St. Mary Land & Exploration
Annual Report 2009
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
05
06
07
08
09
05
06
07
08
09
Proved Reserves
(BCFE)
Proved Reserves Per Share
(MCFE)
1200
1000
800
600
400
200
20
15
10
05
05
06
07
08
09
05
06
07
08
09
Stockholders’ Equity
($ Millions)
Operating Cash Flow
($ Millions)
1200
1000
800
600
400
200
700
600
500
400
300
200
100
05
06
07
08
09
05
06
07
08
09
Financial Highlights
In thousands except production, proved reserves, price data, and per share amounts
Income Statement Data
Oil and gas production revenues
$ 756,601
$ 1,158,304
$ 936,577
$ 758,913
$ 711,005
2009
2008*
2007*
2006
2005
Gains on sales and other
Total operating revenues
Net income (loss)
Diluted earnings (loss) per share
Cash dividends declared and paid per share
Diluted weighted average common
75,600
142,997
$ 832,201
$ 1,301,301
$ (99,370)
$
$
(1.59)
0.10
$
$
$
87,348
1.38
0.10
53,517
$ 990,094
$ 187,098
$
$
2.90
0.10
28,788
$ 787,701
$ 190,015
$
$
2.94
0.10
28,585
$ 739,590
$ 151,936
$
$
2.33
0.10
shares outstanding
62,457
63,133
64,850
65,962
66,894
Balance Sheet Data
Working capital (deficit)
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)
$ (87,625)
$
15,193
$ (92,604)
$ 22,870
2,360,936
2,697,247
2,572,942
1,899,097
454,902
973,570
558,713
1,162,509
536,070
902,574
433,980
743,374
$
4,937
1,268,747
99,885
569,320
194.8
17.3
298.8
204.7
18.1
313.1
181.0
18.9
294.5
154.7
16.6
254.2
141.9
16.2
239.4
$
$
5.59
56.74
$
$
8.79
75.59
$
$
7.63
62.60
$
$
7.37
56.60
$
$
7.90
50.93
449,545
53,784
772,249
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
* On January 1, 2009, new authoritative accounting guidance under FASB ASC Topic 470, “Debt” (“ASC Topic 470”) required retrospective
application with respect to the accounting for the Company’s convertible debt. As a result, prior period balances presented have been adjusted to
reflect the period-specific effects of applying ASC Topic 470.
1
Letter to Stockholders
The theme of last year’s 2008 annual report was “Making the Turn,”
which has several meanings. When used in the context of the explo-
ration and production industry, it literally describes the drilling
operation in a horizontal well when you begin to turn the wellbore
horizontally and extend the lateral that will expose a larger section of
pay than what you could otherwise achieve with a vertical well. In a
broader and more strategic sense, the phrase conveys a perception
that a person or entity has transitioned through challenging or diffi-
cult circumstances and that the outlook is much more promising.
Both of these meanings were applicable to St. Mary in 2009. For the
former use of the phrase, it is relevant given the Company’s focus on
resource plays, most of which are drilled using horizontal wells. The
latter use is perhaps more significant since it aptly captures the
transformation that St. Mary has been undergoing the last couple of
years and our feeling that we are now well positioned for significant
growth ahead.
At this time a year ago, the general tone regarding the economy was
one of great uncertainty. The broader debt and equity markets saw
extreme volatility as questions about the global economic environment
and the duration of the downturn weighed on the minds of investors.
Concerns about demand put pressure on natural gas and oil prices.
Exploration and production companies dropped drilling rigs as
quickly as they could amid fears over liquidity and financial position,
with some firms selling debt or equity at high costs in order to quickly
repair their balance sheets. St. Mary was well positioned as it faced
these challenges. Our balance sheet was in solid shape as we entered
2009. Our hedging positions helped provide a base level of cash flow.
We had a reasonable amount of lease term left on our strategic lease-
hold positions and also had limited long-term commitments to rigs,
so we were able to slow our activity down very quickly. We made a
decision to focus our efforts on advancing our understanding of the
emerging resource plays in our portfolio, particularly the Eagle Ford
shale, the Haynesville shale, and the Marcellus shale. The goal was
to have an improved project inventory available for when economic
conditions improved. We also made a deliberate decision to defer
investment in development projects. Our view was that service
costs would come down throughout the year and that it made more
economic sense to develop projects in that lower cost environment,
particularly in light of the weaker commodity prices that we were
2
faced with at the time.
2009 RESULTS
It is probably safe to say that the business community is happy to have
2009 behind us. Our 2009 results certainly reflect the challenging
environment that we navigated throughout the year. Following is a
summary of our 2009 results:
• Proved reserves as of December 31, 2009 were 772.2 BCFE,
a decrease of 11% year over year.
• Reported average daily production for the year was
298.8 MMCFE, a decrease of 5% year over year.
• Our net loss for the year was $(99.4) million, or $(1.59) per
diluted share.
At first glance our 2009 performance clearly looks disappointing, but
some commentary and context is necessary to have a complete view
of last year’s performance.
As noted above, proved reserves at the end of 2009 were 772.2 BCFE,
which was a decrease of 11% from the 865.5 BCFE at the end of
2008. Our year-end 2009 proved reserves reflect the new SEC reserve
rules that went into effect at the end of the year, which among other
changes required that a lagging 12-month average price rather than
an end of year price be used to estimate proved reserves. Under these
rules, the prices used to estimate our proved reserves were $3.87 per
MMBTU of gas and $61.18 per barrel of oil, which were 32% lower
and 37% higher, respectively, than the prices used for proved reserves
at the end of 2008. Had we used the previous methodology, i.e. end
of year prices, our proved reserves would have been 897 BCFE as
of December 31, 2009, which would have represented 4% proved
reserve growth from the prior year.
