to support a larger overall program as well as a $4.2 million increase in exploratory dry hole expense
related to three wells located in the Gulf Coast region and one in the Rockies region. These increases were offset
by a $4.9 million decrease in exploration overhead expense related to a reduction in amounts recorded in
exploration expense related to payments under the Net Profits Plan. In 2007, we had a change in our accounting
estimate to reflect the view that Net Profits Plan distributions should be reclassified to exploration overhead only
for individuals who are currently employed by us and who continue to be involved in our exploration efforts.
Therefore Net Profits Plan payments associated with the distributions under the Net Profits Plan for ex-employees
were reclassified to general and administrative expense since there is no longer any functional link to exploration
expense as there is by definition no periodic cost associated with geologic, geophysical and exploration related
work by those ex-employees.
General and administrative. General and administrative expenses increased $21.3 million or 55 percent
to $60.1 million for 2007, compared with $38.9 million for 2006. G&A increased $0.14 to $0.56 per MCFE for
2007 compared to $0.42 per MCFE for the period in 2006 as G&A grew at a faster rate than the 16 percent
increase in production. A 23 percent increase in employee count has contributed to an increase in base employee
70
compensation, including taxes and benefits, of approximately 29 percent, or $8.5 million, between the year ended
December 31, 2007, and the same period of 2006.
An increase in oil and gas prices in 2007 triggered additional Net Profits Plan payouts and has increased
the amounts payable to plan participants. Additionally, an increased percentage amount of the distribution dollars
under the Net Profits Plan associated with general and administrative expense contributed to the 2007 realized
expense associated with the Net Profits Plan increased by $5.8 million in 2007 compared with the same period in
2006. An increase in employee count resulted in an increase in cash bonus expense of $2.4 million to $5.2
million for the year ended December 31, 2007, compared with $2.8 million for the year ended December 31,
2006.
RSU bonus expense remained relatively flat decreasing by $100,000 for the year ended
December 31, 2007, compared with the same period in 2006. Compensation expense related to stock options for
the year ended December 31, 2007, decreased $1.4 million to $437,000 from $1.9 million in the comparable
period in 2006 because virtually all of the stock options are now vested. No stock options have been granted since
2004.
The amounts described above, combined with a net $5.4 million increase in other G&A expense,
including office supplies and employee development, were offset by a $5.0 million decrease in the amount of
G&A that was allocated to exploration expense due to the aforementioned change in our Net Profits Plan
accounting estimate and a $4.3 million increase in COPAS overhead reimbursements. COPAS overhead
reimbursements from operations increased due to an increase in our operated well count from our drilling
program.
Change in Net Profits Plan liability. For the year ended December 31, 2007, this expense increased $27.1
million to $50.8 million from $23.8 million for 2006. This increase reflects a decrease in the discount rate used to
calculate the present value of future payments from a base rate of 15 percent to 12 percent. The decrease in the
discount rate to 12 percent resulted from our divestiture marketing process and our assessment that the overall
market for oil and gas reserves is ever more competitive.
Interest expense. Interest expense increased by $11.4 million to $19.9 million for 2007 compared to
$8.5 million for 2006. The increase reflects an increase in our average outstanding borrowings in 2007 compared
with 2006. Additionally, the increase reflects that we have $287.5 million of 3.50% Senior Convertible Notes
outstanding at December 31, 2007, compared with $100.0 million of 5.75% Senior Convertible Notes outstanding
as of December 31, 2006. We also capitalized $5.4 million of interest in 2007 compared to $3.5 million in 2006.
Income tax expense. Income tax expense totaled $110.6 million for 2007 and $105.3 million for 2006,
resulting in effective tax rate of 36.8 percent and 35.7 percent, respectively. The effective rate change from 2006
reflects changes in the mix of the highest marginal state tax rates as a result of enacted Texas margin tax
legislation, the benefit of federal and state estimated percentage depletion expense, acquisition and drilling
activity, and also reflects other permanent differences including differing estimated effects between years of the
domestic production activities deduction.
The current portion of income tax expense in 2007 was $17.6 million compared to $30.5 million in 2006.
These amounts are 16 percent and 29 percent of the total income tax expense for the respective periods. The
decrease resulted from significant drilling activity reflecting the deduction of intangible drilling costs in the year
incurred, thereby reducing current taxable income.
71
Other Liquidity and Capital Resources Information
Pension Benefits
Substantially all of our employees who meet age and service requirements participate in a non-
contributory defined benefit pension plan. At December 31, 2008, and 2007, we had $4.4 million and $2.5
million, respectively, of pre-tax loss in accumulated other comprehensive income. We believe this obligation will
be funded from future cash flows from operating activities. For purposes of calculating our obligation under the
plan, we have used an expected return on plan assets of 7.5 percent. We think this rate of return is appropriate
over a long-term given the mix of plan investments, 60 percent equity and 40 percent debt securities, and the
historical rate of return provided by equity and debt securities since the 1920s. Our actual rate of return was
negative 20.9 percent for 2008 and positive 6.5 percent for 2007. The difference in investment income using our
projected rate of return compared to our actual rates of return was not material in the long run and will not have a
material effect on results of operations or cash flows from operating activities in future years.
For the 2008 plan year, the discount rate assumption was changed from 6.1 percent to 6.6 percent. The
lump sum interest rate was increased from 5.5 percent to 6.0 percent. The lump sum mortality table was updated
to the Pension Protection Act 2009 Optional Combined Unisex table. The actuarial gain/(loss) due to
demographic experience, including any assumption changes, and investment return differences from assumptions
during the prior year was $101,000 and negative $2.3 million, respectively causing a $2.3 million increase in the
projected benefit obligation of the plan. The plan’s accumulated benefit obligation was $9.9 million and
$10.4 million at December 31, 2008, and 2007, respectively. We do not believe this change was material and we
project that it will not have a material effect on the results of operations or on cash flow from operating activities
in future periods.
We also have a supplemental non-contributory defined benefit pension plan that covers certain
management employees. There are no plan assets for this plan. For the 2008 plan year, the discount rate
assumption was changed from 6.1 percent to 6.6 percent. The lump sum interest rate was increased from
5.5 percent to 6.0 percent. The lump sum mortality table was updated to the Pension Protection Act 2009
Optional Combined Unisex table. The actuarial gain/(loss) due to demographic experience, including any
assumption changes, and investment return differences from assumptions during the prior year was $64,000 and
zero, respectively causing a $64,000 decrease in projected benefit obligation of the plan. The plan’s accumulated
benefit obligation was $546,000 and $1.0 million at December 31, 2008, and 2007, respectively. We believe this
obligation will be funded from future cash flows from operating activities.
Accounting Matters
Please see Note 11 – Fair Value Measurements and the section entitled ―Recently Issued Accounting
Standards‖ under Note 1 – Summary of Significant Accounting Policies in Part IV, Item 15 of this report for
accounting matters.
Environmental
St. Mary’s compliance with applicable environmental regulations has not resulted in any significant
capital expenditures or materially adverse effects to our liquidity or results of operations. We believe we are in
substantial compliance with environmental regulations and do not currently foresee that material expenditures will
be required in the future. However, we are unable to predict the impact that future compliance with regulations
may have on future capital expenditures, liquidity, and results of operations.
72
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,‖ ―Summary of Oil and Gas Production Hedges in Place,‖ and ―Summary of Interest Rate Hedges in
Place‖ in Item 7 above and is incorporated herein by reference.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements that constitute Item 8 follow the text of this report. An index to
the Consolidated Financial Statements and Schedules appears in Item 15(a) of this report.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
CONTROLS AND PROCEDURES
We maintain a system of disclosure controls and procedures that are designed to 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 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.
We carried out an evaluation, under the supervision and with the participation of our management,
including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and
operation of our disclosure controls and procedures as of the end of the period covered by the Annual Report on
Form 10-K. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded
that our disclosure controls and procedures are effective for the purpose discussed above as of the end of the
period covered by this Annual Report on Form 10-K. There was no change in our internal control over financial
reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
73
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Stockholders’ of St. Mary Land & Exploration Company
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. 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, 2008. 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, 2008.
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.
/s/ ANTHONY J. BEST
Anthony J. Best
President and Chief Executive Officer
February 23, 2009
/s/ A. WADE PURSELL
A. Wade Pursell
Executive Vice President and Chief Financial Officer
February 23, 2009
74
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
St. Mary Land & Exploration Company and Subsidiaries
Denver, Colorado
We have audited the internal control over financial reporting of St. Mary Land & Exploration Company and
subsidiaries (the ―Company‖) as of December 31, 2008, 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, 2008, 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, 2008, of the
Company and our report dated February 23, 2009, expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 23, 2009
75
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item concerning St. Mary’s Directors and corporate governance is
incorporated by reference to the information provided under the captions ―Election of Directors,‖ ―Nominees for
Election as Directors,‖ ―Corporate Governance‖ and ―Board and Committee Meetings‖ in St. Mary’s definitive
proxy statement for the 2009 annual meeting of stockholders to be filed within 120 days from
December 31, 2008. The information required by the Item concerning St. Mary’s executive officers is
incorporated by reference to the information provided in Part I – Item 4A – EXECUTIVE OFFICERS OF THE
REGISTRANT, included in this Form 10-K.
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 St. Mary’s definitive proxy statement for the 2009 annual
meeting of stockholders to be filed within 120 days from December 31, 2008.
ITEM 11.
EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the information provided under the
captions, ―Director Compensation,‖ ―Compensation Discussion and Analysis,‖ ―Executive Compensation and
Summary Compensation Table,‖ ―Summary Compensation Table For 2007 and 2008,‖ ―Grants of Plan-Based
Awards in 2008,‖ ―Outstanding Equity Awards at 2008 Fiscal Year-End,‖ ―Nonqualified Deferred
Compensation,‖ ―Option Exercises and Stock Vested,‖ ―Retirement Plans,‖ ―2008 Pension Benefits,‖ ―Equity
Compensation Plans,‖ ―Compensation Committee Interlocks and Insider Participation,‖ ―Compensation
Committee Report,‖ ―Employment Agreements and Termination of Employment,‖ and ―Change-of-Control
Arrangements‖ in St. Mary’s definitive proxy statement for the 2009 annual meeting of stockholders to be filed
within 120 days from December 31, 2008.
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 St. Mary’s definitive proxy statement for the 2009 annual
meeting of stockholders to be filed within 120 days from December 31, 2008.
The information required by this Item concerning securities authorized for issuance under equity
compensation plans is incorporated by reference to the information provided under the caption ―Equity
Compensation Plans‖ in Part II, Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matter
and Issuer Purchases of Equity Securities, included in this Form 10-K.
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,‖ ―Election of Directors,‖ ―Corporate Governance,‖ and
―Board and Committee Meetings‖ in St. Mary’s definitive proxy statement for the 2009 annual meeting of
stockholders to be filed within 120 days from December 31, 2008.
76
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 Accountants‖ and ―Audit Committee Preapproval Policy and Procedures‖ in St. Mary’s
definitive proxy statement for the 2009 annual meeting of stockholders to be filed within 120 days from
December 31, 2008.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
PART IV
Audit Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity and Comprehensive Income
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
F-1
F-2
F-3
F-4
F-5
F-7
All other 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
Purchase and Sale Agreement dated November 1, 2006, among Henry Petroleum LP, Henry Holding
LP, Henry Group, Entre Energy Partners LP, and St. Mary Land & Exploration Company (filed as
Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on December 18, 2006, and
incorporated herein by reference)
Purchase and Sale Agreement dated August 2, 2007, among Rockford Energy Partners II, LLC and St.
Mary Land & Exploration Company (filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-
K filed on October 5, 2007, and incorporated herein by reference)
Purchase and Sale Agreement dated December 11, 2007, among St. Mary Land & Exploration
Company, Ralph H. Smith Restated Revocable Trust Dated 8/14/97, Ralph H. Smith Trustee, Kent. J.
Harrell, Trustee of the Kent J. Harrell Revocable Trust Dated January 19, 1995, and Abraxas Operating
LLC (filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on February 1, 2008, and
incorporated herein by reference)
Ratification and Joinder Agreement dated January 31, 2008, among St. Mary Land & Exploration
Company, Ralph H. Smith, Kent J. Harrell, Abraxas Operating, LLC and Abraxas Petroleum
Corporation (filed as Exhibit 2.2 to the registrant’s Current Report on Form 8-K filed on February 1,
2008, and incorporated herein by reference)
Restated Certificate of Incorporation of St. Mary Land & Exploration Company as amended on May
25, 2005 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 2005 and incorporated herein by reference)
Restated By-Laws of St. Mary Land & Exploration Company amended as of December 18, 2008 (filed
as Exhibit 3.1 to the registrant’s Current Report on Form 8-K filed on December 23, 2008, and
incorporated herein by reference)
2.2
2.3
2.4
3.1
3.2
77
Exhibit
Number Description
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†
Shareholder Rights Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the registrant’s Quarterly
Report on Form 10-Q/A for the quarter ended June 30, 1999 and incorporated herein by reference)
First Amendment to Shareholders Rights Plan dated March 15, 2002 as adopted by the Board of
Directors on July 19, 2001 (filed as Exhibit 4.2 to the registrant’s Annual Report on Form 10-K for the
year ended December 31, 2001 and incorporated herein by reference)
Second Amendment to Shareholder Rights Plan dated April 24, 2006 (filed as Exhibit 4.1 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 and incorporated
herein by reference)
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)
Registration Rights Agreement, dated as of April 4, 2007, among St. Mary Land & Exploration
Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wachovia Capital Markets,
LLC, for themselves and as representatives of the Initial Purchasers (filed Exhibit 4.2 to the registrant’s
Current Report on Form 8-K filed on April 4, 2007, 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)
Cash Bonus Plan (filed as Exhibit 10.5 to the registrant’s Registration Statement on Form S-1
(Registration No. 333-53512) and incorporated herein by reference)
Summary Plan Description/Pension Plan dated December 30, 1994 (filed as Exhibit 10.35 to the
registrant’s Annual Report on Form 10-K for the year ended December 31, 1994 and incorporated
herein by reference)
Non-qualified Unfunded Supplemental Retirement Plan, as amended (filed as Exhibit 10.8 to the
registrant’s Registration Statement on Form S-1 (Registration No. 333-53512) and incorporated herein
by reference)
Employee Stock Purchase Plan (filed as Exhibit 10.48 for the registrant’s Annual Report on Form 10-K
for the year ended December 31, 1997 and incorporated herein by reference)
First Amendment to Employee Stock Purchase Plan dated February 27, 2001 (filed as Exhibit 10.1 to
the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 and incorporated
herein by reference)
Second Amendment to the Employee Stock Purchase Plan dated February 18, 2005 (filed as Exhibit
10.48 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 and
incorporated herein by reference)
Form of Change of Control Severance Agreements (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)
10.10† Amendment to Form of Change of Control Severance Agreement (filed as Exhibit 10.9 to the
10.11
registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated
herein by reference)
Amendment to an Extension of Office Lease dated as of December 14, 2001 (filed as Exhibit 10.45 to
the registrant’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated
herein by reference)
10.12† Non-Employee Director Stock Compensation Plan as adopted on March 27, 2003 (filed as Exhibit 10.1
to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 and incorporated
herein by reference)
78
Exhibit
Number Description
10.13† Restricted Stock Plan as adopted on April 18, 2004 (filed as Exhibit 10.1 to the registrant’s Quarterly
Report on Form 10-Q for the quarter ended June 30, 2004 and incorporated herein by reference)
10.19
10.20
10.18
10.17
10.16
10.15†
10.14† Amendment to Restricted Stock Plan, dated December 15, 2005 (filed as Exhibit 10.2 to the registrant’s
Current Report on Form 8-K filed on December 19, 2005 and incorporated herein by reference)
Form of Restricted Stock Unit Award Agreement under the Restricted Stock Plan (filed as Exhibit 10.1
to the registrant’s Current Report on Form 8-K filed on March 15, 2005 and incorporated herein by
reference)
Amended and Restated Credit Agreement dated as of April 7, 2005 among St. Mary Land &
Exploration Company, Wachovia 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 March 31, 2005 and incorporated herein by reference)
2006 Equity Incentive Compensation Plan (filed on May 17, 2006 as Exhibit 99.1 to the registrant’s
Registration Statement on Form S-8 (Registration No. 333-134221) and incorporated herein by
reference)
Form of Non-Employee Director Restricted Stock Award Agreement (filed as Exhibit 10.2 to the
registrant’s Current Report on Form 8-K filed on May 18, 2006 and incorporated herein by reference)
Guaranty Agreement by St. Mary Energy Company in favor of Wachovia Bank, National Association,
as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.2 to the registrant’s Quarterly Report
on Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by reference)
Guaranty Agreement by Nance Petroleum Corporation in favor or Wachovia Bank, National
Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.3 to the registrant’s
quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by
reference)
Guaranty Agreement by NPC Inc. in favor of Wachovia Bank, National Association, as Administrative
Agent, dated April 7, 2005 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for
the quarter ended March 31, 2005 and incorporated herein by reference)
Pledge and Security Agreement between St. Mary Land & Exploration Company and Wachovia Bank,
National Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.5 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and incorporated
herein by reference.)
Pledge and Security Agreement between Nance Petroleum Corporation and Wachovia Bank, National
Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.6 to the registrant’s
Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by
reference.)
First Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit, Assignment, Security
Agreement, Fixture Filing and Financing Statement for the Benefit of Wachovia Bank, National
Association, as Administrative Agent, dated effective as of April 7, 2005 (filed as Exhibit 10.7 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and incorporated
herein by reference)
Deed of Trust – St. Mary Land & Exploration Company to Wachovia Bank, National Association, as
Administrative Agent, dated effective as of April 7, 2005 (filed as Exhibit 10.8 to the registrant’s
Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by
reference)
10.25
10.22
10.24
10.21
10.23
10.26† Net Profits Interest Bonus Plan, as Amended on December 15, 2005 (filed as Exhibit 10.1 to the
registrant’s Current Report on Form 8-K filed on December 19, 2005 and incorporated herein by
reference)
Summary of Charitable Contributions in Honor of Thomas E. Congdon (filed as Exhibit 10.4 to the
registrant’s Current Report on Form 8-K filed on December 19, 2005 and incorporated herein by
reference)
10.27
79
Exhibit
Number Description
10.28†
10.29
Summary of 2006 Base Salaries for Named Executive Officers (filed as Exhibit 10.5 to the registrant’s
Current Report on Form 8-K filed on December 19, 2005 and incorporated herein by reference)
Employment Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.5 to the registrant’s
Current Report on Form 8-K filed on May 4, 2006 and incorporated herein by reference)
10.30*† Summary of Compensation Arrangements for Non-Employee Directors
10.31
Purchase Agreement, dated March 29, 2007, among St. Mary Land & Exploration Company, Merrill
Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wachovia Capital Markets, LLC,
Bear Stearns & Co. Inc., BNP Paribas Securities Corp., and UBS Securities LLC (filed as Exhibit 10.1
to the registrant’s Current Report on Form 8-K filed on April 4, 2007, and incorporated herein by
reference)
First Amendment to Amended and Restated Credit Agreement, dated March 19, 2007, among St. Mary
Land & Exploration Company, the lenders party thereto, Wachovia Bank, National Association, as
issuing bank and administrative agent, Wells Fargo Bank, N.A., as syndication agent, and BNP Paribas,
Comerica Bank-Texas and JPMorgan Chase Bank, N.A., as co-documentation agents (filed as Exhibit
10.2 to the registrant’s Current Report on Form 8-K filed on April 4, 2007, and incorporated herein by
reference)
10.32
10.33† Net Profits Interest Bonus Plan, As Amended and Restated by the Board of Directors on July 19, 2007
(filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on July 25, 2007, and
incorporated herein by reference)
10.34† Cash Bonus Plan as Amended on March 28, 2008 (filed as Exhibit 10.1 to the registrant’s Current
10.35
10.36†
10.37†
10.38†
Report on Form 8-K filed on April 3, 2008 and incorporated herein by reference)
Second Amended and Restated Credit Agreement dated April 10, 2008, among St. Mary Land &
Exploration Company, the lenders party thereto, Wachovia Bank, National Association, as
Administrative Agent, Wells Fargo Bank, N.A., as syndication agent, and BNP Paribas, Comerica
Bank and JPMorgan Chase Bank, N.A., as co-documentation agents (filed as Exhibit 10.1 to the
registrant’s Quarterly Report on Form 10-Q filed on May 5, 2008 and incorporated herein by reference)
2006 Equity Incentive Compensation Plan as Amended and Restated as of March 28, 2008 (filed as
Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2008 and incorporated
herein by reference)
Form of Performance Share Award Agreement (filed as Exhibit 10.4 to the registrant’s Quarterly
Report on Form 10-Q filed on August 5, 2008 and incorporated herein by reference)
Form of Performance Share Award Notice (filed as Exhibit 10.5 to the registrant’s Quarterly Report on
Form 10-Q filed on August 5, 2008 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.
Consent of Netherland, Sewell & Associates, Inc.
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
12.1*
21.1*
23.1*
23.2*
23.3*
24.1*
31.1*
31.2*
32.1** Certification pursuant to U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002
*
**
†
Filed with this Form 10-K
Furnished with this Form 10-K
Exhibit constitutes a management contract or compensatory plan or agreement.
(c) Financial Statement Schedules. See Item 15(a) above.
80
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
St. Mary Land & Exploration Company and Subsidiaries
Denver, Colorado
We have audited the accompanying consolidated balance sheets of St. Mary Land & Exploration Company and
subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of
operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the
period ended December 31, 2008. 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 St. Mary Land & Exploration Company and subsidiaries as of December 31, 2008 and 2007, and the results of
their operations and their cash flows for each of the three years in the period ended December 31, 2008, in
conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 and Note 8 to the financial statements, the Company changed its method of accounting
and disclosure for stock based compensation and its defined benefit plans in 2006.
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, 2008, 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 23, 2009, expressed an unqualified
opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 23, 2009
F-1
PART II. FINANCIAL INFORMATION
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents
Short-term investments
Accounts receivable, net of allowance for doubtful accounts
of $16,788 in 2008 and $152 in 2007
Refundable income taxes
Prepaid expenses and other
Accrued 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, net of impairment allowance
of $42,945 in 2008 and $10,319 in 2007
Wells in progress
Oil and gas properties held for sale less accumulated depletion,
depreciation, and amortization
Other property and equipment, net of accumulated depreciation
of $13,848 in 2008 and $11,549 in 2007
Other noncurrent assets:
Goodwill
Accrued derivative asset
Restricted cash subject to Section 1031 Exchange
Other noncurrent assets
Total other noncurrent assets
Total Assets
Current liabilities:
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued expenses
Accrued derivative liability
Deposit associated with oil and gas properties held for sale
Deferred income taxes
Total current liabilities
Noncurrent liabilities:
Long-term credit facility
Senior convertible notes
Asset retirement obligation
Asset retirement obligation associated with oil and gas properties held for sale
Net Profits Plan liability
Deferred income taxes
Accrued derivative liability
Other noncurrent liabilities
Total noncurrent liabilities
Commitments and contingencies
Stockholders' equity:
Common stock, $0.01 par value: authorized - 200,000,000 shares;
issued: 62,465,572 shares in 2008 and 64,010,832 shares in 2007;
outstanding, net of treasury shares: 62,288,585 shares in 2008
and 63,001,120 shares in 2007
Additional paid-in capital
Treasury stock, at cost: 176,987 shares in 2008 and 1,009,712 shares in 2007
Retained earnings
Accumulated other comprehensive income (loss)
Total stockholders' equity
December, 31
2008
2007
$
6,131
1,002
$
43,510
1,173
157,690
13,161
22,161
111,649
-
311,794
1,350
3,007,946
(947,207)
168,817
90,910
1,827
13,458
2,337,101
-
21,541
14,398
10,182
46,121
159,149
933
14,129
17,836
33,211
269,941
-
2,721,229
(804,785)
134,386
137,417
76,921
9,230
2,274,398
9,452
5,483
-
12,406
27,341
$
2,695,016
$
2,571,680
$
254,811
501
-
41,289
296,601
$
254,918
97,627
10,000
-
362,545
300,000
287,500
108,755
238
177,366
358,334
27,419
11,318
1,270,930
625
99,440
(1,892)
964,019
65,293
1,127,485
285,000
287,500
96,432
8,744
211,406
257,603
190,262
8,843
1,345,790
640
170,070
(29,049)
878,652
(156,968)
863,345
Total Liabilities and Stockholders' Equity
$
2,695,016
$
2,571,680
The accompanying notes are an integral part of these consolidated financial statements.
F-2
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
Operating revenues and other income:
Oil and gas production revenue
Realized oil and gas hedge gain (loss)
Marketed gas system revenue
Gain (loss) on sale of proved properties
Other revenue
Total operating revenues and other income
Operating expenses:
Oil and gas production expense
Depletion, depreciation, amortization,
and asset retirement obligation liability accretion
Exploration
Impairment of proved properties
Abandonment and impairment of unproved properties
Impairment of goodwill
General and administrative
Bad debt expense
Change in Net Profits Plan liability
Marketed gas system expense
Unrealized derivative (gain) loss
Other expense
Total operating expenses
Income from operations
Nonoperating income (expense):
Interest income
Interest expense
Income before income taxes
Income tax expense
For the Years Ended December 31,
2007
2008
2006
$
1,259,400
(101,096)
77,350
63,557
2,090
1,301,301
$
912,093
24,484
45,149
(367)
8,735
990,094
$
730,737
28,176
20,936
6,910
942
787,701
271,355
314,330
60,121
302,230
39,049
9,452
79,503
16,735
(34,040)
72,159
(11,209)
10,415
1,130,100
171,201
485
(20,275)
151,411
(59,858)
218,208
227,596
58,686
-
4,756
-
60,149
-
50,823
42,485
5,458
2,522
670,683
319,411
746
(19,895)
300,262
(110,550)
176,590
154,522
51,889
7,232
4,301
-
38,873
-
23,759
18,526
7,094
2,649
485,435
302,266
1,576
(8,521)
295,321
(105,306)
Net income
$
91,553
$
189,712
$
190,015
Basic weighted-average common shares outstanding
Diluted weighted-average common shares outstanding
62,243
63,133
61,852
64,850
56,291
65,962
Basic net income per common share
$
1.47
$
3.07
$
3.38
Diluted net income per common share
$
1.45
$
2.94
$
2.94
The accompanying notes are an integral part of these consolidated financial statements.
F-3
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(In thousands, except share amounts)
Balances, December 31, 2005
57,011,740
$
570
$
123,278
(250,000)
$
(5,148)
$
(5,593)
$
510,812
$
(54,599)
$
569,320
Common Stock
Shares
Amount
Additional
Paid-in
Capital
Treasury Stock
Shares
Amount
Deferred
Stock-Based
Compensation
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Stockholders'
Equity
Comprehensive income, net of tax:
Net income
Change in derivative instrument fair value
Reclassification to earnings
Minimum pension liability adjustment
Total comprehensive income
SFAS No. 158 transition amount
Cash dividends, $ 0.10 per share
Treasury stock purchases
Retirement of treasury stock
Issuance of common stock under Employee
Stock Purchase Plan
Sale of common stock, including income
tax benefit of stock option exercises
Adoption of Statement of Financial Accounting
Standards No. 123(R)
Stock-based compensation expense
-
-
-
-
-
-
-
(3,275,689)
26,046
1,489,636
-
-
-
-
-
-
-
-
-
(33)
-
16
-
-
-
-
-
-
-
-
-
(122,598)
814
32,970
(5,593)
10,069
-
-
-
-
-
-
(3,319,300)
3,275,689
-
-
-
-
-
-
-
-
(123,108)
122,631
-
-
-
-
-
-
-
-
-
-
-
-
-
43,611
-
1,353
5,593
-
190,015
-
-
-
-
(5,603)
-
-
-
-
-
-
-
87,107
(18,129)
(180)
(1,270)
-
-
-
-
-
-
-
190,015
87,107
(18,129)
(180)
258,813
(1,270)
(5,603)
(123,108)
-
814
32,986
-
11,422
Balances, December 31, 2006
55,251,733
$
553
$
38,940
(250,000)
$
(4,272)
$
-
$
695,224
$
12,929
$
743,374
Comprehensive income, net of tax:
Net income
Change in derivative instrument fair value
Reclassification to earnings
Minimum pension liability adjustment
Total comprehensive income
Cash dividends, $ 0.10 per share
Treasury stock purchases
Issuance of common stock under Employee
Stock Purchase Plan
Conversion of 5.75% Senior Convertible Notes
due 2022 to common stock, including income
tax benefit of conversion
Issuance of common stock upon settlement of
RSUs following expiration of restriction period,
net of shares used for tax withholdings
Sale of common stock, including income
tax benefit of stock option exercises
Stock-based compensation expense
-
-
-
-
-
-
29,534
-
-
-
-
-
-
-
-
-
-
-
-
-
919
7,692,295
77
106,854
302,370
733,650
1,250
3
7
-
(4,569)
19,011
8,915
-
-
-
-
-
-
-
-
-
(792,216)
-
(25,957)
-
-
-
-
-
-
-
32,504
-
1,180
-
-
-
-
-
-
-
-
-
-
-
189,712
-
-
-
(6,284)
-
-
-
-
-
-
-
(154,497)
(15,470)
70
-
-
-
-
-
-
-
189,712
(154,497)
(15,470)
70
19,815
(6,284)
(25,957)
919
106,931
(4,566)
19,018
10,095
Balances, December 31, 2007
64,010,832
$
640
$
170,070
(1,009,712)
$
(29,049)
$
-
$
878,652
$
(156,968)
$
863,345
Comprehensive income, net of tax:
Net income
Change in derivative instrument fair value
Reclassification to earnings
Minimum pension liability adjustment
Total comprehensive income
Cash dividends, $ 0.10 per share
Treasury stock purchases
Retirement of treasury stock
Issuance of common stock under Employee
Stock Purchase Plan
Issuance of common stock upon settlement of
RSUs following expiration of restriction period,
net of shares used for tax withholdings
Sale of common stock, including income
tax benefit of stock option exercises
Stock-based compensation expense
-
-
-
-
-
-
(2,945,212)
45,228
482,602
868,372
3,750
-
-
-
-
-
-
(29)
-
-
5
9
-
-
-
-
-
-
(103,237)
1,055
(6,910)
24,691
13,771
-
-
-
-
-
(2,135,600)
2,945,212
-
-
-
-
-
-
-
(77,150)
103,266
-
-
-
23,113
-
1,041
-
-
-
-
-
-
-
-
-
-
-
91,553
-
-
-
(6,186)
-
-
-
-
-
-
-
177,005
46,463
(1,207)
-
-
-
-
-
-
-
91,553
177,005
46,463
(1,207)
313,814
(6,186)
(77,150)
-
1,055
(6,905)
24,700
14,812
Balances, December 31, 2008
62,465,572
$
625
$
99,440
(176,987)
$
(1,892)
$
-
$
964,019
$
65,293
$
1,127,485
The accompanying notes are an integral part of these consolidated financial statements.
F-4
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
Reconciliation of net income to net cash provided
by operating activities:
Net income
Adjustments to reconcile net income to net cash
provided by operating activities:
Loss related to hurricanes
(Gain) loss on insurance settlement
(Gain) loss on sale of proved properties
Depletion, depreciation, amortization,
and asset retirement obligation liability accretion
Bad debt expense
Exploratory dry hole expense
Impairment of proved properties
Impairment of goodwill
Abandonment and impairment of unproved properties
Unrealized derivative (gain) loss
Change in Net Profits Plan liability
Stock-based compensation expense*
Deferred income taxes
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 options
Net cash provided by operating activities
Cash flows from investing activities:
Proceeds from insurance settlement
Proceeds from sale of oil and gas properties
Capital expenditures
Acquisition of oil and gas properties
Deposits to restricted cash
Other
Net cash used in investing activities
Cash flows from financing activities:
Proceeds from credit facility
Repayment of credit facility
Excess income tax benefit from the exercise of stock options
Net proceeds from issuance of senior convertible debt
Proceeds from sale of common stock
Repurchase of common stock
Dividends paid
Other
Net cash provided by (used in) financing activities
For the Years Ended December 31,
2007
2008
2006
$
91,553
$
189,712
$
190,015
6,980
2,296
(63,557)
314,330
16,735
6,823
302,230
9,452
39,049
(11,209)
(34,040)
14,812
40,634
(3,593)
(14,327)
(12,228)
(1,504)
(12,348)
(13,867)
678,221
-
178,867
(745,617)
(81,823)
(14,398)
(9,814)
(672,785)
2,571,500
(2,556,500)
13,867
-
11,888
(77,202)
(6,186)
(182)
(42,815)
-
(5,243)
367
227,596
-
14,365
-
-
4,756
5,458
50,823
10,095
92,955
(10,497)
(6,557)
6,751
19,375
40,769
(9,933)
630,792
5,948
495
(637,748)
(182,883)
-
10,316
(803,872)
822,000
(871,000)
9,933
280,657
10,007
(25,904)
(6,284)
(4,283)
215,126
-
-
(6,910)
154,522
-
10,191
7,232
-
4,301
7,094
23,759
11,422
74,832
(2,479)
22,476
-
(17,886)
5,215
(16,084)
467,700
-
860
(455,056)
(270,639)
-
116
(724,719)
935,137
(601,137)
16,084
-
17,716
(123,108)
(5,603)
4,469
243,558
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
(37,379)
43,510
6,131
$
42,046
1,464
43,510
$
(13,461)
14,925
1,464
$
* Stock-based compensation expense is a component of exploration expense and general and administrative expense
on the consolidated statements of operations. During 2008, 2007, and 2006, respectively, approximately $5.8 million,
$3.2 million, and $3.1 million of stock-based compensation expense was included in exploration expense.
During 2008, 2007, and 2006, respectively, approximately $9.0 million, $6.9 million, and $8.3 million of stock-based
compensation expense was included in general and administrative expense.
The accompanying notes are an integral part of these consolidated financial statements.
F-5
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
Supplemental schedule of additional cash flow information and noncash investing and financing activities:
Cash paid for interest
$
21,976
$
22,816
$
9,826
Net cash paid or (refunded) for income taxes
$
17,326
$
(1,156)
$
25,505
2008
For the Years Ended December 31,
2007
(In thousands)
2006
In December 2008 the Company closed a transaction whereby it exchanged non-core oil and gas properties
located in Coupee Parish, Louisiana fair valued at $30.4 million for an increased interest in properties
located in Upton and Midland Counties, Texas and $17.6 million in cash.