Our reported proved reserves for year-end 2009 were impacted by the
sale of 44 BCFE of proved reserves, the majority of which related to
our non-strategic coalbed methane project at Hanging Woman Basin.
Revisions for the year were comprised of a net 12 BCFE upward price
revision and a downward engineering revision of 62 BCFE. The
pricing revision generally reflected positive price revisions from oil
properties and negative price revisions on gas properties which are
consistent with the change in prices used to estimate proved reserves
between 2008 and 2009. The majority of the downward performance
revision relates to our Wolfberry tight oil program in the Permian
Basin and Cotton Valley properties in our ArkLaTex region. We added
110 BCFE through the drill bit, which replaced our production for
the year. Drilling additions are directly related to the amount of
capital invested in drilling activities. As I mentioned earlier, we shifted
our focus away from development drilling for much of 2009 and this
reduced our potential to add proved reserves during the year, all other
things being equal.
Our reported production for 2009 was 109 BCFE, which was a
decrease from the 115 BCFE we produced in 2008. It should be
noted however that we have been divesting of non-core properties
over the last couple of years as part of our strategic transformation to
a resource play-focused company. Adjusting for these divestitures,
5
production was flat from 2008 to 2009. Given the significant reduction
in development capital in 2009, keeping production level on these
retained properties is something that we feel good about.
Our net loss for 2009 was $(99.4) million, or $(1.59) per diluted share.
This compares to net income of $87.3 million, or $1.38 per diluted
share, in 2008. Our 2009 results were impacted most significantly
by lower commodity prices and large non-cash impairments. The
average net realized price for 2009 was $6.94 per MCFE, which is
31% lower than the $10.11 per MCFE realized in 2008. The decrease
resulted in lower oil and gas revenues for the year. The impairment
of proved properties for 2009 was $174.8 million. The majority of
this impairment related to the first quarter of 2009, when properties
in eastern Oklahoma as well as coalbed methane properties in the
Rocky Mountain region were impaired. Low natural gas prices in
effect at the end of the first quarter contributed to these impairments.
We also recognized $45.4 million for abandonments and impairments
of unproved properties in 2009 to write off acreage that the Company
does not believe it will be able to develop under current capital
allocations or given our technical assessment of the acreage.
Our 2009 results clearly do not represent the level of performance that
we strive to achieve. However, I believe that we responded appropri-
ately to the difficult circumstances we were forced to face. Moreover,
our 2009 financial information does not capture the improvement in
our portfolio or the success of our transformation efforts.
LOOKING UP!
Which brings us to our theme for this year’s annual report—“Looking
Up.” Contrasting where we stand today to where we were a year
ago, we clearly are in a better position now and have better visibility
to where we are going as a company. Today, the broader economic
environment has stabilized and the economy appears to be recovering,
albeit slowly. The debt and equity markets are accessible again and at
reasonable costs. Commodity prices have improved from the lows
seen in early 2009. While we expect there will always be some level
of volatility in oil and gas prices, prices we are seeing in the
futures markets are at levels where we have developed a rational
growth plan for the company.
Things are certainly “Looking Up” at St. Mary. The nascent resource
plays that we had in our portfolio at the beginning of last year
experienced positive developments in 2009. In the Eagle Ford shale
program in South Texas, favorable results from our early testing on
our operated leasehold led us to expand our drilling in the second half
of 2009. We have been encouraged by the consistency of the results
we are seeing in the Eagle Ford program. Additionally, the richer gas
6
and condensate that we are producing on a portion of our acreage
position provides for a more valuable product stream that enhances our
returns. In our Marcellus shale program in north central Pennsylvania,
we drilled and completed two horizontal wells in 2009. The initial
tests from these two wells lead us to believe that we will be able to
pursue a commercial development program on much of our Marcellus
shale acreage. In the Haynesville shale, industry activity around our
leasehold in Shelby and San Augustine Counties, Texas appears to
confirm that some level of development of the Haynesville will take
place in East Texas. This is in contrast to the view of many a year ago
that acreage outside of North Louisiana would not be economic to
develop for the Haynesville shale. In addition to these three plays, the
application of horizontal drilling in the Granite Wash in the Anadarko
Basin and a better understanding of the Bakken and Three Forks
intervals in the Williston Basin have further improved our inventory.
This improvement in inventory is only valuable to our stockholders
if we have the financial capability to develop it, and I am pleased to
report St. Mary has the liquidity and financial strength to do just that.
We successfully managed our capital investments in 2009 to be within
our cash flows for the year and not only preserved our strong balance
sheet but strengthened it by yearend. By divesting over $300 million
of non-core properties in late 2009 and early 2010, most of which
were in the Rocky Mountain region, not only did we improve our
operational focus but we also raised cash that can be used to test and
develop our emerging resource plays and further strengthen our
financial position.
Our plan for 2010 is to continue advancing our emerging resource
plays. We have active operated programs budgeted in the Eagle Ford
and Haynesville shales. In the Marcellus shale, we have a number of
horizontal wells planned to further test our acreage as well as a seismic
shoot to acquire 3D data over our leasehold. We will also be focusing
development capital toward oilier parts of our portfolio, which means
increased activity in the Permian and Williston Basins, with better
margins due to higher crude prices.
With the broader economy recovering and our project portfolio
and financial capabilities improved over last year, things are clearly
“Looking Up” for St. Mary!