In September 2008 the Company hired a new senior executive. Upon commencement of employment, the
Company issued 15,496 shares of restricted stock awards to the senior executive, of which half will vest on
December 15, 2009 and the remaining half will vest on December 15, 2010, provided that on such vesting dates the
executive is employed by the Company. The total fair value of the issuance was $600,005.
In August 2008 the Company issued 465,751 Performance Share Awards to employees as equity-based
compensation pursuant to the Company's 2006 Equity Incentive Compensation Plan. The total fair value of the
issuance equaled $12.3 million.
For the years ended December 31, 2008, 2007, and 2006, the Company issued 428,407, 102,634, and 492,851
restricted stock units, respectively, to employees as equity-based compensation pursuant to the Company's 2006
Equity Incentive Compensation Plan. The total fair values of the issuances were $23.4 million, $3.3 million, and
$16.7 million, respectively.
As of December 31, 2008, 2007, and 2006, $116.5 million, $116.9 million, and $73.5 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.
For the years ended December 31, 2008, 2007, and 2006, the Company issued 23,113, 32,504, and 29,827 shares,
respectively, of common stock from treasury to its non-employee directors pursuant to the Company's 2006 Equity
Incentive Compensation Plan. The Company recorded compensation expense related to these issuances of
approximately $1,041,000, $983,500, and $976,000 for the years ended December 31, 2008, 2007, and 2006, respectively.
In March 2007 the Company called the 5.75% Senior Convertible Notes for redemption. All of the note holders
elected to convert the 5.75% Senior Convertible Notes to common stock. As a result, the Company issued
7,692,295 shares of common stock on March 16, 2007, in exchange for the $100 million of 5.75% Senior
Convertible Notes then outstanding. The conversion was executed in accordance with the conversion provisions
of the original indenture. Additionally, the conversion resulted in a $7.0 million decrease in non-current deferred
income taxes payable and a corresponding increase in additional paid-in capital that resulted from the recognition
of the cumulative excess tax benefit earned by the Company associated with the contingent interest feature of
the notes.
In June 2006 the Company hired a new senior executive. In doing so, the Company issued 13,784 shares of stock. The
fair value of this issuance was $727,600. In February 2008 and 2007, the Company issued 3,750 and 1,250 shares
of stock, respectively, to the senior executive, as the Company achieved certain performance metrics under an
agreement with the executive. The total fair values of these issuances were $141,900, and $45,012, respectively.
In May 2006 the Company closed a transaction whereby it exchanged non-core oil and gas properties for oil
and gas properties located in Richland County, Montana. This transaction is considered a non-monetary
exchange for accounting purposes with a fair value assigned to this transaction of $11.5 million.
The accompanying notes are an integral part of these consolidated financial statements.
F-6
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2008
Note 1 – Summary of Significant Accounting Policies
Description of Operations
St. Mary Land & Exploration Company (“St. Mary” or the “Company”) is an independent energy
company engaged in the exploration, exploitation, development, acquisition, and production of natural gas and
crude oil. The Company’s operations are conducted entirely in the continental United States and offshore in the
Gulf of Mexico.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of the Company and its wholly-
owned subsidiaries. Subsidiaries that are not wholly-owned are accounted for using full consolidation with
minority interest or by the equity or cost methods as appropriate. Equity method investments are included in
other noncurrent assets, and minority interest, which is immaterial to the Company, is included in other
noncurrent liabilities in the accompanying consolidated balance sheets. Intercompany accounts and transactions
have been eliminated.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the
United States requires management to make estimates and assumptions that affect the reported amounts of 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 oil and gas reserve quantities provide the basis for the calculation of
depletion, depreciation, and amortization (“DD&A”), impairment, goodwill, and the Net Profits Interest Bonus
Plan (“Net Profits Plan”) liability, each of which represents a significant component of the accompanying
consolidated financial statements.
Revenue Recognition
The Company derives revenue primarily from the sale of produced natural gas and crude oil. The
Company reports revenue as the gross amount received before taking into account production taxes and
transportation costs, which are reported as separate expenses. 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, New York Mercantile Exchange (“NYMEX”) and local spot market prices, quality and
transportation differentials, and other factors as the basis for these estimates.
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.
F-7
Short-term Investments
As of December 31, 2008, and 2007, the Company’s short-term investment consists of a certificate of
deposit. Securities categorized as held-to-maturity are stated at amortized cost whereas available-for-sale
securities are marked-to-market. As of December 31, 2008, and 2007, the Company held $1.0 million and
$1.2 million, respectively, of short-term investments.
Concentration of Credit Risk
Substantially all of the Company’s receivables are within the oil and gas industry, primarily from
purchasers of oil and gas and from partners with interests in common properties operated by the Company.
Although diversified among many companies, collectability is dependent upon the financial wherewithal of each
individual company as well as the general economic conditions of the industry. The receivables are not
collateralized. The Company currently has $16.8 million recorded as allowance for doubtful accounts. For
additional discussion on allowance for doubtful accounts, please see Note 14 – SemGroup Bankruptcy.
The Company has accounts with separate banks in Denver, Colorado; Shreveport, Louisiana; Franklin,
Louisiana; Tulsa, Oklahoma; and Billings, Montana. At December 31, 2008, and 2007, the Company had
$4.8 million and $42.8 million, respectively, invested in money market funds and overnight investment sweep
accounts. The difference between the investment amount and the cash and cash equivalents amount on the
accompanying consolidated balance sheets represents uncleared disbursements and non-interest bearing checking
accounts. The Company’s policy is to invest in highly-rated instruments and to limit the amount of credit
exposure at each individual institution.
The Company currently uses eight separate counterparties for its oil and gas commodity and interest rate
derivatives. The counterparties to the Company’s derivative instruments are highly-rated entities with corporate
credit ratings at or exceeding A- or A2 classified by Standard & Poor’s and Moody’s, respectively.
Oil and Gas Producing Activities
The Company follows the successful efforts method of accounting for its oil and gas properties. Under
this method of accounting, all property acquisition costs and costs of exploratory and development wells are
capitalized when incurred, pending determination of whether the well has found proved reserves. If an
exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. 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. The costs of development wells are capitalized whether
those wells are successful or unsuccessful.
Geological and geophysical costs and the costs of carrying and retaining unproved properties are
expensed as incurred. 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, 2008, the Company’s capitalized proved oil and gas properties
included $102.3 million of estimated salvage value.
The Company follows Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) FAS 19-
1, “Accounting for Suspended Well Costs,” (“FSP FAS 19-1”). For additional discussion, please see Note 16 –
Oil and Gas Activities under the heading Suspended Well Costs.
F-8
Impairment of Proved and Unproved Properties
Producing oil and gas property costs are evaluated for impairment and reduced to fair value if the sum of
expected undiscounted future cash flows is less than net book value pursuant to Statement of Financial
Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", (“SFAS No.
144”). Expected future cash flows are calculated on all proved 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 price forecast is based on NYMEX strip pricing, adjusted for basis differentials,
for the first five years. At the end of the first five years a flat terminal price is used. Future operating costs are
also adjusted as deemed appropriate for these estimates. An impairment write down is provided on unproved
property when the Company determines that either the property will not be developed or the carrying value is not
realizable.
For the years ended December 31, 2008, and 2006, the Company recorded expense of $302.2 million and
$7.2 million, respectively, related to proved property impairment write-downs. The Company did not incur any
proved property impairment write-downs during 2007. Approximately $154 million of the 2008 impairment
write-down relates to the South Texas assets that were acquired as part of the 2007 Rockford and Catarina
acquisitions.
For the years ended December 31, 2008, 2007, and 2006, the Company recorded expense related to the
abandonment and impairment of unproved properties of $39.0 million, $4.8 million, and $4.3 million,
respectively.
Sales of Proved and Unproved Properties
The sale of a partial interest in a proved oil and gas property is accounted for as normal retirement, and no
gain or loss is recognized as long as the treatment does not significantly affect the units-of-production depletion
rate. A gain or loss is recognized for all other sales of producing properties and is included in the results of
operations.
The sale of a partial interest in an 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
the sale is recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A
gain or loss is recognized for all other sales of nonproducing properties and is included in the accompanying
consolidated statements of operations.
Assets Held for Sale
In accordance with SFAS No. 144, any properties held for sale as of the date of presentation of a balance
sheet have been classified as assets held for sale and are separately presented on the accompanying consolidated
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. For additional discussion of assets held for sale, please see Note 3 – Acquisitions,
Divestitures, and Assets Held for Sale.
Other Property and Equipment
Other property and equipment such as office furniture and equipment, automobiles, 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 the straight-line method over the estimated useful lives of the assets which range
from three to thirty years. When other property and equipment is sold or retired, the capitalized costs and related
accumulated depreciation are removed from the accounts.
F-9
Restricted Cash
Proceeds from certain sales of oil and gas properties are held in escrow and restricted for future
acquisitions under a tax-free exchange agreement. These funds are invested in money market funds consisting of
corporate commercial paper, repurchase agreements, and U.S. Treasury obligations and are carried at cost, which
approximates fair market value.
Gas 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. The Company’s gas imbalance position at December 31, 2008, and 2007,
resulted in the recording of $1.8 million and $1.9 million, respectively, to accounts receivable, and $1.1 million
and $1.1 million, respectively, to accounts payable.
Derivative Financial Instruments
The Company seeks to manage or reduce commodity price risk on acquisitions of producing properties
and other production by hedging cash flows. The Company intends for derivative instruments used for this
purpose to be designated as, and to qualify as, cash flow hedging instruments under Statement of Financial
Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS No.
133”) and related pronouncements. The Company seeks to minimize its basis risk and indexes the majority of its
oil hedges to NYMEX prices and the majority of its gas hedges to various regional index prices associated with
pipelines in proximity to the Company’s areas of gas production. For additional discussion of derivatives, please
see Note 10 – Derivative Financial Instruments.
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. The Company had $300.0 million and $285.0 million in loans outstanding under its revolving
credit agreement as of December 31, 2008, and 2007, respectively. The Company’s interest rate swaps are
recorded at fair value as discussed in Note 10 – Derivative Financial Instruments. The Company’s 3.50% Senior
Convertible Notes due 2027 (the “3.50% Senior Convertible Notes”) are recorded at cost, and the fair value is
disclosed in Note 5 – Long-Term Debt. The Company has derivative financial instruments that are marked-to-
market for which changes in fair value are recorded in accumulated other comprehensive income in the
accompanying consolidated balance sheets. Considerable judgment is required to develop estimates of fair value.
The estimates provided are not necessarily indicative of the amounts the Company could realize upon the sale or
refinancing of such instruments.
Net Profits Plan
The Company records the estimated fair value of the liability for future payments under the Net Profits
Plan. The estimated liability is a discounted calculation and has underlying assumptions including estimates of oil
and gas reserves, recurring and workover lease operating expense, production and ad valorem tax rates, present
value discount factors, and pricing assumptions. The estimates the Company uses 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 as these changes are considered changes in estimates. The estimated Net
Profits Plan liability is recorded separately as a noncurrent liability in the accompanying consolidated balance
sheets.
F-10
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 consolidated statements of
operations. The corresponding current liability is included in accounts payable and accrued expenses in the
accompanying consolidated 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 see Note 7 – Compensation Plans under the heading Net Profits Plan.
Asset Retirement Obligations
The Company estimates future asset retirement obligations pursuant to the provisions of Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations,” ("SFAS No. 143").
SFAS No. 143 requires the Company to recognize 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.
Income Taxes
The Company accounts for deferred income taxes utilizing Statement of Financial Accounting Standards
No. 109, “Accounting for Income Taxes,” (“SFAS No. 109”) as amended. SFAS No. 109 prescribes an asset and
liability method whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary
differences between the carrying amount on the financial statements and the tax basis of assets and liabilities, as
measured by current enacted tax rates. These differences will result in taxable income or deductions in future
years when the reported amount of the asset or liability is recorded or settled, respectively. When appropriate, in
accordance with SFAS No. 109, the Company evaluates the need for a valuation allowance to reduce deferred tax
assets.
Earnings per Share
Basic net income per common share is calculated by dividing net income available to common
stockholders by the weighted-average basic common shares outstanding for the respective period. The shares
represented by vested restricted stock units (“RSUs”) are included in the calculation of the weighted-average
basic common shares outstanding. The basic earnings per share calculations reflect the impact of any repurchases
of shares of common stock made by the Company.
Diluted net income per common share of stock is calculated by dividing adjusted net income by the
weighted-average diluted common shares outstanding, which includes the effect of potentially dilutive securities.
Potentially dilutive securities for the diluted earnings per share calculation consist of unvested RSUs, in-the-
money outstanding stock options to purchase the Company’s common stock, Performance Share Awards
(“PSAs”), and shares into which the 3.50% Senior Convertible Notes are convertible.
The treasury stock method is used to measure the dilutive impact of stock options, RSUs, and PSAs. The
following table details the weighted-average dilutive and anti-dilutive securities related to stock options, RSUs,
and PSAs for the years presented:
For the Years Ended December 31,
2007
2006
2008
Dilutive
Anti-dilutive
890,189
330,231
1,441,556
-
1,978,577
-
Prior to the conversion of the Company’s 5.75% Senior Convertible Notes due 2022 (“5.75% Senior
Convertible Notes”) on March 16, 2007, potentially dilutive shares associated with this instrument were
accounted for using the if-converted method for the determination of diluted earnings per share. Adjusted net
F-11
income used in the if-converted method was derived by adding interest expense paid on the 5.75% Senior
Convertible Notes back to net income and then adjusting for nondiscretionary items that are based on net income
and would have changed had the 5.75% Senior Convertible Notes been converted at the beginning of the
respective periods. The 5.75% Senior Convertible Notes were called for redemption by the Company on March
16, 2007, and all of the note holders elected to convert the notes to shares of the Company’s common stock. The
Company issued 7.7 million common shares in connection with the conversion of the 5.75% Senior Convertible
Notes. Upon conversion, these shares were included in the calculation of weighted-average common shares
outstanding. The diluted earnings per share calculation for the year ended December 31, 2007, was adjusted for
the conversion and included a time-weighted-average of approximately 1.6 million potentially dilutive shares
related to the 5.75% Senior Convertible Notes. A total of 7.7 million potentially dilutive shares related to the
5.75% Senior Convertible Notes were included in the calculation of diluted earnings per share for the year ended
December 31, 2006.
The Company’s 3.50% Senior Convertible Notes, which were issued on April 4, 2007, have a net-share
settlement right whereby each $1,000 principal amount of notes may be surrendered for conversion to cash in an
amount equal to the principal amount and, if applicable, shares of common stock for the amount in excess of the
principal amount. The treasury stock method is used to measure the potentially dilutive impact of shares
associated with that conversion feature. The 3.50% Senior Convertible Notes have not been dilutive for any
reporting period that they have been outstanding and therefore do not impact the diluted earnings per share
calculation for the periods ended December 31, 2008, and 2007, respectively.
On August 1, 2008, the Company granted 465,751 PSAs for the three-year performance period ending
June 30, 2011. At the end of each grant’s three-year performance period, a multiplier will be applied to all vested
PSAs to determine the number of common shares issued. The number of common shares issued is determined by
the Company’s absolute stock price performance and a comparison of the Company’s stock price performance to
that of its peers. The number of potentially dilutive shares related to the PSAs is based on the number of shares, if
any, which would be issuable if the end of the reporting period was the end of the contingency period. There
were no potentially dilutive shares related to the PSAs included in the diluted earnings per share calculation as of
December 31, 2008. For additional discussion on PSAs, please see Note 7 – Compensation Plans under heading
Performance Share Awards.
The following table sets forth the calculations of basic and diluted earnings per share.
2008
For the Years Ended December 31,
2006
2007
(In thousands, except per share amounts)
Net income
$
91,553
$ 189,712
$
190,015
Adjustments to net income for dilution:
Add: Interest expense not incurred if 5.75% Senior
Convertible Notes converted
Less: Other adjustments
Less: Income tax effect of adjustment items
Net Income adjusted for the effect of dilution
$
Basic weighted-average common shares outstanding
Add: Dilutive effect of stock options and unvested
restricted stock units
Add: Dilutive effect of 5.75% Senior Convertible
Notes using the if-converted method
Diluted weighted-average common shares outstanding
-
-
-
91,553
62,243
890
-
63,133
1,285
(13)
(469)
$
$ 190,515
61,852
1,441
1,557
64,850
Basic earnings per common share
Diluted earnings per common share
$
$
F-12
1.47
1.45
$
$
3.07
$
2.94
$
6,337
(63)
(2,237)
194,052
56,291
1,979
7,692
65,962
3.38
2.94
Stock Based Compensation
At December 31, 2008, the Company had stock-based employee compensation plans that included RSUs,
PSAs, and stock options issued to employees and non-employee directors as more fully described in Note 7-
Compensation Plans. Stock options were last issued in December 2004. On January 1, 2006, the Company
adopted the provisions of Statement of Financial Accounting Standards No. 123 (R), “Share-Based Payment”
(“SFAS No. 123 (R)”). This statement requires the Company to record expense associated with the fair value of
stock-based compensation. The total unrecognized compensation expense associated with unvested stock options
at the date of adoption of this standard totaled $2.4 million. The Company elected to use the modified-
prospective adoption method for the standard and consequently recognized compensation expense of $1.9 million
in 2006, $437,000 in 2007 and $17,000 in 2008, at which point all options were fully vested. The Company
records compensation expense associated with the issuance of RSUs and PSAs. The Company records expense
associated with these grants based on the estimated fair value of the RSUs and PSAs as determined at the time of
grant.