Anthony J. Best
President & Chief Executive Officer
9
Our Employees
David Abegg • Kelly Abelmann • Tonya Adam • Judy Adamsson • Jerry Alexander • Tina Allen • Dwayne Allen • Beverly Allgood
Billy Allmon • Melissa Andreani • Joanne Anschutz • Christopher Arnold • Debra Arroyo • Nathan Aucoin • Penny Ayers
Robert Bachman • Thomas Bagley • Eva Balderas • Justin Balkenbush • Michael Barbula • James Barnes • Jessica Baros
Tracy Bartholomew • Jayme Bauman • Rebecca Beaumier • Laura Beers • David Beers • William Bentley • Diane Bents
Sandra Beresford • Frank Berry • Tony Best • Gary Bjerke • Kerry Bjorgen • Kory Bjorgen • Brooke Blackburn • Jordan Blackburn
Carla Blair • Mark Bondy • Louis Bradshaw • Mark Brannum • Gary Breitling • Linda Brewer • Judith Brewer • Jill Briesch
Stephen Briggs • Chasity Broadbrooks • Marianne Brocklebank • Cynthia Brogren • Brandy Brooks • Gregory Brooks
Nancy Brostuen • Laurel Brown • Leah Brumlow • Kristyn Bryan • Michael Bryant • Nathan Buchanan • Willis Buckley
Janet Buckley • Rita Buress • Jacqueline Burgesser • Susan Burk • Karen Burns • Katharen Burns • Naomi Burrow • Linda Burrow
Angel Bustamante • Paul Button • Debra Calhoun • Virginia Calhoun • Diane Cameron • Guadalupe Campos • Bruce Carathers
Ashley Cardenas • Roel Cardona • William Carignan • Nicholas Carlson • Randall Carlson • Bartow Carroll • William Carroll
Vicki Cartledge • Debra Casey • Michael Cash • Megan Casselman • Paul Causey • Donna Caviness • Joanne Celentano
Melchor Cervantez • Melanie Chaffin • Jarrod Charlifue • Louis Chemin • Karen Chism • Frank Chomout • Avis Clark
Donald Clark • Rachelle Clemons • Cody Clickner • 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 • Kelly Davis • Marilee Day • Carla Deangelis • Janice DeLuzio • Revah DeMar • Michael Detrick • Marian Devasher
Jimmy Dew • Ryan Dial • Ricardo Diaz • Robin Diedrich • Debra Dinner • Linda Ditsworth • John Dodds • Clare Domingue
Jamie Donovan • Carolyn Doolittle • Kevin Dorrington • Cal Dowhaniuk • William Downs • Karla Drange • David Dubiel
Mark Dunham • Kristal Duval • Mark Eck • Joyce Eckardt • James Edwards • Tanner Egan • Kevin Eide • Patricia Ellington
Harvey Ellis • Dustin Ellis • Teri Elrod • Robert Elrod • James Erlandson • Rodrigo Escamilla • Ryan Fairfield • Thomas Ferguson
Gary Fifer • Carla Fishback • Rosendo Flores • Margarito Flores • David Flores • David Flurry • Tammy Fode • Dana Fox
Julie Fragnito • Dale Fredrickson • George Friesen • Paula Frisbee • Eric Fugate • Jenice Fugere • Jeffrey Fulco • Alfredo Galan
Sandra Garbiso • Shannon Garcie • Carlos Garza • Albert Garza • Gayle Gaul • Jessica Gaul • Bob Geries • Karun Ghimire
Mac Gilger • Jesse Gilman • Aric Glasser • Vicky Gonzales • Gazaan Gonzalez • Jennifer Gordon • Donna Grant • Bryan Graves
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 • Angela Hanson • Mary Harris • Vera Harris • Betty Hartung • Eric Hauwert • Amber Hawkins • Cheryl Head
William Hearne • Thomas Hedegaard • Larry Hedstrup • Daniel Heggem • Roxie Helstad • Meghan Hendershot • Andrew Hennes
Shawn Heringer • Angel Hernandez • Randy Herr • Jerardo Herrera • Connie Heston • Lorain Hicks • Donald Hill • Garth Hill
Delitha Hilliard • Kevin Hillyard • Greg Hilton • Ezequiel Hinojosa • Mary Hirsch • Betty Hodge • Cory Hoffman
Rebecca Houghton • Cornell House • Randy House • Lorraine Huck • Donna Huddleston • Carrie Hunter • Christopher Hunter
Brian Huzzey • Robert Jackson • Joey Jafek • Toni Jarrett • Bridgett Jenefor • Jette Jenks • John Jensen • Jenny Jensen
Hutch Jobe • Debra Johnson • Deanna Johnson • James Johnston • Lisa Johnston • Joel Jones • Kyle Jordison • Gail Joy
10
Alley Juma • Brandon Junker • Valeri Kaae • Patrick Kadel • Sherry Karst • Benjamin Kennedy • Robert Kessel • John Killian
Raymond Killpack • Kevin Kindrick • Johnathan King • Jill Klein • John Kluz • Stephen Knapp • Kenneth Knott • Janice Knotts
Daniel Koehling • Brady Kolb • Eileen Kosakowski • Alicia Kucharek • Renee Kucharek • Sarah Lacey • Hung Lai • Twyla Lance
Regina Lanier • Jason Lara • Barbara Larson • Paul Larson • Kathryn Leathers • Mildred Leblanc • Timothy Lechner • Barry Lee
James Legare • Myron Leintz • Greg Leyendecker • Gregory Little • Carl Lothringer • Ryan Lowden • David Lustig • Dean Lutey
Mary Ellen Lutey • Francis Lynch • Robert Lynn • Candace Lyon • Patrick Lytle • Robyn Maez • Jennifer Major • Luke Malsam