Recently Issued Accounting Standards
The Company adopted FSP No.157-2 as of January 1, 2008, electing to partially adopt Statement of
Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”). The Company did not
apply SFAS No. 157 to nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities,
including nonfinancial long-lived assets measured at fair value for an impairment assessment under SFAS No.
144 and asset retirement obligations initially measured at fair value under SFAS No. 143. The partial adoption of
SFAS No. 157 did not have a material impact on the Company’s consolidated financial statements. Please refer
to Note 11 – Fair Value Measurements. The adoption of SFAS No. 157 for all nonfinancial assets and
nonfinancial liabilities is effective for the Company beginning January 1, 2009. The adoption of this
pronouncement does not have a material impact on the Company’s consolidated financial statements.
In December 2007 the FASB issued Statement of Financial Accounting Standards No. 141(R), “Business
Combinations” (“SFAS No. 141(R)”), which requires the acquiring entity in a business combination to recognize
and measure all assets and liabilities assumed in the transaction and any non-controlling interest in the acquiree at
fair value as of the acquisition date. The statement also establishes guidance for the measurement of the acquirer
shares issued in consideration for a business combination, the recognition of contingent consideration, the
accounting treatment for pre-acquisition gain and loss contingencies, the treatment of acquisition related
transaction costs, and the recognition of changes in the acquirer’s income tax valuation allowance and deferred
taxes. SFAS No. 141(R) changes the way the Company accounts for acquisitions of proved properties. Such
acquisitions will now be treated as business combinations, which will require transaction costs to be expensed as
incurred, may generate gains or losses due to changes between the effective and closing dates of acquisitions, and
require possible recognition of goodwill given differences between the purchase price and assets received. SFAS
No. 141(R) is effective for the Company beginning January 1, 2009. The impact of the adoption of SFAS No.
141(R) on the Company’s consolidated financial statements will largely be dependent on the size and nature of
the business combinations completed after the adoption of this statement.
In December 2007 the FASB issued Statement of Financial Accounting Standards No. 160,
“Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (“SFAS No.
160”), which establishes accounting and reporting standards that require noncontrolling interests to be reported as
a component of equity. SFAS No. 160 also requires that changes in a parent’s ownership interest while the
parent retains its controlling interest be accounted for as equity transactions and that any retained noncontrolling
equity investment upon the deconsolidation of a subsidiary be initially measured at fair value. SFAS No. 160 is
effective for the Company beginning January 1, 2009. The adoption of this pronouncement will not have a
material impact on the Company’s consolidated financial statements.
In March 2008 the FASB issued Statement of Financial Accounting Standard No. 161, “Disclosures about
Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS No. 161”),
which requires that objectives for using derivative instruments be disclosed in terms of underlying risk and
F-13
accounting designation. The statement requires fair value disclosures of derivative instruments and their gains
and losses to be in tabular format, the potential effect on the entity’s liquidity from the credit-risk-related
contingent features to be disclosed, and cross-referencing within the footnotes. SFAS No. 161 is effective for the
Company beginning January 1, 2009. The adoption of this pronouncement will not have an impact on the
Company’s consolidated financial statements, but it will require the Company to expand its disclosures about
derivative instruments.
In May 2008 the FASB issued FSP APB 14-1, “Accounting for Convertible Debt Instruments That May
Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” (“FSP APB 14-1”), which requires
issuers of convertible debt that may be settled fully or partially in cash upon conversion to account separately for
the liability and equity components of the convertible debt. The liability component is measured so that the
effective interest expense associated with the convertible debt reflects the issuer's borrowing rate at the date of
issuance for similar debt instruments without the conversion feature. FSP APB 14-1 applies to the Company’s
3.50% Senior Convertible Notes and will be effective for the Company beginning on January 1, 2009. FSP APB
14-1 will be applied retrospectively to all periods that will be presented in the Company’s consolidated financial
statements beginning after January 1, 2009. Upon adoption, the Company will retrospectively record a decrease
in the book value of its 3.50% Senior Convertible Notes of approximately $42 million at their inception on
April 4, 2007, and a corresponding increase in additional paid-in capital. Further, the Company will record an
additional $8.4 million and $6.3 million of interest expenses (net of applicable tax benefit of $3.1 million and
$2.3 million) in its 2008 and 2007 consolidated financial statements, respectively. The Company will begin
recording an additional non-cash interest expense of approximately $8 million per year in 2009.
On December 31, 2008, the Securities and Exchange Commission (“SEC”) published the final rules and
interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in
the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a
widely accepted standard for the management of petroleum resources that was developed by several industry
organizations. Key revisions include changes to the pricing used to estimate reserves, the ability to include
nontraditional resources in reserves, the use of new technology for determining reserves, and permitting
disclosure of probable and possible reserves. The SEC will require companies to comply with the amended
disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal
years ending on or after December 15, 2009. Early adoption is not permitted. The Company is currently
assessing the impact that the adoption will have on the Company’s disclosures, operating results, financial
position, and cash flows.
Comprehensive Income
Comprehensive income consists of net income, the unrealized gain or loss for the effective portion of
derivative instruments classified as cash flow hedges, and the accrued pension benefit obligation in excess of plan
assets. Comprehensive income is presented net of income taxes in the accompanying consolidated statements of
stockholders’ equity and comprehensive income.
F-14
The changes in the balances of components comprising other comprehensive income and loss are
presented in the following table:
Derivative
Instruments
Pension
Liability
Adjustments
(In thousands)
Other
Comprehensive
Income (Loss)
For the year ended December 31, 2006
Before tax income (loss)
Tax benefit (expense)
After deferred tax income (loss)
$ 111,437
(42,459)
68,978
$
For the year ended December 31, 2007
Before tax income (loss)
Tax benefit (expense)
After deferred tax income (loss)
$ (272,655)
102,688
$ (169,967)
For the year ended December 31, 2008
$
$
$
$
(290)
110
(180)
119
(49)
70
$
$
111,147
(42,349)
68,798
$
$
(272,536)
102,639
(169,897)
Before tax income (loss)
Tax benefit (expense)
After deferred tax income (loss)
$ 358,632
(135,164)
$ 223,468
$ (1,941)
734
$ (1,207)
$
$
356,691
(134,430)
222,261
Major Customers
During 2008, 2007, and 2006, no customer individually accounted for more than ten percent of the
Company’s total oil and gas production revenue.
Industry Segment and Geographic Information
The Company operates exclusively in the exploration and production segment. All of the Company’s
operations are conducted in the continental United States and in state and federal waters offshore in the Gulf of
Mexico. Consequently, the Company currently reports as a single industry segment. The Company’s gas
marketing department provides mostly internal services and acts as the first purchaser of natural gas and natural
gas liquids produced by the Company in certain cases. We consider the Company’s marketing function as
ancillary to the Company’s 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 financial position, 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 discreetly in the accompanying consolidated statements of operations.
Intangible Assets
As of December 31, 2008, and 2007, the Company’s accompanying consolidated balance sheets include
$1.4 million and $2.4 million, respectively, of intangible assets. These assets arise from acquired oil and gas sale
contracts with favorable pricing terms. They do not qualify as derivatives or hedges under SFAS No. 133.
Intangible assets of the Company are amortized using the units-of-production method and are evaluated for
impairment if such indicators arise. Intangible assets are included in other noncurrent assets on the Company’s
accompanying consolidated balance sheets.
Goodwill
Goodwill is measured as the excess of the acquisition costs over the sum of the amounts assigned to the
identifiable assets acquired less liabilities assumed. Goodwill was recorded as a result of the acquisition of Agate
F-15
Petroleum, Inc. in January 2005. Goodwill is reviewed for impairment annually or more frequently if impairment
indicators arise. The goodwill review was conducted at the reporting unit level. A reporting unit is defined as the
oil and gas properties in a region. The Company fully impaired its goodwill at December 31, 2008.
Off-Balance Sheet Arrangements
As part of its ongoing business, 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. As of and up to
December 31, 2008, 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 St. Mary is the primary beneficiary of a variable interest entity, that entity is consolidated into
St. Mary.
Note 2 – Accounts Receivable and Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
Accrued oil and gas sales
Due from joint interest owners
Settled hedge receivable
Other
Total accounts receivable
As of December 31,
2008
2007
(In thousands)
$ 84,583
56,493
8,829
7,785
$ 157,690
$ 115,534
37,860
-
5,755
$ 159,149
Accounts payable and accrued expenses are comprised of the following:
As of December 31,
2008
2007
(In thousands)
Accrued drilling costs
Revenue and severance tax payable
Accrued lease operating expense
Accrued property taxes
Accrued interest
Accrued compensation
Trade payables
Accrued payments to hedge contract
counterparties
Plug and abandonment liability on offshore
platform related to hurricanes
Accrued marketed gas system expense
Other
$ 111,397
42,520
20,328
4,889
2,794
18,613
25,629
-
7,281
8,892
12,468
$ 112,481
37,048
14,604
5,042
3,590
17,887
28,187
9,640
3,108
13,520
9,811
Total accounts payable and accrued expenses
$ 254,811
$ 254,918
F-16
Note 3 – Acquisitions, Divestitures, and Assets Held for Sale
Greater Green River Basin Divestiture
In June 2008 the Company completed the divestiture of certain non-strategic gas properties located in the
Greater Green River Basin in the Rocky Mountain region. The cash received at closing, net of commission costs,
was $21.7 million. The final sales price is subject to normal post-closing adjustments and is expected to be
finalized during the first quarter of 2009. The estimated gain on sale of proved properties related to the
divestiture is approximately $932,000 and may be impacted by the previously mentioned post-closing
adjustments. The Company determined that this sale does not qualify for discontinued operations accounting
under FASB Emerging Issues Task Force Issue No. 03-13, “Accounting for the Impairment or Disposal of Long-
Lived Assets”, (“EITF No. 03-13”).
Abraxas Divestiture
On January 31, 2008, the Company completed the divestiture of certain non-strategic oil and gas
properties located primarily in the Rocky Mountain and Mid-Continent regions to Abraxas Petroleum Corporation
and Abraxas Operating, LLC. The cash received at closing, net of commission costs, was $129.6 million. The
final sale price is subject to normal post-closing adjustments and is expected to be finalized during the first
quarter of 2009. The estimated gain on sale of proved properties related to the divestiture is approximately
$55.6 million and may be impacted by the previously mentioned post-closing adjustments. The Company
determined that this sale does not qualify for discontinued operations accounting under EITF No. 03-13. These
assets were classified as assets held for sale as of December 31, 2007.
Williston Basin Acquisition
On August 13, 2008, the Company acquired oil and gas properties located in the Bakken and Three Forks
formations in the Williston Basin for $20.2 million of cash. After normal purchase price adjustments, the
Company allocated $3.6 million to proved oil and gas properties and $16.6 million to unproved oil and gas
properties. The acquisition was funded with cash on hand and borrowings under the Company’s existing credit
facility.
Carthage Acquisition
On March 21, 2008, the Company acquired oil and gas properties located primarily in the Carthage Field
in Panola County, Texas for $49.2 million in cash. After normal purchase price adjustments, the Company
allocated $29.0 million to proved oil and gas properties, $20.6 million to unproved oil and gas properties, and a
net $215,000 to other liabilities. The Company also recorded a $165,000 asset retirement obligation liability
associated with the acquired properties. The acquisition was funded with cash on hand and borrowings under the
Company’s existing credit facility. During the second quarter of 2008, the Company acquired additional interests
in the majority of these properties for $8.1 million.
Rockford Acquisition
On October 4, 2007, the Company completed the purchase of certain oil and gas properties in the Gold
River project area targeting the Olmos shallow gas formation located primarily in Webb and Dimmit Counties,
Texas. The assets were purchased from Rockford Energy Partners II, LLC for $149.0 million. After normal
purchase price adjustments, the Company allocated $127.3 million to proved oil and gas properties, $23.1 million
to unproved oil and gas properties, and a net $292,000 to other assets. The Company also recorded a $1.7 million
asset retirement obligation liability associated with the acquired properties. The acquisition was funded with cash
on hand and borrowings under the Company’s existing credit facility. The acquired properties are adjacent to the
Catarina project area discussed below. In 2008 the Company recorded approximately $154 million of impairment
write-downs for the properties acquired through this acquisition and the Catarina acquisition.
F-17
Catarina Acquisition
On June 1, 2007, the Company acquired oil and gas properties located primarily in the Catarina project
area in Webb County, Texas in exchange for $30.0 million of cash. After normal purchase price adjustments, the
Company allocated $29.9 million to proved oil and gas properties, $535,000 to unproved oil and gas properties,
and $215,000 to other assets. The Company also recorded a $623,000 asset retirement obligation liability
associated with the acquired properties. The acquisition was funded with cash on hand and borrowings under the
Company’s existing credit facility.
Like-Kind Exchanges and Variable Interest Entities
On December 31, 2008, the Company closed on a partial Section 1031 Internal Revenue Code of 1986, as
amended (the “IRC”) tax deferred exchange whereby it exchanged certain non-strategic, partner-operated oil and
gas properties located in Pointe Coupee Parish, Louisiana for an increased interest in the Company-operated
Sweetie Peck tight oil assets in Upton and Midland Counties, Texas and $17.6 million in cash. After normal
purchase price adjustments, the Company allocated $11.0 million to proved oil and gas properties and
$1.8 million to unproved oil and gas properties. Proceeds of $14.4 million were deposited to restricted cash to
facilitate the acquisition of additional assets in tax deferred transactions. The exchange of proved properties
resulted in the recognition of approximately $13.8 million of gain on sale of proved properties.
The Carthage acquisition described above was structured to qualify as the first step of a reverse like-kind
exchange under Section 1031 of the IRC and Internal Revenue Service (“IRS”) Revenue Procedure 2000-37.
Prior to closing on the acquisition, the Company assigned all of its rights and duties under the purchase and sale
agreement to NBF Reverse Exchange, LLC, an indirect wholly-owned subsidiary of Comerica Incorporated,
which further assigned all of its rights and duties under the purchase and sale agreement to St. Mary Acquisition,
LLC (“SMA, LLC”), a company unaffiliated with St. Mary. The Carthage Field assets were acquired by NBF
Reverse Exchange, LLC as an exchange accommodation titleholder. In October 2008, SMA, LLC, was merged
into St. Mary. Its existence with the Secretary of State of Texas was terminated.
From the date of the closing of the Carthage acquisition on March 21, 2008, through October 10, 2008,
the assets held by SMA, LLC, were leased by St. Mary under a triple net lease whereby St. Mary had the benefits
and risks of all revenues and costs attributed to the properties. The Carthage assets were managed by St. Mary
under the terms of a management agreement with SMA, LLC. The second step of the like-kind exchange was
partially completed in conjunction with the divestiture of certain non-core oil and gas properties discussed above
under Greater Green River Divestiture. The funds from this transaction were deposited in an account owned by
Comerica Incorporated as qualified intermediary in this transaction. On September 12, 2008, the funds from this
transaction were moved into the Company’s operating cash account upon completion of the like-kind exchange.
In connection with the reverse like-kind exchange described above, St. Mary loaned an amount equal to
the purchase price of the assets to SMA, LLC. Based on the provision of FASB Interpretation No. 46(R),
“Consolidation of Variable Interest Entities” (“FIN 46(R)”), the Company determined that SMA, LLC was a
variable interest entity for which St. Mary was the primary beneficiary. Accordingly, SMA, LLC was
consolidated into St. Mary subsequent to SMA, LLC’s completion of the purchase of oil and gas properties on
March 21, 2008. As a result of the consolidation, St. Mary recognized all oil and gas reserves and production as
well as all revenues and expenses attributed to the Carthage acquisition as of the March 21, 2008, acquisition date.
St. Mary’s loan to SMA, LLC was repaid on October 10, 2008.
The Rockford acquisition of the Gold River assets described above was also structured to qualify as the
first step of a reverse like-kind exchange under Section 1031 of the IRC, and IRS Revenue Procedure 2000-37.
Prior to closing on the Rockford acquisition, the Company assigned all of its rights and duties under the purchase
and sale agreement to NBF Reverse Exchange, LLC, an indirect wholly-owned subsidiary of Comerica
Incorporated, which further assigned all of its rights and duties under the purchase and sale agreement to St. Mary
Land & Exploration Acquisition, LLC (“SMLEA, LLC”), a company unaffiliated with St. Mary. The Gold River
assets were acquired by NBF Reverse Exchange, LLC as an exchange accommodation titleholder. SMLEA, LLC
F-18
held the assets pursuant to a qualified exchange accommodation agreement until January 31, 2008, when the
second step of the like-kind exchange was completed in conjunction with the divestiture of certain non-core oil
and gas properties discussed above under Abraxas Divestiture and St. Mary acquired all of the limited liability
company interests of SMLEA, LLC from NBF Reverse Exchange, LLC. As of the date of closing of the
Rockford acquisition on October 4, 2007, through February 7, 2008, the assets held by SMLEA, LLC, were
leased by St. Mary under a triple net lease whereby St. Mary enjoyed the benefits and risks of all revenues and
costs attributed to the properties. The Gold River assets were managed by St. Mary under the terms of a
management agreement with SMLEA, LLC. On February 7, 2008, the Gold River assets were transferred to St.
Mary. As of this filing date SMLEA, LLC, is inactive and does not hold any assets.
In connection with the reverse like-kind exchange described above, St. Mary loaned an amount equal to
the purchase price of the assets to SMLEA, LLC. Based on the provision of FIN 46(R), the Company determined
that SMLEA, LLC is a variable interest entity for which St Mary is the primary beneficiary. Accordingly,
SMLEA, LLC was consolidated into St. Mary subsequent to SMLEA, LLC’s completion of the purchase of oil
and gas properties on October 4, 2007. As a result of the consolidation, St. Mary recognized all oil and gas
reserves and production as well as all revenues and expenses attributed to the Rockford acquisition beginning on
October 4, 2007. St. Mary’s loan to SMLEA, LLC was repaid on February 7, 2008.
Assets Held for Sale
As of December 31, 2008, the Company is engaged in marketing for sale certain non-core oil and gas
properties located in the Rocky Mountain and Gulf Coast regions. In accordance with SFAS No. 144, these
properties have been separately presented in the accompanying consolidated balance sheet at the lower of carrying
value or fair value less the cost to sell. The accompanying consolidated balance sheets as of December 31, 2008,
represents $1.8 million of assets held for sale, net of accumulated depletion, depreciation and amortization.
Assets held for sale were measured at carrying value, which was less than fair value less cost to sell as of
December 31, 2008. Any subsequent changes to fair value less the cost to sell will impact the measurement of
assets held for sale if the fair value is determined to be less than the carrying value of the assets. Asset retirement
obligation liabilities of $238,000 related to these properties have also been reclassified to liabilities associated
with oil and gas properties held for sale on the consolidated balance sheet as of December 31, 2008. The
Company determined that these sales do not qualify for discontinued operations accounting under EITF No. 03-
13.
Note 4 – Income Taxes
The provision for income taxes consists of the following:
2008
For the Years Ended December 31,
2007
(In thousands)
2006
Current taxes
Federal
State
Deferred taxes
Total income tax expense
$ 17,863
1,361
40,634
$ 59,858
$ 15,136
2,459
92,955
$ 110,550
$ 28,557
1,917
74,832
$ 105,306
F-19
As a result of the exercise of stock options, the Company reduced its income tax payable in each year
presented. The tax benefit to the Company of stock option exercises was $13.9 million in 2008, $9.9 million in
2007, and $16.1 million in 2006.
The components of the net deferred tax liability are as follows:
Deferred tax liabilities:
Oil and gas properties
Unrealized derivative asset
Interest on Senior Convertible Notes
Other
Total deferred tax liabilities
Deferred tax assets:
Net Profits Plan liability
Unrealized derivative liability
Stock compensation
State tax net operating loss carryforward or carryback
State and federal income tax benefit
Employee benefits and other
Other
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 (payable)
December 31,
2008
2007
(In thousands)
$
$
433,536
42,407
6,456
3,635
486,034
66,800
1,072
7,291
7,215
3,285
2,845
1,049
-
89,557
(3,146)
86,411
399,623
(42,766)
1,477
358,334
13,136
25
$
$
$
$
$
$
412,669
-
2,596
1,429
416,694
79,552
93,829
8,849
6,808
2,939
1,543
614
1,724
195,858
(3,556)
192,302
224,392
(1,425)
34,636
257,603
933
(105)
At December 31, 2008, the Company had estimated state net operating loss carryforwards of
approximately $174 million expiring between 2009 and 2028 and tax credits of $288,000 expiring between 2008
and 2017. A portion of the Company’s valuation allowance relates to 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. The Company has concluded that permanent items included in the calculation of income tax
for certain states may impact its ability to deduct operating losses and realize federal income tax deduction
benefits in certain states and has adjusted its valuation allowances accordingly. The remaining portion of the
valuation allowance relates to the Net Profits Plan liability and reflects an estimate of future executive
compensation that may not be deductible for income tax purposes when future cash payments occur under the
plan.
F-20
Federal income tax expense differs from the amount that would be provided by applying the statutory
U.S. Federal income tax rate to income before income taxes primarily due to the effect of state income taxes,
percentage depletion, the estimated effect of the domestic production activities deduction, impairment of
goodwill, and other permanent differences, as follows:
Federal statutory taxes
Increase (reduction) in taxes resulting from
State taxes (net of federal benefit)
Goodwill
Change in valuation allowance
Statutory depletion
Domestic production activities deduction
Other
Income tax expense from operations
For the Years Ended December 31,
2007
2008
(In thousands)
2006
$ 52,994
$ 105,092
$103,504
4,669
3,308
(409)
(294)
(275)
(135)
$ 59,858
5,111
-
896
(407)
(384)
242
$ 110,550
2,081
-
88
(315)
(287)
235
$105,306
At December 31, 2008, the Company recognized an impairment on Goodwill recorded in conjunction
with the Agate acquisition (see Goodwill in Note 1). In accordance with the provisions of SFAS No. 109 tax
benefit is not calculated upon the recognition of this expense. This resulted in a 2.2 percent increase in the
Company’s tax rate for the year ended December 31, 2008.
Acquisitions, drilling, and basis differentials impacting the prices received for crude oil and natural gas,
affect apportionment of taxable income to the states where the Company owns property. As its apportionment
factors change, the Company’s blended state income tax rate changes. This change, when applied to the
Company’s total temporary difference, 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 after completion of the
prior year income tax return and when significant acquisitions are closed during the current year.
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various
states. With few exceptions, the Company is no longer subject to U.S. federal or state income tax examinations
by these tax authorities for years before and including 2004. The Internal Revenue Service initiated an audit of
the Company’s 2005 tax year in 2008. The audit began on April 14th and is ongoing at year-end, but is expected
to close in the first quarter of 2009 with no material impact to the Company.
In the third quarter of 2007 the Company received a refund of income tax and interest of $3.1 million
from a carryback of net operating losses to the 2000 tax year. An additional $1.0 million due to the Company for
income tax refunds and accrued interest resulting from a carryover of minimum tax credits to the 2003 tax year
was received in January 2008. These amounts were previously recognized by the Company.
The Company adopted the provision of FASB Interpretation No. 48, “Accounting for Uncertainty in
Income Taxes” (“FIN No. 48”), on January 1, 2007. There was no financial statement adjustment required as a
result of adoption. At adoption, the Company had a long-term liability for unrecognized tax benefit of
$1.0 million and accumulated interest liability of $92,000. The entire amount of unrecognized tax benefit would
affect the Company’s effective tax rate if recognized. Interest expense in the 2008 accompanying consolidated
statements of operation includes a nominal $12,000 associated with income tax. Penalties associated with income
tax are recorded in general and administrative expense in the accompanying consolidated statements of
operations. There were no penalties associated with income tax recorded for the year ended December 31, 2008.
F-21
The total amount recorded for unrecognized tax benefits is presented below:
For the Years Ended December 31,
2008
2007
(In thousands)
$
957
173
(136)
$
1,112
233
(388)
$
994
$
957
Beginning balance
Additions for tax positions of prior years
Reductions for lapse of statute of limitations
Ending balance
Note 5 – Long-term Debt
Revolving Credit Facility
The Company’s revolving credit facility specifies a maximum loan amount of $500 million and has a
maturity date of April 7, 2010. Borrowings under the facility are secured by a pledge, in favor of the lenders, of
collateral that includes the majority of the Company’s oil and gas properties and the common stock of the material
subsidiaries of the Company. The borrowing base under the credit facility, as authorized by the bank group as of
the date of this filing, is $1.4 billion and is subject to regular semi-annual redeterminations. The borrowing base
redetermination process considers the value of St. Mary’s oil and gas properties and other assets, as determined by
the bank syndicate. The Company has elected an aggregate commitment amount of $500 million under the credit
facility. The Company must comply with certain covenants under its existing credit facility agreement, including
the limitation of the Company’s annual dividend rate to no more than $0.25 per share. The Company is in
compliance with all covenants under the credit facility. Interest and commitment fees are accrued based on the
borrowing base utilization percentage table below. Euro-dollar loans accrue interest at London Interbank Offered
Rate (“LIBOR”) plus the applicable margin from the utilization table, and Alternative Base Rate (“ABR”) loans
accrue interest at Prime plus the applicable margin from the utilization table. Commitment fees are accrued on
the unused portion of the $500 million aggregate commitment amount and are included in interest expense in the
accompanying consolidated statements of operations.
Borrowing base
utilization percentage
Euro-dollar loans
ABR loans
Commitment fee rate
< 50%
1.000%
0.000%
0.250%
≥ 50%< 75%
1.250%
0.000%
0.300%
≥ 75%< 90%
1.500%
0.250%
0.375%
≥ 90%
1.750%
0.500%
0.375%
The Company had $300.0 million, $285.0 million, and $318.5 million in outstanding loans under its
revolving credit agreement on December 31, 2008, 2007, and February 17, 2009, respectively. The Company had
$200.0 million, $215.0 million, and $181.5 million of available borrowing capacity under this facility as of
December 31, 2008, 2007, and February 17, 2009, respectively.
5.75% Senior Convertible Notes Due 2022
The Company called for the redemption of its 5.75% Senior Convertible Notes on March 16, 2007. The
call for redemption resulted in the note holders electing to convert the notes to common stock in accordance with
the conversion provision in the original indenture. The 5.75% Senior Convertible Note holders converted all
$100 million of the 5.75% Senior Convertible Notes to common shares at a conversion price of $13.00 per share.
The Company issued 7.7 million common shares in connection with the conversion.
F-22
3.50% Senior Convertible Notes Due 2027
On April 4, 2007, the Company issued $287.5 million in aggregate principal amount of 3.50% Senior
Convertible Notes. The 3.50% Senior Convertible Notes mature on April 1, 2027, unless converted prior to
maturity, redeemed, or purchased by the Company. The 3.50% Senior Convertible 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.
Holders may convert their notes based on a conversion rate of 18.3757 shares of the Company’s common
stock per $1,000 principal amount of the 3.50% Senior Convertible Notes (which is equal to an initial conversion
price of approximately $54.42 per share), subject to adjustment, contingent upon and only under the following
circumstances: (1) if the closing price of the Company’s common stock reaches specified thresholds or the trading
price of the notes falls below specified thresholds, (2) if the notes are called for redemption, (3) if specified
distributions to holders of the Company’s common stock are made or specified corporate transactions occur, (4) if
a fundamental change occurs, or (5) during the ten trading days prior to, but excluding the maturity date. The
notes and underlying shares have been registered under a shelf registration statement. If the Company becomes
involved in a material transaction or corporate development, it may suspend trading of the 3.50% Senior
Convertible Notes under the prospectus. In the event the suspension period exceeds 45 days within any three-
month period or 90 days within any twelve-month period, the Company will be required to pay additional interest
to all holders of the 3.50% Senior Convertible Notes, not to exceed a rate per annum of 0.50 percent of the issue
price of the 3.50% Senior Convertible Notes; provided that no such additional interest shall accrue after April 4,
2009.
Upon conversion of the 3.50% Senior Convertible Notes, holders will receive cash or common stock, or
any combination thereof as elected by the Company. At any time prior to the maturity date of the notes, the
Company has the option to unilaterally and irrevocably elect to net share settle its obligations upon conversion of
the notes in cash and, if applicable, shares of common stock. If the Company makes this election, then the
Company will pay the following to holders for each $1,000 principal amount of notes converted in lieu of shares
of common stock: (1) an amount in cash equal to the lesser of (i) $1,000 or (ii) the conversion value determined in
the manner set forth in the indenture for the 3.50% Senior Convertible Notes, and (2) if the conversion value
exceeds $1,000, the Company will also deliver, at its election, cash or common stock or a combination of cash
and common stock with respect to the remaining value deliverable upon conversion. Currently, it is the
Company’s intention to net share settle the 3.50% Senior Convertible Notes. However, the Company has not
made this a formal legal irrevocable election and thereby reserves the right to settle the 3.50% Senior Convertible
Notes in any manner allowed under the indenture as business conditions warrant.
If the holder elects to convert its notes in connection with certain events that constitute a change of
control before April 1, 2012, the Company will pay, to the extent described in the related indenture, a make-whole
premium by increasing the conversion rate applicable to the 3.50% Senior Convertible Notes. In addition, the
Company will pay contingent interest in cash, commencing with any six-month period beginning on or after
April 1, 2012, if the average trading price of a note for the five trading days ending on the third trading day
immediately preceding the first day of the relevant six-month period equals 120 percent or more of the principal
amount of the 3.50% Senior Convertible Notes.
On or after April 6, 2012, the Company may redeem for cash all or a portion of the 3.50% Senior
Convertible Notes at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed
plus accrued and unpaid interest, if any, up to but excluding the applicable redemption date. Holders of the 3.50%
Senior Convertible Notes may require the Company to purchase all or a portion of their notes on each of
April 1, 2012, April 1, 2017, and April 1, 2022, at a purchase price equal to 100 percent of the principal amount
of the notes to be repurchased plus accrued and unpaid interest, if any, up to but excluding the applicable purchase
date. On April 1, 2012, the Company may pay the purchase price in cash, in shares of common stock, or in any
combination of cash and common stock. On April 1, 2017, and April 1, 2022, the Company must pay the
purchase price in cash. Based on the market price of the 3.50% Senior Convertible Notes, the estimated fair value
of the notes was approximately $204 million as of December 31, 2008.
F-23
Weighted-Average Interest Rate Paid and Capitalized Interest
The weighted-average interest rate paid in 2008, 2007, and 2006 was 4.4 percent, 5.4 percent, and 7.6
percent, respectively, including commitment fees paid on the unused portion of the credit facility aggregate
commitment, amortization of deferred financing costs, amortization of the contingent interest embedded
derivative associated with the 5.75% Senior Convertible Notes for 2007 and 2006, and the effect of interest rate
swaps. The average outstanding loan balance in 2008 increased in comparison to the average outstanding loan
balance in 2007, while the rates associated with the balances decreased. The decrease is attributed to significantly
lower LIBOR and Prime rates for the specified periods in 2008 compared to 2007. Capitalized interest costs for
the Company for the years ended December 31, 2008, 2007, and 2006, were $3.7 million, $5.4 million, and $3.5
million, respectively.
Note 6 – Commitments and Contingencies
The Company has entered into various operating leases, which include drilling rig contracts, of
approximately $25.4 million, office space leases including maintenance of approximately $13.6 million,
compressor contracts of approximately $3.8 million, and vehicle leases of approximately $3.1 million. The
annual minimum lease payments for the next five years and thereafter are presented below:
Years Ending December 31,
2009
2010
2011
2012
2013
Thereafter
Total
(In thousands)
$
33,247
6,066
4,431
1,647
585
241
$ 46,217
The Company leases office space under various operating leases with terms extending as far as
May 31, 2014. Rent expense, net of sublease income, was $2.4 million, $1.9 million, and $1.5 million in 2008,
2007, and 2006, respectively. The Company also leases office equipment under various operating leases. The
Company has a non-cancelable sublease through May 2012, worth approximately $632,000, with payments due to
St. Mary of $185,000 per year through 2011 and $77,000 in 2012.
The Company is subject to litigation and claims that have arisen 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 litigation and claims will not have a material effect on the results
of operations, the financial position, or cash flows of the Company.
Note 7 – Compensation Plans
Cash Bonus Plan
The Company has a cash bonus plan, under which the Company has established a performance
measurement framework whereby selected employee participants may be awarded an annual cash bonus. As
amended by the Board of Directors on March 28, 2008, 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 current year’s
performance. Included in the general and administrative and exploration expense line items in the accompanying
consolidated statements of operations are $6.4 million, $3.6 million, and $1.9 million of cash bonus expense
related to the specific performance year for the years ended December 31, 2008, 2007, and 2006, respectively.
F-24
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 Company’s Compensation Committee of the 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, ten 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 ten percent level. The Net Profits Plan has been in place since 1991. Pool years prior to and including
2006 are fully vested. The 2007 pool year carries a vesting period of three years, whereby one-third is vested at
the end of the year for which participation is designated and one-third vests on each of the following two
anniversary dates. The 2006 and 2007 Pool years include a cap whereby the maximum benefit to full participants
from a particular year’s pool is limited to 300 percent of a participating individual’s adjusted base salary paid
during the year to which the pool relates. In December 2007 the Board approved a restructuring of the
Company’s incentive compensation programs. The change in the incentive compensation structure is designed to
replace the programs involving the grant of RSUs and the grant of participation interests in the Net Profits Plan
with a single long-term incentive program utilizing performance share awards. As a result, the 2007 Net Profits
Plan pool was the last pool established by the Company.
The Company records changes in the present value of estimated future payments under the Net Profits Plan
as a separate item in the accompanying consolidated 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. The table below presents the
estimated allocation of the change in the liability if the Company did allocate the adjustment to these specific
functional line items based on the current allocation of actual distributions being made by the Company. The change
in allocation of costs to the functional classification relates to the current composition of employees as compared to
those individuals that have terminated employment with the Company. Of the payments made under the Net Profits
Plan, 13 percent, 22 percent, and 54 percent would have been classified as exploration expense in the accompanying
consolidated statements of operations for the years ended December 31, 2008, 2007, and 2006, respectively. As
time progresses, less of the distributions relate to prospective exploration efforts as more of the distributions are
made to employees that have terminated employment and thereby do not provide ongoing exploration support.
General and administrative expense (benefit)
Exploration expense (benefit)
Total
401(k) Plan
$
$
2008
For the Years Ended December 31,
2007
(In thousands)
39,866
$
10,957
50,823
$
$
$
(29,672)
(4,368)
(34,040)
2006
10,820
12,939
23,759
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. 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 contributions to
the 401(k) Plan were $2.0 million, $1.5 million, and $1.2 million for the years ended December 31, 2008, 2007,
and 2006, respectively. No discretionary contributions were made by the Company to the 401(k) Plan for any of
these years.