Sarah Mann • Laurie Marcotte • Nathan Markham • Joanna Martin • Jesse Martin • Victoria Martinez • Danielle Maruna
Thomas Mathis • Catherine Mayo • Derek McFarlane • Joseph McFerran • Dana McGoveran • Michael McGoveran
LaKesha McGuire • Joshua McIver • Dustin McLean • Kevin McMaster • Charles McNaney • Michael McNeely • Jennifer McQueen
John Mears • Robbin Mekelburg • Leonardo Mendez • Charles Mercer • Virginia Minturn • John Mitchell • Jamie Mitzo
Matthew Modjeski • Shane Mogensen • John Monark • Steven Moore • Shane Moran • Carol Moreno • Paul Morrison
Thomas Morrow • Bruce Mortenson • Mark Mount • Jennifer Mueller • Donald Mueller • Mark Mueller • Teresa Muhic
Chad Mulliniks • Macy Mullins • Robert Nail • Billy Neal • Rodney Nelson • Roger Nelson • Pamela Nelson • Justin Nelson
Lehman Newton • Van-Tuyet Nguyen • Casey Nichols • Stephanie Nicolarsen • John Nightengale • Nicholas Norberg
Elmer Nordsven • Robert Norman • Breanne Oakley • Tolulope Ogundare • Michelle O’Neil • Sybil Onyeagoro • Fred Otis
Jay Ottoson • Brenda Oyloe • Billie Ann Pagliasotti • Guadalupe Parham • Donna Parker • Randall Parpart • Kimberly Paulson
Rory Pendleton • Saturnino Perez • Carlos Perez • Kelly Perrin • Brandy Perry • Randy Pester • Randy Pharo • Susan Piehl
Julie Pike • Nancy Pochatko • Anita Pollock • David Ponto • Donald Poole • Charles Porter • Paul Porter • Wesley Portra
Susan Potts • Robert Prescott • Billy Preston • Kimberly Preston • Sheryl Price • Loren Prigan • Bonnie Pritchett • Sandra Puettman
Stephen Pugh • Michael Pulliam • 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
Curt Rodriguez • Dawn Rohrs • Jon Ruby • Robin Ryder • Jonathan Sachen • Steve Sadler • Ricardo Saldana • Greg Salveson
Pat Salwey • Karin Sanford • Ronald Santi • Joseph Scarfarotti • Benjamin Schalk • Michael Schanck • Carol Schellhouse
Dinah Schlecht • Dennis Schmidt • Beverly Schreiner • Jeffrey Schurbon • Kelly Scott • Douglas Selvius • Karla Semm • James Shaffer
Edward Shannon • Tiffany Sharp • Michael Shaw • Kelly Shield • Brennan Short • Deborah Siegmund Lilly Simpson • Eric Skaalure
Jared Slade • Michael Slay • Craig Smith • Sabrina Smith • Jayme Smith • Benjamin 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 • Robert Stillwell • Amber Stockdale • Diane Stokes • Luke Studer • Laura Sutfin
Bradford Sutton • Kelly Sutton • Pamela Sweet • Elizabeth Sylvan • Janice Tabbert • John Takach • Elizabeth Taruscio • John Taylor
Sherri Thibodeaux • Benjamin Thogerson • Estelle Thomas • Linda Thompson • Dave Thompson • Braden Thompson
Connie Thunem • Kerin Todaro • Joy Torgerson • Staci Tribelhorn • Ashley Trunnell • Andrew Urie • Joseph Van • David Van Brunt
Kirk Vanderbeek • Charlotte Vangsnes • Rhonda Vardeman • Paul Veatch • Juanita Vela • Kathleen Vitas • Shari Vitt • Margaret Vogl
Charles Waelde • Kelli Wahrmund • Edwin Wakefield • Wilford Walker • Rhett Wallace • Vicky Wallace • Jamie Ward • Galen Watt
Ann Watters • Justin Watts • Lynette Watts • Cynthia Wedge • Charles Wedlund • Randall Weeks • Jon Weible • Marlon Wells
Daniel Wells • Dianna West • David Whitcomb • Lonnie Whitson • Shane Wiggins • Linda Wilkins • John Williams
Brandon Williams • Dannet Williams • Jane Williams • Kathy Willis • Jerry Willman • Kelsey Wilson • Stanley Wilson • 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
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, 2009
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)
1776 Lincoln Street, Suite 700, Denver, Colorado
(Address of principal executive offices)
41-0518430
(I.R.S. Employer Identification No.)
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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12
months (or for such shorter period that the registrant was required to submit and post such files).
Yes 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 62,106,243 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale
price of the common stock on June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, for
$20.87 per share as reported on the New York Stock Exchange was $1,296,157,291. 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 16, 2010, the registrant had 62,777,688 shares of common stock outstanding, which is net of 126,893 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 2010 annual meeting of stockholders to be filed within 120 days after December 31, 2009.