F-25
Employee Stock Purchase Plan
Under the St. Mary Land & Exploration Company Employee Stock Purchase Plan (“the ESPP”), eligible
employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent
of 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 purchase period, and shares issued under the ESPP are restricted for a period of
18 months from the date issued. The ESPP is intended to qualify under Section 423 of the IRC. The Company
had to set aside 2,000,000 shares of its common stock to be available for issuance under the ESPP, of which
1,554,583 shares are available for issuance as of December 31, 2008. Shares issued under the ESPP totaled
45,228 in 2008, 29,534 in 2007, and 26,046 in 2006. Total proceeds to the Company for the issuance of these
shares were $1.1 million in 2008, $919,000 in 2007, and $814,000 in 2006.
The fair value of ESPP shares are measured at the date of grant using the Black-Scholes option-pricing
model. The fair values of ESPP shares issued 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,
2006
2007
2008
5.1%
4.1%
1.2%
0.3%
0.3%
0.2%
81.5%
0.5
27.2%
0.5
36.7%
0.5
For the ESPP offering periods during 2008, 2007, and 2006, the Company expensed $307,000, $260,000,
and $243,000, respectively, based on the estimated fair value of grants on the respective grant dates.
Equity Incentive Compensation Plan
There are several components to the equity compensation plan that are described in this section. Various
types of equity awards have been granted by the Company in different periods. These disclosures reflect the
culmination of the disclosure requirements for all equity awards still outstanding.
In May 2006 the stockholders approved the 2006 Equity Incentive Compensation Plan (the “2006 Equity
Plan”) to authorize the issuance of restricted stock, RSUs, non-qualified stock options, incentive stock options,
stock appreciation rights, and stock-based awards to key employees, consultants, and members of the Board of
Directors of St. Mary or any affiliate of St. Mary. The 2006 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 St. Mary Land & Exploration Company Restricted Stock Plan, and the St. Mary Land &
Exploration Company Non-Employee Director Stock Compensation Plan (collectively referred to as the
“Predecessor Plans”). All grants of equity are now made out of the 2006 Equity Plan, and no further grants will
be made under the Predecessor Plans. Each outstanding award under the Predecessor Plans prior to the effective
date of the 2006 Equity Plan continues to be governed solely by the terms and conditions of the instruments
evidencing such grants or issuances. An amendment and restatement of the 2006 Equity Plan was approved by
the Company’s stockholders at the 2008 annual stockholders’ meeting held on May 21, 2008.
As of December 31, 2008, 1.5 million shares of common stock remained available for grant under the
2006 Equity Plan. For an issuance of a direct share benefit such as an outright grant of common stock, a grant of
a restricted share, or a RSU grant, each direct share benefit issued counts as two shares against the number of
shares available to be granted under the 2006 Equity Plan. The issuance of a PSA is considered a direct share
benefit under the 2006 Equity Plan. At the end of each grant’s three-year performance period a final multiplier
ranging between zero and two is applied to each performance share so that each performance share granted has
the potential to result in the issuance of two shares of common stock. Consequently, each performance share
granted counts as four shares against the number of shares available to be granted under the 2006 Equity Plan.
F-26
Stock options granted count as one share for each instrument issued against the number of shares available to be
granted under the 2006 Equity Plan.
The Company has outstanding stock option grants under the Predecessor Plans and RSU awards under the
Predecessor Plans and the 2006 Equity Plan. The following sections describe the details of RSU grants and stock
options outstanding as of December 31, 2008.
Effective January 1, 2006, the Company adopted SFAS No. 123(R) using the modified-prospective
transition method. Under that transition method, compensation expense recognized in 2006, 2007, and 2008
includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of
January 1, 2006 based on the grant date fair value estimated in accordance with the original provision of SFAS
No. 123, and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on
the grant date fair value estimated in accordance with the provisions of SFAS No. 123 (R).
Performance Share Awards
In late 2007, St. Mary decided to transition from RSUs and interests in the Net Profits Plan to PSAs as the
primary form of long-term equity incentive compensation. On August 1, 2008, the Company granted 465,751
PSAs. PSAs represent the right to receive, upon settlement of the PSAs after the completion of a three-year
performance period ending June 30, 2011, a number of shares of the Company’s common stock that may be from
zero to two times the number of PSAs granted on the award date, depending on the extent to which the
Company’s performance criteria have been achieved and the extent to which the PSAs have vested. The
performance criteria for the PSAs are based on a combination of the Company’s cumulative total shareholder
return (“TSR”) for the performance periods and the relative measure of the Company’s TSR compared with the
cumulative TSR of certain peer companies for the performance period. The PSAs will vest 1/7th on August 1,
2009, 2/7ths on August 1, 2010, and 4/7ths on August 1, 2011. Total stock-based compensation expense related to
the PSAs granted in 2008 was $2.5 million.
In measuring compensation expense related to the grant of PSAs, SFAS No. 123(R) requires companies
to estimate the fair value of the award on the grant date. The fair value of PSAs has been measured using 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 PSAs, the Company cannot predict with certainty the
path its stock price or the stock price 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 to 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 PSAs.
The fair value of the Company’s PSAs granted on August 1, 2008, was equal to $12.3 million.
F-27
A summary of the status and activity of PSAs for the year ended December 31, 2008, is presented in the
following table.
At January 1, 2008
Granted
Vested
Forfeited
Weighted-
Average
Grant-Date
Fair Value
-
26.48
-
26.48
$
$
$
$
PSAs
-
465,751
-
(1,418)
At December 31, 2008
464,333
$
26.48
Restricted Stock Incentive Program Under the Equity Incentive Compensation Plan
The Company historically had a long-term incentive program whereby grants of restricted stock or RSUs
were awarded to eligible employees, consultants, and members of the Board of Directors. Restrictions and
vesting periods for the awards were determined at the discretion of the Board of Directors and were 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. These grants were determined annually
based on a formula consistent with the cash bonus plan.
St. Mary issued 158,744 RSUs on February 28, 2008, related to 2007 performance, 78,657 RSUs on
February 28, 2007, related to 2006 performance, and 484,351 RSUs on February 28, 2006, related to 2005
performance. The total fair value associated with these issuances was $6.0 million in 2008, $2.5 million in 2007,
and $16.4 million in 2006 as measured on the respective grant dates. The granted RSUs vested 25 percent
immediately upon grant and vest 25 percent on each of the first three anniversary dates of the grant.
In 2008, 2007, and 2006, the Company issued 4,290, 23,977, and 8,500 RSUs for various grants to certain
employees. These grants have various vesting schedules. The total fair value associated with these issuances was
$164,000, $803,000, and $319,000 for 2008, 2007, and 2006, respectively as measured on the respective grant
dates.
In 2008, 2007, and 2006, the Company issued 23,113, 32,504, and 29,827 shares respectively, of common
stock from treasury to its non-employee directors pursuant to the Company’s 2006 Equity Plan. The Company
recorded compensation expense related to the issuances of shares to non-employee directors of $1.0 million,
$983,500, and $976,000 for the years ended December 31, 2008, 2007, and 2006, respectively.
St. Mary issued 265,373 RSUs on June 30, 2008, as a transitional award to employees when the Company
moved from the old RSU program to the new PSA program. The total fair value associated with this issuance was
$17.2 million as measured on the grant date. One third of the granted RSUs vest on December 15th in 2008, 2009,
and 2010, respectively. Compensation expense is recorded monthly over the vesting period of the award. For
RSUs awarded prior to 2006, vested shares of common stock underlying the RSU grants were issued on the third
anniversary of the grant, at which time the shares carried no further restrictions. For all awards subsequent to the
2005 RSU grant, St. Mary eliminated the restriction period that extends beyond the vesting period so shares were
issued without restriction upon vesting, rather than on the third anniversary of the award. This change was
effected for existing awards in 2007 within the safe harbor adoption provisions of the newly enacted U.S.
Treasury regulations interpreting IRC provisions governing deferred compensation. A mutual election of the
employee and the Company was required to effect this change for each outstanding award. Essentially all of the
awards were modified by mutual election, and as such, the incremental value associated with removal of this
restriction period is being amortized over the remaining service period for these awards. For grants made
beginning with the 2006 grant period, the Company is using the accelerated amortization method as described in
FASB Interpretation No. 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or
Award Plans – an interpretation of APB Opinion No.’s 15 and 25,” whereby approximately 48 percent of the total
F-28
estimated compensation expense is recognized in the first year of the vesting period. As of December 31, 2008, a
total of 409,388 RSUs were outstanding, of which 7,091 were vested. The total RSU compensation expense for
the year ended December 31, 2008, 2007, and 2006 was $11.0 million, $8.4 million, and $8.5 million,
respectively. As of December 31, 2008, there was $13.4 million of total unrecognized compensation expense
related to unvested RSU awards. The unrecognized compensation expense is being amortized through 2011.
During 2008, the Company converted 678,197 RSUs, relating to awards granted in 2008, 2007, 2006, and
2005 into common stock based on the amended terms of the RSU 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 Company issued net 482,602 shares of
common stock associated with these grants. The remaining 195,595 shares were withheld to satisfy income and
payroll tax withholding obligations that occurred upon the delivery of the shares underlying those RSUs.
During 2007, the Company converted 427,059 RSUs into common stock, relating to awards granted in
2004. 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 302,370 shares of common stock associated with these grants. The remaining 124,689 shares
were withheld to satisfy income and payroll tax withholding obligations that occurred upon the delivery of the
shares underlying those RSUs.
In measuring compensation expense related to the grant of RSUs, SFAS No. 123(R) requires companies
to estimate the fair value of the award on the grant date. For grants prior to January 1, 2008, the Company had a
restriction period beyond vesting. Therefore, the fair value of the RSUs was inherently less than the market value
of an unrestricted share of St. Mary’s common stock. The fair value of RSUs had been measured using the Black-
Sholes option-pricing model. The Company’s computation of expected volatility was based on the historic
volatility of St. Mary’s common stock. The Company’s computation of expected life was determined based on
historical experience of similar awards, giving consideration to the contractual terms of the awards, vesting
schedules, and expectations of future employee behavior. The interest rate for periods within the contractual life
of the award was based on the U.S. Treasury constant maturity yield at the time of the grant.
The fair values of RSU awards granted 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 of the awards (in years)
For the Years Ended December 31,
2007
4.5%
0.3%
32.0%
3
2006
4.7%
0.3%
36.6%
3
Beginning January 1, 2008, RSU awards no longer have a restriction beyond vesting. Therefore the fair
value of an RSU award is equal to the market value of the underlying stock on the date of the grant.
Upon the adoption of SFAS No. 123(R), the deferred compensation balance of $5.6 million related to
outstanding RSU awards was reclassified to additional paid-in-capital within the shareholders’ equity section of
the balance sheet. This deferred compensation balance had been recorded in accordance with APB Opinion No.
25. The Company had recorded compensation expense in periods prior to January 1, 2006, for restricted stock
awards based on the intrinsic value on the date of grant. The intrinsic value was recorded as deferred
compensation in a separate component of shareholders’ equity and was amortized to compensation expense over
the vesting period. SFAS No. 123(R) requires expense recognized subsequent to the adoption date to be based on
fair value.
F-29
Stock Awards Under the Equity Incentive Compensation Plan
As part of hiring a new senior executive in the second quarter of 2006, St. Mary granted a special
common stock award of 20,000 shares that vested immediately upon commencement of employment. The fair
value associated with this award was $727,600. In addition to this award, the employee will earn an additional
5,000 shares over a four-year period and an additional 15,000 shares contingent on the Company meeting certain
net asset growth performance conditions over a four-year period. In 2008 and 2007, the Company issued 3,750
and 1,250 worth of guaranteed and contingent shares with associated fair values of $141,900 and $45,012,
respectively. The fair value of these awards will be recorded as compensation expense over the vesting period.
As part of hiring a new senior executive in the third quarter of 2008, St. Mary granted a special restricted
stock award of 15,496 shares that vest one half on December 15, 2009, and one half on December 15, 2010. The
fair value of this award was $600,005 and will be recorded as compensation expense over the vesting period. For
the year ended December 31, 2008, the Company recorded compensation expense of $115,000 related to this
award.
A summary of the status and activity of non-vested stock awards and RSUs for the year ended
December 31, 2008, is presented below:
Non-vested, at December 31, 2007
Granted
Vested
Forfeited
Weighted-
Average
Grant-Date
Fair Value
$ 32.26
$ 53.81
$ 22.92
$ 37.82
Shares
289,385
443,903
(291,659)
(39,332)
Non-vested, at December 31, 2008
402,297
$ 48.24
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 was December 31, 2004. Stock options to purchase shares of the Company’s common
stock had been issued to eligible employees and members of the Board of Directors. All options granted to date
under the option plans have been granted at exercise prices equal to the respective closing market price of the
Company’s underlying common stock on the grant dates, which generally occurred on the last date of a fiscal
period. All stock options granted under the option plans are exercisable for a period of up to ten years from the
date of grant.
During the year ended December 31, 2008, the Company recognized stock-based compensation expense
of approximately $17,000 related to stock options that were outstanding and unvested as of January 1, 2006.
There was no cumulative effect adjustment from the adoption of SFAS No. 123 (R). As of December 31, 2008,
there were no unvested stock options outstanding.
Prior to adopting SFAS No. 123(R), all tax benefits resulting from the exercise of stock options were
presented as operating cash flows in the accompanying consolidated statements of cash flows. SFAS No. 123 (R)
requires cash flows resulting from excess tax benefits to be classified as part of cash flows from financing
activities. Excess tax benefits are realized tax benefits from tax deductions for exercised options in excess of the
deferred tax asset attributable to stock compensation costs for such options. The Company has recorded
$13.9 million, $9.9 million, and $16.1 million of excess tax benefits for the years ended December 31 2008, 2007,
and 2006, respectively, as cash inflows from financing activities. Cash received from option exercises under all
F-30
share-based payment arrangements for the years ended December 31, 2008, 2007, and 2006 was $10.8 million,
$9.1 million, and $16.9 million, respectively.
A summary of activity associated with the Company’s Stock Option Plans during the last three years
follows:
Weighted
Average
Shares
Exercise Price
Aggregate
Intrinsic
Value
For the period ended December 31, 2006
Outstanding, start of year
4,698,243
$
12.21
Granted
Exercised
Forfeited
Outstanding, end of year
-
(1,489,636)
(87,005)
3,121,602
-
11.35
14.33
12.56
$
$
$
$ 75,800,322
Vested, or expected to vest, end of year
3,121,602
$
12.56
$ 75,800,322
Exercisable, end of year
2,966,944
$
12.56
$ 72,049,258
For the period ended December 31, 2007
Outstanding, start of year
3,121,602
$
12.56
Granted
Exercised
Forfeited
Outstanding, end of year
-
(733,650)
(2,452)
2,385,500
-
12.38
7.34
12.62
$
$
$
$ 62,007,749
Vested, or expected to vest, end of year
2,385,500
$
12.62
$ 62,007,749
Exercisable, end of year
2,378,000
$
12.62
$ 61,814,737
For the period ended December 31, 2008
Outstanding, start of year
2,385,500
$
12.62
Granted
Exercised
Forfeited
Outstanding, end of year
-
(868,372)
(7,418)
1,509,710
-
12.47
13.39
12.69
$
$
$
$ 11,529,600
Vested, or expected to vest, end of year
1,509,710
$
12.69
$ 11,529,600
Exercisable, end of year
1,509,710
$
12.69
$ 11,529,600
F-31
A summary of additional information related to options outstanding as of December 31, 2008, follows:
Options Outstanding
Weighted-
Average
Remaining
Contractual
Life
Weighted-
Average
Exercise
Price
Options Exercisable
Weighted-
Average
Remaining
Contractual
Life
Number
Exercisable
Range of
Exercise Prices
Number
Outstanding
$ 6.19
10.60
11.58
12.08
12.53
13.39
13.65
14.25
16.66
20.87
Total
- $ 7.97
- 10.86
- 12.03
- 12.50
- 12.66
- 13.39
- 13.65
- 14.25
- 16.66
- 20.87
174,346
155,428
223,381
161,268
213,754
31,723
130,585
194,119
166,474
58,632
1,509,710
1.5 years
3.1 years
3.6 years
4.0 years
4.5 years
4.8 years
4.5 years
5.0 years
2.0 years
6.0 years
$
6.69
10.72
11.92
12.47
12.59
13.39
13.65
14.25
16.66
20.87
174,346
155,428
223,381
161,268
213,754
31,723
130,585
194,119
166,474
58,632
1,509,710
1.5 years
3.1 years
3.6 years
4.0 years
4.5 years
4.8 years
4.5 years
5.0 years
2.0 years
6.0 years
Weighted-
Average
Exercise
price
$
6.69
10.72
11.92
12.47
12.59
13.39
13.65
14.25
16.66
20.87
The fair value of options was measured at the date of grant using the Black-Scholes option-pricing model.
Note 8 – Pension Benefits
The Company has a non-contributory 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”).
On December 31, 2006, the Company adopted the recognition and disclosures provisions of Statement of
Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans – an Amendment of the FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”).
This standard requires the Company to recognize the funded status (i.e., the difference between the fair value of
plan assets and the projected benefit obligation) of its pension plan in the consolidated balance sheets as either an
asset or a liability, with the corresponding adjustment to accumulated other comprehensive income, net of tax.