DOCUMENTS INCORPORATED BY REFERENCE
ITEM
TABLE OF CONTENTS
PART I
ITEMS 1. and 2. BUSINESS and PROPERTIES
General
Strategy
Significant Developments in 2009
Outlook for 2010
Assets
Reserves
Production
Productive Wells
Drilling Activity
Acreage
Delivery Commitments
Major Customers
Employees and Office Space
Title to Properties
Seasonality
Competition
Government Regulations
Cautionary Information about Forward-Looking Statements
Available Information
Glossary of Oil and 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
Financial Results of Operations and Additional Comparative Data
Comparison of Financial Results and Trends between
2009 and 2008
Comparison of Financial Results and Trends between
2008 and 2007
Overview of Liquidity and Capital Resources
Critical Accounting Policies and Estimates
Other Liquidity and Capital Resources Information
Accounting Matters
Environmental
Climate Change
PAGE
1
1
1
1
4
4
9
13
14
14
15
15
16
16
16
16
16
17
18
20
21
26
39
39
39
39
43
48
50
50
58
62
66
68
79
82
82
82
83
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
85
85
85
85
88
88
88
88
88
89
89
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 our growth. Additionally, we believe that we will be able to create more long-term value for our stockholders
by building an asset base that allows for more predictable growth in production and reserves and does not rely
solely on acquisitions. 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 legacy assets 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 2009
Broad Economic Downturn. Beginning in the latter part of 2008 and continuing into the first half of
2009 the global economy experienced a significant downturn related primarily to concerns over the
U.S. financial system. The impact of the downturn spread quickly and affected a wide range of
industries. There were two significant ramifications to the exploration and production industry. The
first was that capital markets were essentially frozen at the beginning of 2009. Equity, debt, and
credit markets were 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 and the associated negative impact on energy demand resulted in a
significant decline in oil and gas prices. We significantly scaled back our operating activity in
response to these price decreases. Our hedging program helped moderate the price fluctuations that
we experienced, particularly in the first half of 2009. After the first quarter of 2009, the broader
economy began to stabilize. The public markets for debt and equity opened up and banks began to be
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less restrictive with credit. We were able to renew our credit facility in April of 2009. The outlook
for commodity prices also began to improve. The rapid decrease in activity across the exploration
and production industry led many oilfield service companies to cut their prices to the benefit of
ourselves and our peers as the year progressed. As industry conditions improved throughout the year,
drilling activity increased in many parts of the country.
Advancement of Resource Play Potential. From late 2007 through 2009, we established meaningful
positions in several new potential resource plays, principally the Eagle Ford shale, Haynesville shale,
and the Marcellus shale. Over the past year we worked to advance our understanding of these plays
and move them closer to development mode. The greatest progress was made in our Eagle Ford shale
program in South Texas. We successfully tested seven wells across our operated acreage position
during the second half of 2009. The early results from this program suggest wells at the southern end
of our acreage will produce drier gas while wells drilled further north will produce higher BTU-
content gas and condensate. We are currently booking only the parallel offsets to producing wells as
proved undeveloped locations. As a result, meaningful potential exists to grow proved reserves on
our operated acreage because of our planned drilling activity for 2010. On our joint venture acreage
in Dimmitt County, Texas, we believe these wells will produce even higher amounts of condensate
and oil compared to our operated position. In the Haynesville shale program in the ArkLaTex region,
a number of successful wells were drilled around our acreage position in Shelby and San Augustine
counties in East Texas in 2009. The 3D seismic shoot of our acreage was recently received, and we
have begun our horizontal drilling in the play. In our Marcellus shale program in north central
Pennsylvania, we drilled and completed our first two horizontal wells during 2009. Initial indications
from the well tests were encouraging. We are in the process of constructing the gathering system that
will connect these two wells, as well as future wells, to the sales pipeline.
Volatility in Commodity Prices. Prices in 2009 were generally more stable than in 2008. However
the exploration and production sector still experienced significant volatility in the prices for crude oil
and natural gas. Our operations and financial condition are significantly impacted by these prices.
The spot price for NYMEX crude oil in 2009 ranged from a high of $81.04 per barrel in October to a
low of $33.98 per barrel in February. The average spot price for oil during the year was $61.99 per
barrel. The volatility in crude oil prices in early 2009 was driven by concern regarding global
demand for oil. A volatile U.S. dollar was also a contributing factor in crude price volatility as the
spot price of oil reacted to the relative weakening or strengthening of the U.S. dollar.
The spot price for gas at Henry Hub, a widely used industry measuring point, averaged $3.94 per
MMBtu in 2009, with a high of $6.11 per MMBtu in January and a low of $1.88 per MMBtu in
September. Natural gas prices came under pressure in 2009 as a result of lower domestic product
demand caused by the weakening economy; and concerns over excess supply of natural gas due to the
high productivity of several emerging shale plays in the U.S. 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
regions, as well as a lack of pipeline takeaway capacity or local demand. This was most pronounced
in our Mid-Continent and Rocky Mountain regions. However, local index differentials, in the areas
where we sell gas, narrowed towards NYMEX Hub prices in late 2009.
Decrease in Year-End Proved Reserve Estimates. Our estimated proved reserves decreased 11
percent to 772.2 BCFE at December 31, 2009, from 865.5 BCFE at December 31, 2008. We added
109.6 BCFE from our drilling program during the year, with our emerging resource play in the Eagle
Ford shale in the Maverick Basin in South Texas contributing a significant portion of those additions.
Our programs targeting the Woodford shale in eastern Oklahoma and the Bakken/Three Forks
formations in the North Dakota portion of the Williston Basin also added meaningful additions in
2009. We sold 44.2 BCFE of proved reserves during the year, with roughly 90 percent of those
relating to the divestiture of our coalbed methane project at Hanging Woman Basin along the border
of Montana and Wyoming. The balance of the divested properties sold in 2009 related to non-
strategic assets spread across our company.