The adjustment to accumulated other comprehensive income at adoption represented the net unrecognized
actuarial losses and unrecognized prior service costs, both of which were previously netted against the plan’s
funded status in the Company’s consolidated balance sheets pursuant to the provisions of Statement of Financial
Accounting Standards No. 87, “Employers’ Accounting for Pension” (“SFAS No. 87”). These amounts will be
subsequently recognized as net periodic pension cost pursuant to the Company’s accounting policy for amortizing
such amounts. Further actuarial gains and losses that arise in subsequent periods and are not recognized as net
periodic pension cost in the same periods will be recognized as a component of other comprehensive income.
Those amounts will be subsequently recognized as a component of net period pension cost on the same basis as
the amounts recognized in accumulated other comprehensive income at adoption of SFAS No. 158.
F-32
The incremental effects of adopting the provisions of SFAS No. 158 on the Company’s consolidated
balance sheet at December 31, 2006, are presented in the following table. The adoption of SFAS No. 158 had no
effect on the Company’s accompanying consolidated statements of operations for the year ended
December 31, 2006, or for any prior period presented, and it will not affect the Company’s operating results in
future periods. The effect of recognizing this additional liability is included in the table below in the column
labeled “Prior to Adopting SFAS No. 158.”
Prior to
Adopting
SFAS No. 158
At December 31, 2006
Effect of
Adopting
SFAS No.
158
(In thousands)
$
$
$
2,619
(990)
2,619
As Reported
$
$
$
5,974
(1,922)
2,619
Accrued pension liability
Deferred income taxes
Accumulated other comprehensive income
$
$
$
3,355
(932)
-
Actuarial gains and losses are comprised of experience changes and effects of changes in actuarial
assumption. Experience changes are the effects of differences between previous actuarial assumptions and what
actually occurred. Included in accumulated other comprehensive income at December 31, 2008, are the following
amounts that have not yet been recognized in net periodic pension cost:
Unrecognized actuarial losses
Unrecognized prior service costs
Accumulated other comprehensive income
As of December 31,
2008
(In thousands)
$
$
4,441
-
4,441
The estimated net loss for the Qualified Pension Plan and the Nonqualified Pension Plan (the “Pension
Plans”) that will be amortized from accumulated other comprehensive income into net periodic benefit cost over
the next fiscal year is $312,000.
F-33
Obligations and Funded Status for Both Pension Plans
2008
For the Years Ended December 31,
2007
(In thousands)
2006
Change in benefit obligations
Projected benefit obligation at beginning of year
$
Service cost
Interest cost
Actuarial (gain) 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
Accumulated Benefit Obligation
$
$
$
$
$
14,744
2,229
889
(166)
(2,910)
14,786
8,755
(1,782)
2,489
(2,910)
6,552
(8,234)
9,922
$ 13,763
1,911
793
95
(1,818)
$ 14,744
$
$
7,789
536
2,248
(1,818)
8,755
$
(5,989)
$ 10,416
$
$
$
$
$
$
11,900
1,684
652
7
(480)
13,763
5,955
968
1,346
(480)
7,789
(5,974)
9,922
The combined underfunded status for the Pension Plans of $8.2 million at December 31, 2008, is
recognized in the accompanying consolidated balance sheets as a portion of other noncurrent liabilities. No plan
assets of the Qualified Pension Plan are expected to be returned to the Company during the fiscal year ended
December 31, 2008. There are no plan assets in the Nonqualified Pension Plan.
Information for Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets for Both Plans
As of December 31,
2008
2007
(In thousands)
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
$
$
$
14,786
9,922
6,552
$ 14,744
$ 10,416
8,755
$
F-34
Components of Net Periodic Benefit Cost for Both Pension Plans
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
$
2008
For the Year Ended December 31,
2007
(In thousands)
2006
$
2,229
889
$ 1,911
793
$
1,684
652
(565)
-
248
2,801
(540)
-
218
$ 2,382
(427)
-
296
2,205
$
Prior service costs are amortized on a straight-line basis over the average remaining service period of
active participants. Gains and losses in excess of ten 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.
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
As of December 31,
2008
6.6%
6.2%
6.1%
7.5%
6.2%
2007
6.1%
6.2%
5.9%
7.5%
6.2%
The Company’s weighted-average asset allocation for the Qualified Pension Plan is as follows:
Asset Category
Equity securities
Debt securities
Other
Total
Target
2009
60.0%
40.0%
-%
100.0%
2007
57.5%
As of December 31,
2008
52.0%
48.0%
-%
100.0%
42.5%
-%
100.0%
Equity securities do not include any shares of the Company’s common stock for any period presented.
There is no asset allocation of the Nonqualified Pension Plan since that plan does not have its own assets. An
expected return on plan assets of 7.5 percent was used to calculate the Company’s obligation under the Qualified
Pension Plan for 2008 and 2007. Factors considered in determining the expected return include the 60 percent
equity and 40 percent debt securities mix of investment of plan assets and the long-term historical rate of return
provided by the equity and debt securities markets. 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 statements of operations or cash flows from operating activities in future years.
F-35
Contributions
The Company contributed $2.5 million, $2.2 million, and $1.3 million, to the Pension Plans in the years
ended December 31, 2008, 2007, and 2006, respectively. Under the Pension Protection Act of 2006 St. Mary is
required to make a minimum contribution of $395,000 to the Pension Plans in 2009.
Benefit Payments
The Pension Plans made actual benefit payments of $2.9 million, $1.8 million, and $480,000 in the years
ended December 31, 2008, 2007, and 2006, respectively. Expected benefit payments over the next ten years are
as follows:
Years Ended December 31,
2009
2010
2011
2012
2013
2014 through 2018
(In thousands)
$
415
722
1,274
1,605
2,460
$ 14,437
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 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 consolidated 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 consolidated 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 6.5 percent to 12.0 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.
F-36
A reconciliation of the Company’s asset retirement obligation liability is as follows:
Beginning asset retirement obligation
Liabilities incurred
Liabilities settled
Accretion expense
Revision to estimated cash flows
Ending asset retirement obligation
As of December 31,
2008
2007
(In thousands)
$ 108,284
11,684
(24,154)
7,486
12,974
$ 116,274
$
$
77,242
10,851
(12,276)
5,458
27,009
108,284
Accounts payable and accrued expenses as of December 31, 2008, contain $7.3 million related to the
Company’s asset retirement obligation. The amount relates to the estimated plugging and abandonment costs
associated with one offshore platform that was destroyed during Hurricane Ike. Please refer to Note 15 –
Hurricanes Gustav and Ike for additional details. Accounts payable and accrued expenses contained $3.1 million
related to the Company’s asset retirement obligation as of December 31, 2007. The amount relates to the
estimated plugging and abandonment costs associated with one offshore platform that was destroyed during
Hurricane Rita. Plugging and abandonment of the platform has been completed as of December 31, 2008. Please
refer to Note 13 – Insurance Settlement for additional details.
Note 10 – Derivative Financial Instruments
The following table summarizes derivative instrument recognized gain (loss) activity:
Derivative contract settlements included in
realized oil and gas hedge gain (loss)
Ineffective portion of hedges qualifying for
hedge accounting included in unrealized
derivative (gain) loss
Non-qualifying derivative contracts included
in unrealized derivative gain (loss)
Interest rate derivative contract settlements
Total recognized gain (loss) on derivative
instruments
Oil and Gas Commodity Hedges
2008
For the Years Ended December 31,
2007
(In thousands)
2006
$ (101,096)
$
24,484
$ 28,176
11,209
-
(1,017)
(4,123)
(1,335)
226
(8,087)
993
(550)
$ (90,904)
$
19,252
$ 20,532
To mitigate a portion of the potential exposure to adverse market changes, the Company has entered into
various derivative contracts. The Company’s derivative contracts in place include swap and collar arrangements
for the sale of oil, natural gas, and natural gas liquids. As of December 31, 2008, the Company has hedge
contracts in place through 2011 for a total of approximately 8 million Bbls of anticipated crude oil production, 54
million MMBtu of anticipated natural gas production, and 1 million Bbls of anticipated natural gas liquids
production.
The Company attempts to qualify its oil and gas derivative instruments as cash flow hedges for
accounting purposes under SFAS No. 133 and related pronouncements. The Company formally documents all
relationships between the derivative instruments and the hedged production, as well as the Company’s risk
management objective and strategy for the particular derivative contracts. This process includes linking all
F-37
derivatives that are designated as cash flow hedges to the specific forecasted sale of oil or gas at its physical
location. The Company also formally assesses (both at the derivative’s inception and on an ongoing basis)
whether the derivatives being utilized have been highly effective in offsetting changes in the cash flows of hedged
production and whether those derivatives may be expected to remain highly effective in future periods. If it is
determined that a derivative has ceased to be highly effective as a hedge, the Company will discontinue hedge
accounting prospectively. If hedge accounting is discontinued and the derivative remains outstanding, the
Company will recognize all subsequent changes in its fair value on the Company’s consolidated statements of
operations for the period in which the change occurs. As of December 31, 2008, all oil and natural gas derivative
instruments qualified as cash flow hedges for accounting purposes. The Company anticipates that all forecasted
transactions will occur by the end of their originally specified periods. All contracts are entered into for other
than trading purposes.
The Company’s oil and gas hedges are measured at fair value and are included in the accompanying
consolidated balance sheets as assets and liabilities. The Company derives internal valuation estimates taking into
consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money and
then compares that to the counterparties’ mark-to-market statements. The considered factors result in an
estimated exit-price for each asset or liability under a market place participant’s view. Management believes that
this approach provides a reasonable, non-biased, verifiable, 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 and gas derivative markets are highly active. The fair value of oil and
natural gas derivative contracts designated and qualifying as cash flow hedges under SFAS No. 133 was a net
asset of $105.3 million at December 31, 2008.
The Company recognized a net loss of $90.9 million, a net gain of $19.3 million, and a net gain of
$20.5 million from its oil and natural gas and interest rate derivative contracts for the years ended December 31,
2008, 2007, and 2006, respectively.
After-tax changes in the fair value of derivative instruments designated as cash flow hedges, to the extent
they are effective in offsetting cash flows attributed to the hedged risk, are recorded in other comprehensive
income until the hedged item is recognized in earnings upon the sale of the hedged production. As of
December 31, 2008, the amount of unrealized gain net of deferred income taxes to be reclassified from
accumulated other comprehensive income to oil and gas production operating revenues in the next twelve months
was $64.5 million.
Any change in fair value resulting from ineffectiveness is recognized currently in unrealized derivative
(gain) loss in the accompanying consolidated statements of operations. Unrealized derivative (gain) loss for the
years ended December 31, 2008, 2007, and 2006, includes a net gain of $11.2 million, a net loss of $4.1 million,
and a net loss of $8.1 million, respectively, from ineffectiveness related to oil and natural gas derivative contracts.
Gains or losses from the settlement of oil and gas derivative contracts are reported in the total operating
revenues section of the accompanying consolidated statements of operations.
The company seeks to minimize ineffectiveness by entering into oil derivative contracts indexed to
NYMEX and natural gas derivative contracts indexed to regional index prices associated with pipelines in
proximity to the Company’s areas of production. As the Company’s derivative contracts contain the same index
as the Company’s sale contracts, this results in hedges that are highly correlated with the underlying hedged item.
Interest Rate Derivative Contracts
In September 2007, the Company entered into a one year floating-to-fixed interest rate derivative contract
for a notional amount of $75 million. Under the agreement, the Company paid a fixed rate of 4.90 percent and
received a variable rate based on the one-month LIBOR rates. The interest rate derivative contract was measured
at fair value using quoted prices in active markets. The interest rate swap was a straightforward, non-complex,
non-structured instrument that was highly liquid. This derivative qualified for cash flow hedge treatment under
F-38
SFAS No. 133 and related pronouncements. The Company recorded a net derivative loss of $1.0 million in the
accompanying consolidated statements of operations for the year ended December 31, 2008, related to this
interest rate derivative contract. This contract was settled in the third quarter of 2008.
Convertible Note Derivative Instrument
In relation the Company’s 5.75% Senior Convertible Notes converted in March 2007, the Company
entered into fixed-to-floating interest rate swaps of $50 million of principal in October 2003. Due to the
continued increases in interest rates, the Company entered into a floating-to-fixed interest rate swap in April 2005
through March 20, 2007, for this same notional amount of $50 million in order to effectively offset our fixed-to-
floating interest rate swaps. The impact of this instrument, when combined with the other interest rate swaps, was
that the Company fixed the net liability related to the interest rate swaps, and paid a 1.1 percent interest rate on
$50 million of notional debt through March 2007.
The contingent interest provision of the 3.50% Senior Convertible Notes is a derivative instrument.
However, the value of the derivative was determined to be deminimis at the inception of the instrument.
Note 11 – Fair Value Measurements
Effective January 1, 2008, the Company partially adopted SFAS No. 157 for all financial assets and
liabilities measured at fair value on a recurring basis. The statement establishes a framework for measuring fair
value and requires enhanced disclosures about fair value measurements. SFAS No. 157 defines fair value as the
price that would be received to sell an asset or paid to transfer a liability (an exact price) in an orderly transaction
between market participants at the measurement date. The statement establishes market or observable inputs as
the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of
market inputs. The statement establishes a hierarchy for grouping these assets and liabilities, 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 and 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
The following is a listing of the Company’s assets and liabilities required to be measured at fair value on
a recurring basis and where they are classified within the hierarchy as of December 31, 2008:
Assets:
Accrued derivative
Liabilities:
Accrued derivative
Net Profits Plan
Level 1
Level 2
(In thousands)
Level 3
$
$
$
-
-
-
$
133,190
$
-
$
$
27,920
-
$
-
$ 177,366
A financial asset or liability is categorized within the hierarchy based on the lowest level of input that is
significant to the fair value measurement. Following is a description of the valuation methodologies used by the
Company as well as the general classification of such instruments pursuant to the hierarchy.
F-39
Derivatives
The Company uses Level 2 inputs to measure the fair value of oil and gas hedges and the interest rate
swap. 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 and
then compares that to the counterparties’ mark-to-market statements. The considered factors result in an
estimated exit-price for each asset or liability under a market place participant’s view. Management believes that
this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing derivative
instruments.
Counterparty credit valuation adjustments are necessary when the market price of an instrument is not
indicative of the fair value due to the credit quality of the counterparty. Generally, market quotes assume that all
counterparties have near zero, or low, default rates and have equal credit quality. Therefore, 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 counterparties’ credit ratings and may ask counterparties to post collateral if their
ratings deteriorate. In some instances the Company will attempt to novate the trade with a more stable
counterparty.
Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value
of any liability position with a counterparty. 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, taking into account the Company’s credit rating, current credit spreads, and any change in
such spreads since the last measurement date. The majority of the Company’s derivative counterparties are
members of St. Mary’s secured 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 the requirements of SFAS No. 157 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.
Commodity Derivative Assets and Liabilities – The Company has a variety of derivatives including
commodity swaps and collars for the sale of oil, natural gas, and natural gas liquids. Standard oil and gas
activities expose the Company to varying degrees of commodity price risk. To mitigate a portion of this risk, the
Company may enter into natural gas, crude oil, and natural gas liquids derivatives to lower the commodity price
risk associated with an acquisition or when market conditions are favorable. The Company values these
derivatives using index prices, mark-to-market statements received from counterparties, counterparties’ credit
ratings, and the Company’s credit adjusted borrowing rate. The Company also factors in the time value of money.
As the value is derived from numerous factors, all of the Company’s commodity derivative assets and liabilities
are classified as having Level 2 inputs.
Interest Rate Derivative Assets and Liabilities – The Company had one interest rate swap agreement in
place for the notional amount of $75 million, which was settled in the third quarter of 2008. This instrument
effectively caused a portion of the Company’s floating rate debt to become fixed rate debt and was held with a
major financial institution. A mark-to-market valuation that took into consideration anticipated cash flows from
the transaction using quoted market prices, other economic data and assumptions, and pricing indications used by
other market participants was used to value the swap. Given the degree of varying assumptions used to value the
swap, it was deemed as having Level 2 inputs.
F-40
Net Profits Plan
The Net Profits Plan is a standalone liability for which there is no available market price, principal
market, or market participants. The inputs available for this instrument are unobservable, and therefore classified
as Level 3 inputs. The Company employs the income approach, which converts future 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 time value of money, the risk premium, and
nonperformance risk to calculate the fair value. There is a direct correlation between performance and the 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 a predominate number
of the pools, a discount rate of 12 percent is used to calculate this liability. This rate is intended to represent the
best estimate of the present value of expected future payments under the Net Profits Plan.
The Company’s estimate of its liability is highly dependent on commodity price and cost assumptions and
the discount rates used in the calculations. The commodity price assumptions are formulated by applying the
price that is derived from a rolling average of actual prices realized of the prior 24 months together with adjusted
New York Mercantile Exchange (“NYMEX”) strip prices for the ensuing 12 months. This average price is
adjusted to include the effect of hedge prices for the percentage of forecasted production hedged in the relevant
periods. The forecasted 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 and natural gas commodity markets. Higher
commodity prices experienced in recent years have moved more pools into payout status. The Company
continually evaluates the assumptions used in this calculation in order to consider the current market environment
for oil and gas prices, costs, discount rate, and overall market conditions.
As noted above, the calculation of the estimated liability for the Net Profits Plan is highly sensitive to
price estimates and discount rate assumptions. For example, if the commodity prices used in the calculation
changed by five percent, the liability recorded at December 31, 2008, would differ by approximately $14 million.