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We had a net downward revision of 49.6 BCFE that consisted of 61.6 BCFE in downward
engineering revisions and an upward pricing revision of 12.0 BCFE. The largest portion of the
performance revision relates to producing properties in our Wolfberry tight oil program in the
Permian Basin in West Texas. Well performance data collected during 2009 at our Sweetie Peck and
Halff East programs that target the Wolfberry interval indicate that these assets are underperforming
our year-end 2008 decline forecasts. Accordingly, we removed 37 BCFE from proved reserves in the
Permian region, primarily related to the Wolfberry tight oil program. We believe a significant portion
of these reserves, while not meeting the criteria to be booked as proved reserves at year-end, are
likely to eventually be produced. We also had a downward performance revision of approximately 12
BCFE related to certain Cotton Valley assets in our ArkLaTex region. The pricing methodology used
to determine proved reserves changed in 2009 in accordance with new rules promulgated by the SEC.
Rather than using year-end pricing, companies are now required to use the 12-month average of the
first of month prices for oil and gas to estimate proved reserves. This change in methodology from
2008 resulted in a higher oil price and a lower gas price in effect for determining year-end proved
reserves for 2009. As a result, we recognized positive pricing revisions in our oil-weighted Rocky
Mountain and Permian regions that offset the negative price revisions we recognized in the natural
gas weighted Mid-Continent, ArkLaTex, and South Texas & Gulf Coast regions. Under the previous
methodology of using year-end pricing for the determination of proved reserves, we would have had a
four percent increase in proved reserves to approximately 897 BCFE.
Prior to and subsequent to year-end, we entered into several transactions to divest non-strategic
properties across our company. Proved reserves associated with these properties are estimated to be
approximately 71 BCFE and primarily relate to the previously announced Rocky Mountain oil
property divestiture. Part of this divestiture package closed in mid-February 2010 and we expect the
balance to close by the end of the first quarter of 2010.
Impairment of Proved Properties. We recognized pre-tax non-cash impairments of proved properties
in the amount of $174.8 million in 2009 compared with $302.2 million of proved property
impairments in 2008. A significant decrease in commodity prices, including differentials, during the
first quarter of 2009 caused the majority of the non-cash impairment. The largest portion of the
impairment in 2009 was $97.3 million related to assets located in the Mid-Continent region which
were significantly impacted by both low natural gas prices and wider than normal differentials at the
end of the first quarter. The ArkLaTex region was impacted by a $20.4 million impairment related to
downward pricing and engineering revisions. We incurred a $14.0 million impairment of proved
properties related to the write-down of certain assets located in the Gulf of Mexico for which we are
relinquishing our ownership interests to satisfy our abandonment obligations.
Abandonment and Impairment of Unproved Properties. During the year, we abandoned or impaired
$45.4 million related to unproved properties. The largest specific components of the 2009
impairment and abandonment related to the Floyd Shale acreage located in Mississippi and acreage in
Oklahoma. The remaining write-offs were related to acreage we believe we will not keep based on
our current capital allocation plans or related to acreage that we do not believe will be prospective.
Divestiture of Non-Strategic Properties. In 2009 we undertook an effort to sell a number of non-
strategic properties in order to optimize our portfolio. The objective of these divestitures is to dispose
of properties with limited future drilling potential while generating cash that can be used in the testing
and development of our resource plays. During 2009 we sold roughly 44.2 BCFE of reserves, the
vast majority of which related to our coalbed methane program in Hanging Woman Basin. We
received $39.9 million in proceeds from the sales we closed in 2009. Subsequent to year end, we
closed on a portion of our previously disclosed sale of non-strategic oil and gas properties in the
Rocky Mountain region. The Wyoming sub-package was sold to Legacy Reserves Operating LP.
The cash received at closing was $118.7 million before commission costs. The final sales price is
subject to normal post-closing adjustments and is expected to be finalized by the end of second
quarter of 2010. Additionally, subsequent to year-end, we also entered into agreements to sell the
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remaining non-core properties from our Rocky Mountain divestiture package in North Dakota for
$137 million to Sequel Energy Partners LP, as well as some other minor properties for approximately
$6 million. We expect these divestitures to close by the end of the first quarter of 2010. In total,
these divestitures represent 71 BCFE of proved reserves.
Outlook for 2010
The general economic outlook for the country has improved compared to this time a year ago. We
successfully weathered a rough 2009, and in the process advanced a number of potential resource plays and
improved our financial condition.
As we enter 2010, our company is well positioned both financially and operationally. Early in 2009, we
extended the maturity of our revolving credit facility and subsequently reduced outstanding borrowings on that
facility during the year. As of February 16, 2010, we had $467 million available to us under the revolving credit
facility. We have no debt maturities until 2012. Additionally, we believe that access to the capital markets has
improved significantly since last year and that we could access capital through the public markets, if necessary.
From an operational standpoint, we believe 2010 has the potential to be very promising for our company. We will
be building upon our successful testing programs from 2009. We have moved the Eagle Ford shale program
closer to development mode, and it will receive the largest portion of our capital budget this year. We will also be
allocating more capital toward oil and rich natural gas projects, given their higher returns in the current
environment. Specifically, we will be drilling more Wolfberry tight oil and Bakken/Three Forks wells in the
Permian and Rocky Mountain regions, respectively. In the Haynesville shale, we have begun our horizontal
drilling program. We continue to monitor service costs as the recent uptick in industry activity may pressure rates
for the drilling and completion of wells higher than the levels we saw in 2009. We intend to fund these projects
with our current year operating cash flows and proceeds from our previously announced non-core divestitures.