A one percentage point decrease in the discount rate would result in an increase to the liability of approximately
$9 million, while a one percentage point increase in the discount rate would result in a decrease to the liability of
approximately $8 million. Actual cash payments to be made to participants in future periods are dependent on
realized actual production, prices, and 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 the Net
Profits Plan liability. As such, the recorded fair value is based entirely on the management estimates that are
described within this footnote. While some inputs to the Company’s calculation of the 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 liabilities measured at fair value using Level 3 inputs:
Beginning balance
Net increase in liability (a)
Net settlements (a) (b)
Transfers in (out) of Level 3
Ending balance
2008
2006
For the Years Ended December 31,
2007
(In thousands)
$ 160,583
82,734
(31,911)
-
$ 211,406
$ 136,824
49,900
(26,141)
-
$ 160,583
$ 211,406
17,421
(51,461)
-
$ 177,366
(a) Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying
consolidated statements of operations.
(b) Settlements represent cash payments made or accrued for under the Net Profits Plan.
F-41
In February 2007 the FASB issued SFAS No. 159, which allows entities to choose, at specified election
dates, to use fair value to measure eligible financial assets and liabilities that are not otherwise required to be
measured at fair value. SFAS No. 159 was effective for the Company on January 1, 2008, at which point the
Company elected not to implement the fair value option.
Refer to Note 10 – Derivative Financial Instruments, and Note 7 – Compensation Plans, for more
information regarding the Company’s hedging instruments and the Net Profits Plan, respectively. Additionally,
refer to Note 5 – Long-term Debt for the disclosure of the December 31, 2008, fair value of the 3.50% Senior
Convertible Notes Due 2027.
Note 12 – Repurchase and Retirement of Common Stock
Stock Repurchase Program
In July 2006 the Company’s Board of Directors approved an increase of 5,473,182 shares to the
remaining authorized number of shares that can be repurchased under the Company’s original authorization
approved in August 1998, for a total number of shares to be repurchased under the plan of 6 million. As of the
date of this filing, the Company has Board authorization to repurchase up to 3,072,184 shares of common stock.
The shares may be repurchased from time to time in open market transactions or in privately negotiated
transactions, subject to market conditions and other factors, including certain provisions of St. Mary’s existing
credit facility agreement and compliance with securities law. Stock repurchases may be funded with existing cash
balances, internal cash flow, and borrowings under the credit facility. The details for shares repurchased and
retired are summarized as follows:
For the Years Ended December 31,
2007
2008
2006
Number of shares repurchased
Total purchase price, including commissions
Weighted-average price, including commissions
2,135,600
$ 77,149,451
36.13
$
792,216
$ 25,956,847
32.76
$
3,319,300
$ 123,106,775
37.09
$
Number of shares retired
Remaining shares authorized to be repurchased
2,945,212
3,072,184
-
5,207,784
3,275,689
6,000,000
Note 13 – Insurance Settlement
In April 2007 the Company reached a global insurance settlement for reimbursement of damages
sustained during Hurricane Rita in 2005. St. Mary’s net cash received in the final settlement was approximately
$33 million. As a result of this settlement, the Company recorded a gain of $5.2 million in other revenue in the
accompanying consolidated statements of operations for the year ended December 31, 2007. The Company
experienced significant weather-related and other delays in its retirement efforts and consequently incurred
additional retirement costs for the offshore platform. For the year ended December 31, 2008, the Company has
recorded a gain of $2.9 million associated with the insurance settlement, which is included in other revenue on the
Company’s consolidated statements of operations. The Company’s retirement efforts are complete as of
December 31, 2008.
Note 14 – SemGroup Bankruptcy
On July 22, 2008, SemGroup, L.P. and certain of its North American subsidiaries (collectively referred to
herein as “SemGroup”) filed voluntary petitions for reorganization under Chapter 11 of the United States
Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Certain SemGroup entities
purchase a portion of the Company’s crude oil production. As a result of the SemGroup bankruptcy filing the
Company recorded an allowance for doubtful accounts and bad debt expense of $16.6 million as of
December 31, 2008. The Company believes that it has fully allowed for all potentially uncollectible amounts and
believes that it has no remaining exposure resulting from this bankruptcy. In an effort to maximize its recovery,
F-42
the Company has filed the appropriate pleadings and is participating in certain adversary proceedings in the
SemGroup bankruptcy case to establish the Company’s secured and priority claims. The matter does not have a
material adverse effect on the Company’s liquidity or overall financial position.
Note 15 – Hurricanes Gustav and Ike
During the third quarter of 2008, assets in which the Company has an interest were impacted by
Hurricanes Gustav and Ike. The Company incurred damage to two wells and to its production facilities located at
Goat Island in Galveston Bay and minor damages to several other properties. The Vermilion 281 production
platform was lost in Hurricane Ike.
The Company maintains insurance that it expects to utilize with regard to the lost platform and damage to
several other properties. Due to the severe damage caused by the hurricanes, the Company currently expects the
total storm related costs to exceed the maximum insurance policy limit. During the third quarter of 2008, the
Company wrote off the carrying value of the Vermilion 281 platform, as well as the carrying value associated
with the production facility assets located at Goat Island. Additionally, the Company established an accrual for
the estimate of the remediation and various other property damage repair costs the Company expects to incur in
excess of its maximum insurance policy limit. As a result, the Company has recorded a $7.0 million loss, which
is included in other expense in the accompanying consolidated statement of operations for 2008. Any variation
between actual and estimated storm related costs will impact the final determination of the loss.
Note 16 – Oil and Gas Activities
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:
2008
For the Years Ended December 31,
2007
(In thousands)
2006
Development costs (1)
Exploration costs
Acquisitions
$ 586,579
92,199
$ 591,013
111,470
$ 367,546
126,220
Proved properties
Unproved properties – acquisitions of
proved properties (2)
Unproved properties - other
Total, including asset retirement obligation (3)
51,567
161,665
238,400
43,274
83,078
$ 856,697
23,495
38,436
$ 926,079
44,472
28,816
$ 805,454
(1) Includes capitalized interest of $3.7 million, $5.4 million, and $3.5 million in 2008, 2007, and 2006, respectively.
(2) Represents a portion of the allocated purchase price of unproved properties acquired as part of the acquisition of proved properties.
Refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale in Part IV, Item 15 of this report for additional information.
(3) Includes amounts relating to estimated asset retirement obligations of $15.4 million, $27.6 million, and $7.8 million in 2008, 2007,
and 2006, respectively.
F-43
Suspended Well Costs
The following table reflects the net changes in capitalized exploratory well costs during 2008, 2007, and
2006. The table does not include amounts that were capitalized and either subsequently expensed or reclassified
to producing well costs in the same period:
2008
For the Years Ended December 31,
2007
(In thousands)
2006
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,
$ 42,930
$ 22,799
$ 7,994
9,437
29,551
17,693
(36,842)
(6,088)
$ 9,437
(9,237)
(183)
$ 42,930
(2,888)
-
$ 22,799
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
2008
For the Years Ended December 31,
2007
(In thousands)
$ 29,368
13,562
$ 42,930
$ 17,958
4,841
$ 22,799
2006
$ 9,437
-
$ 9,437
-
3
1
Note 17 – Disclosures about Oil and Gas Producing Activities (Unaudited)
Oil and Gas Reserve Quantities
For all years presented, Netherland, Sewell and Associates, Inc (“NSAI”) prepared the reserve
information for the Company’s coalbed methane projects at Hanging Woman Basin in the northern Powder River
Basin as well as the Company’s non-operated coalbed methane interests in the Green River Basin. The Company
engaged Ryder Scott Company, L.P. to review internal engineering estimates for 80 percent of the PV-10 value of
its proved conventional oil and gas reserves in 2008, 2007 and 2006. 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.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids
that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are
those expected to be recovered through existing wells with existing equipment and operating methods. All of the
Company’s proved reserves are located in the continental United States and offshore in the Gulf of Mexico.
F-44
Presented below is a summary of the changes in estimated reserves of the Company:
2008
For the Years Ended December 31,
2007
2006
Oil or
Condensate
(MBbl)
Gas
(MMcf)
Oil or
Condensate
(MBbl)
Gas
(MMcf)
Oil or
Condensate
(MBbl)
Gas
(MMcf)
Developed and undeveloped
Beginning of year
Revisions of previous
estimate(a)
Discoveries and extensions
Infill reserves in an existing
proved field
Purchases of minerals in
place
Sales of reserves
Production
End of year (b)
Proved developed reserves
Beginning of year
End of year
78,847
613,450
74,195
482,475
62,903
417,075
(22,667)
677
(108,163)
41,077
5,238
1,166
9,489
28,483
524
857
10,946
36,723
5,424
92,389
4,592
69,090
4,131
49,107
356
(4,659)
(6,615)
51,363
26,956
(33,433)
(74,910)
557,366
567
(4)
(6,907)
78,847
91,374
(1,400)
(66,061)
613,450
11,857
(20)
(6,057)
74,195
28,030
(2,958)
(56,448)
482,475
68,277
47,106
426,627
433,210
61,519
68,277
358,477
426,627`
55,971
61,519
313,125
358,477
(a) For the year ended December 31, 2008, of the 244.2 BCFE downward revision of previous estimate 199.7 BCFE and 44.5 BCFE
relate to price and performance revisions, respectively. For the year ended December 31, 2007, of the 40.9 BCFE upward revision of
previous estimate 34.5 BCFE and 6.4 BCFE relate to price and performance revisions, respectively. For the year ended December
31, 2006, of the 14.1 BCFE upward revision of previous estimate (52.2) BCFE and 66.3 BCFE relate to price and performance
revisions, respectively.
(b) For the years ended December 31, 2008, 2007, and 2006 amounts included approximately 659, 316, and 523 MMcf respectively,
representing the Company’s net underproduced gas balancing position.
Standardized Measure of Discounted Future Net Cash Flows
Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing
Activities” (“SFAS No. 69”) prescribes guidelines for computing a standardized measure of future net cash flows
and changes therein relating to estimated proved reserves. The Company follows these guidelines, which are
briefly discussed below.
Future cash inflows and future production and development costs are determined by applying benchmark
prices and costs, including transportation, quality, and basis differentials, in effect at year end to the year-end
estimated quantities of oil and gas to be produced in the future. 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 ten percent
annual discount factor.
Future operating costs are determined based on estimates of expenditures to be incurred in developing and
producing the proved oil and gas 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
Securities and Exchange Commission. These assumptions do not necessarily reflect the Company’s expectations
F-45
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:
2008
2007
2006
Gas (per Mcf)
Oil (per Bbl)
$ 4.88
$ 33.91
$ 7.56
$ 88.71
$ 5.54
$ 53.65
The following summary sets forth the Company’s future net cash flows relating to proved oil and gas
reserves based on the standardized measure prescribed in SFAS No. 69:
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
2008
$ 4,463,894
(1,866,821)
(393,620)
(419,544)
1,783,909
(724,840)
As of December 31,
2007
(In thousands)
$ 11,629,679
(3,672,857)
(611,288)
(2,316,637)
5,028,897
(2,321,983)
2006
$ 6,653,455
(2,283,452)
(429,303)
(1,125,955)
2,814,745
(1,238,308)
$ 1,059,069
$ 2,706,914
$ 1,576,437
The principle sources of change in the standardized measure of discounted future net cash flows are:
2008
For the Years Ended December 31,
2007
(In thousands)
2006
Standard measure, beginning of year
Sales of oil and gas 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
Purchase of minerals in place
Development costs incurred during the year
Changes in estimated future development costs
Revisions of previous quantity estimates
Accretion of discount
Sales of reserves in place
Net change in income taxes
Changes in timing and other
Standardized measure, end of year
$ 2,706,914
$1,576,436
$ 1,712,298
(988,045)
(2,033,674)
(693,885)
1,320,994
(554,147)
(661,074)
288,162
33,215
105,031
213,554
(363,908)
386,118
(198,514)
947,955
(37,739)
$ 1,059,069
462,952
265,285
123,630
(32,566)
166,428
215,745
(1,915)
(573,259)
(122,931)
$2,706,914
280,822
263,762
67,864
114,007
34,940
249,417
(8,991)
200,858
(123,319)
$ 1,576,437
F-46
Note 18 – Quarterly Financial Information (Unaudited)
The Company’s quarterly financial information for fiscal 2008 and 2007 is as follows (in thousands,
except per share amounts):
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Year Ended December 31, 2008
Total operating revenues
Total operating expenses
Income (loss) from operations
Income (loss) before income taxes
Net income (loss)
$ 362,102
204,762
$ 157,340
$ 152,466
$ 95,996
Basic net income (loss) per common share
Diluted net income (loss) per common share
Dividends declared per common share
$
$
$
1.53
1.50
0.05
$ 356,942
298,691
58,251
$
$ 324,088
179,762
$ 144,326
$ 258,169
446,885
$ (188,716)
$
$
$
$
$
52,782
33,550
$ 139,206
88,047
$
$ (193,043)
$ (126,040)
0.54
0.53
-
$
$
$
1.42
1.40
0.05
$
$
$
(2.03)
(2.01)
-
Year Ended December 31, 2007
Total operating revenues
Total operating expenses
Income from operations
Income before income taxes
Net income
Basic net income per common share
Diluted net income per common share
Dividends declared per common share
$ 221,006
151,494
$ 69,512
$ 63,562
$ 39,950
$
$
$
0.70
0.63
0.05
$ 247,154
149,171
97,983
$
$ 246,687
151,336
95,351
$
$ 275,247
218,682
56,565
$
$
$
$
$
$
94,387
59,235
0.93
0.91
-
$
$
$
$
$
91,624
57,653
0.91
0.89
0.05
$
$
$
$
$
50,689
32,874
0.52
0.51
-
F-47
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
ST. MARY LAND & EXPLORATION COMPANY
(Registrant)
Date: February 23, 2009
By:
/s/ ANTHONY J. BEST
Anthony J. Best
President, Chief Executive Officer,
and Director
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, 2008, 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
President, Chief Executive Officer,
and Director
February 23, 2009
/s/ A. WADE PURSELL
A. Wade Pursell
/s/ MARK T. SOLOMON
Mark T. Solomon
Executive Vice President and Chief
Financial Officer
February 23, 2009
Controller
February 23, 2009
Signature
Title
Date
/s/ MARK A. HELLERSTEIN
Mark A. Hellerstein
/s/ BARBARA M. BAUMANN
Barbara M. Baumann
/s/ LARRY W. BICKLE
Larry W. Bickle
/s/ WILLIAM J. GARDINER
William J. Gardiner
/s/ JULIO M. QUINTANA
Julio M. Quintana
/s/ JOHN M. SEIDL
John. M. Seidl
/s/ WILLIAM D. SULLIVAN
William D. Sullivan
Chairman of the Board of Directors
February 23, 2009
Director
February 23, 2009
Director
February 23, 2009
Director
February 23, 2009
Director
February 23, 2009
Director
February 23, 2009
Director
February 23, 2009
STOCKHOLDER INFORMATION
I N V E S T O R S E R V I C E S
You can reach our corporate office at:
St. Mary Land & Exploration Company
1776 Lincoln Street, Suite 700
Denver, CO 80203
303-861-8140
Fax: 303-861-0934
We also have offices in Tulsa, Oklahoma; Shreveport, Louisiana;
Billings, Montana; Houston, Texas; and Midland, Texas
St. Mary Land & Exploration Company
7060 South Yale, Suite 800
Tulsa, OK 74136-5741
918-488-7600
St. Mary Land & Exploration Company
330 Marshall Street, Suite 1200
Shreveport, LA 71101
318-424-0804
St. Mary Land & Exploration Company
550 N. 31st Street, Suite 500
Billings, MT 59101
406-245-6248
St. Mary Land & Exploration Company
777 N. Eldridge Pkwy., Suite 1000
Houston, TX 77079
281-677-2800
St. Mary Land & Exploration Company
3300 N. A Street, Bldg. 7, Suite 200
Midland, TX 79705
432-688-1700
DESIGN BY: MARK MULVANY GRAPHIC DESIGN (DENVER, COLORADO)
PHOTOGRAPHY BY: JIM BLECHA (AURORA, COLORADO)
I N V E S T O R R E L AT I O N S C O N TA C T
Stockholders, securities analysts, or portfolio managers who have
questions or need information concerning St. Mary may contact
Brent Collins, Director of Investor Relations at 303-861-8140.
E-mail: bcollins@stmaryland.com
Annual Reports, 10Ks, 10Qs
To receive an information packet on St. Mary or to be added to
our mailing list, contact Pam Sweet at 303-861-8140.
E-mail:
information@stmaryland.com
Please visit our web site at: www.stmaryland.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 St. Mary Land & Exploration 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 17, 2009 the
Company had 62,305,557 shares of common stock outstanding, net
of 176,987 treasury shares owned by the Company.
Closing Prices
2008 — Quarter Ended
2007— Quarter Ended
March 31
June 30
September 30
December 31
high
low
high
low
$39.55
$32.94
$38.16
$33.80
64.64
62.51
34.99
38.36
33.68
15.31
39.87
36.86
44.07
35.90
31.80
36.16
OTHER INFORMATION
In 2008, St. Mary submitted to the New York Stock Exchange a
certificate of the Chief Executive Officer of St. Mary certifying that he
was not aware of any violation by St. Mary of the New York Stock
Exchange corporate governance listing standards. St. Mary has filed
with the SEC certifications of the Chief Executive Officer and the 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, 2008.
St. Mary Land & Exploration Company • www.stmaryland.com