Assets
As of December 31, 2009, we had estimated proved reserves of 53.8 MMBbl of oil and 449.5 Bcf of
natural gas. The 12-month average prices in effect on December 31, 2009, used to estimate proved reserves were
$61.18 per barrel of oil and $3.87 per MMBtu of gas, which represent a 37 percent increase and 32 percent
decrease, respectively, from prices used to estimate proved reserves as of December 31, 2008. On an equivalent
basis, our proved reserves were 772.2 BCFE as of December 31, 2009, a decrease of 11 percent from 865.5 BCFE
at the end of the prior year. On an equivalent basis, 82 percent of our proved reserves were classified as proved
developed as of year-end. Total proved oil and gas reserves had a PV-10 value of $1.3 billion and a standardized
measure value of $1.0 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 2009 our average daily
production was 194.8 MMcf of gas and 17.3 MBbl of oil, for an average equivalent production rate of
298.8 MMCFE per day, which was down slightly compared with 313.1 MMCFE per day for 2008. Adjusting for
production from properties sold as part of our active divestiture efforts over the last two years, production from
retained properties has remained essentially flat from 285.6 MMCFE per day in 2008 to 284.7 MMCFE per day in
2009.
In 2009 we incurred costs of $419.0 million for drilling and exploration activities and acquisitions. This
was 51 percent lower than the $857.7 million incurred in 2008. During 2009 we incurred exploration costs of
$154.1 million compared to $92.2 million in 2008. We incurred development costs of $223.1 million in 2009,
which was 62 percent lower than the $587.6 million in 2008. The decrease in development dollars and increase in
exploration dollars reflects our decision to not invest capital in development projects in a low commodity price
environment, particularly while service costs were declining. Moreover we ramped up our exploration efforts to
accelerate our understanding of our emerging resource plays, particularly in the Eagle Ford shale, in order to put
ourselves in a positive position once industry conditions improved. In 2009 we invested a total of $41.7 million
on undeveloped leasehold compared to $83.1 million in 2008. The majority of our 2009 leasing activity targeted
emerging resource plays in our South Texas & Gulf Coast and Mid-Continent regions. We spent approximately
$126.4 million in 2008 on undeveloped leasehold, including leasehold acquired as part of producing property
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acquisitions, targeting the Cotton Valley and Bakken formations in the ArkLaTex and Rocky Mountain regions,
respectively. In 2009, we did not make any meaningful acquisitions.
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, 2009.
ArkLaTex
Mid-
Continent
South
Texas &
Gulf Coast
Permian
Rocky
Mountain
Total(1) (2)
2009 Proved Reserves
Oil (MMBbl)
Gas (Bcf)
Equivalents (BCFE)
Relative percentage
Proved Developed %
0.4
117.8
120.0
15%
65%
1.1
216.7
223.5
29%
83%
1.4
44.9
53.2
7%
53%
14.2
30.1
115.2
15%
83%
36.7
40.0
260.3
34%
93%
53.8
449.5
772.2
100%
82%
PV-10 Values (in millions)
Proved Developed
Proved Undeveloped (3)
Total Proved
Relative percentage
$ 92.1
0.1
$ 92.2
7%
2009 Production
Oil (MMBbl)
Gas (Bcf)
Equivalent (BCFE)
Avg. Daily Equivalents
(MMCFE/d)
Relative percentage
0.1
14.2
14.9
40.8
14%
$ 266.3
(7.4)
$ 258.9
20%
0.3
34.4
36.0
98.7
33%
$ 50.5
(2.0)
$ 48.5
4%
$ 295.5
34.9
$ 330.4
26%
$ 548.7
5.4
$ 554.1
43%
$ 1,253.1
31.0
$ 1,284.1
100%
0.4
7.2
9.7
26.6
9%
1.8
4.1
15.2
41.5
14%
3.7
11.2
33.3
91.2
30%
6.3
71.1
109.1
298.8
100%
(1) Totals may not add due to rounding.
(2) Included in the total are approximately 71 BCFE related to non-core properties that we have either divested or entered into agreements
to divest subsequent to December 31, 2009.
(3) St. Mary will record proved undeveloped locations with a negative PV-10 value if we have intent to drill the well provided it generates
positive net undiscounted cash flow and meets our economic criteria based on our corporate price call.
ArkLaTex Region. St. Mary’s operations in the ArkLaTex region are managed from our office in
Shreveport, Louisiana. The ArkLaTex region was our first operating office, originating from an acquisition in
1992. For years the activities of this region focused on the Cotton Valley, James Lime, and Travis Peak
formations in the region. In 2008 the Haynesville shale emerged as the leading potential resource play in East
Texas and North Louisiana.
The ArkLaTex region incurred costs of $65.7 million in 2009 for exploration, development, and
acquisition activities. This amount is 70 percent lower than the $218.4 million spent in 2008, which included
$60.3 million in acquisitions targeting the Cotton Valley formation in East Texas. Significantly less money was
spent on development and exploration activity in 2009 compared to 2008. With the emergence of the Haynesville
shale late in 2008 and into 2009, our operating partner activity targeting the Cotton Valley and James Lime
formations declined significantly as they focused on testing and developing their Haynesville shale properties.
We participated in a number of partner-operated wells that focused on the Haynesville shale. Additionally, we
elected to defer most of our operated horizontal Haynesville drilling until we could acquire seismic data that
would help mitigate risk for larger parts of our acreage. Our 2009 operated activity in the ArkLaTex region was
primarily focused on drilling wells that preserve acreage. The region’s 2009 production decreased 19 percent to
14.9 BCFE as a result of the lower levels of activity described above. Our 2009 year-end proved reserves were
120.0 BCFE, which is 29 percent lower than the 2008 year-end proved reserves of 170.0 BCFE. The decrease in
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proved reserves is primarily the result of 14.9 BCFE of production and 48.0 BCFE of negative pricing and
engineering revisions. At year-end 2009 we have no proved reserves booked for our Haynesville potential related
to our acreage in Shelby and San Augustine Counties in East Texas.
The Elm Grove Field is the highest value field in the ArkLaTex region at year-end 2009. We own
interests in approximately 500 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 36 percent, although it varies greatly across
the field. Generally, our working interest increases as one moves south in the field. The primary zones of interest
in this field have historically been the Cotton Valley and Hosston. The vast majority of the value and proved
reserves in this field relate to those zones. Over the past year, our operating partner has focused its drilling efforts
almost exclusively in the Haynesville shale on acreage in the field where we have no working interest. As a
result, we have very little PV-10 value or proved reserve volumes attributable to the Haynesville shale at the end
of 2009 at Elm Grove field.
Our plans for 2010 in the ArkLaTex region are based almost entirely on testing and developing the
Haynesville shale on our operated acreage. We have approximately 41,000 net acres across the region with
potential for the Haynesville shale, of which 31,000 is located in Shelby and San Augustine Counties in East
Texas. Roughly 70 percent of our Haynesville spending will be operated by us and will be focused on our
acreage in these counties. We plan to drill seven horizontal wells targeting the Haynesville shale in 2010. We
will also participate in a number of wells with operating partners in both northern Louisiana and East Texas that
target the Haynesville interval. We expect that we will invest a minimal amount of capital this year on the drilling
of James Lime and Cotton Valley wells, although we will have some leasehold and seismic expenditures related
to those programs in 2010. In recent months, the industry has begun to test the Bossier shale, which is above the
Haynesville shale. As information emerges about this interval, we could choose to test this formation in 2010.
We believe a large portion of our acreage position in East Texas is also prospective for the Bossier shale.
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 also oversees our Marcellus shale activity in north central Pennsylvania.
In 2009 we incurred costs of $106.8 million in the Mid-Continent region for exploration, development,
and acquisition activity, which is 34 percent less than the $162.0 million deployed in 2008. Approximately
$97 million was deployed in exploration and development activities in 2009, with the remainder being spent on
leasing activities. The 2009 activity for the region focused on the continued development of our horizontal
Woodford shale program in the Arkoma Basin and included the successful completion of two pilot programs to
test the effect of near simultaneous fracture stimulation on increased density drilling. In the Anadarko Basin, we
maintained a consistent level of operated activity targeting the Deep Springer formation throughout the year. We
also participated in a largely non-operated program targeting the stacked washes in western Oklahoma. Lastly,
we drilled and completed our first initial tests in our Marcellus shale program during the second half of 2009.
Mid-Continent production in 2009 was 36.0 BCFE, an increase of 9 percent from the 33.0 BCFE produced in
2008. Proved reserves at the end of 2009 were 223.5 BCFE, a decrease of five percent from the 234.4 BCFE
report for the prior year. The decrease in proved reserves was due in large part to the low gas price in effect at
year end which resulted in downward pricing revisions of roughly 17 BCFE for some previously booked proved
reserves. The low gas price also resulted in no new proved undeveloped reserves being added in the region at
December 31, 2009.
The Centrahoma Field in the Arkoma Basin is the highest value field in the Mid-Continent region. At
year-end, we have nearly 160 producing wells in the field. Over half of those wells were completed in the
Woodford shale and the majority of those were drilled horizontally. The Woodford shale is the primary
contributor to proved reserve volumes and PV-10 value at the Centrahoma Field. We believe there is additional
drilling potential in the Woodford shale as well as uphole development in the Cromwell and Wapanucka
formations.
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The largest operated portion of the Mid-Continent region’s budget for 2010 relates to our emerging
program targeting the Marcellus shale in north central Pennsylvania. We currently have roughly 42,000 net acres
leased or optioned in the Marcellus shale. Four operated horizontal wells are planned for the year and we expect
to begin drilling late in the second quarter of 2010. Additionally, we are currently in the process of constructing a
gathering system through a large portion of our acreage position that will connect the first two wells we drilled in
2009 to sales as well as service future development. Our Marcellus program for 2010 also includes amounts for
leasehold, facilities, and seismic costs. In the horizontal Woodford, our program for 2010 is primarily designed to
preserve core acreage. Six operated horizontal wells are currently planned, and we will participate in a handful of
wells that will be operated by others. In the Anadarko Basin, we have four wells planned in the successful Deep
Springer program our regional team has run for the past several years. Four operated horizontal wells are planned
for the horizontal Granite Wash play that is emerging in western Oklahoma. Our first horizontal Granite Wash
well in this part of the play commenced drilling in December of 2009 and is still drilling as of the date of this
report.
South Texas & 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 $3.6 million of oil and gas royalty revenue in 2009. Our presence
expanded along the Gulf Coast 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. During 2009, one of the other zones of interest, the Eagle
Ford shale, was successfully tested by St. Mary and a competitor. Today, the Eagle Ford shale is one of the most
promising shale plays in North America. The focus of our Houston office has steadily shifted over the last couple
of years away from projects along the Gulf Coast and in the Gulf of Mexico toward programs onshore that allow
for multiple years of drilling inventory.
Our capital expenditures for exploration, development, and acquisition activity in the South Texas & Gulf
Coast region decreased slightly from $120.9 million in 2008 to $115.1 million in 2009. Nearly all of the capital
deployed in the South Texas & Gulf Coast region in 2009 targeted formations in south western Texas, namely the
Eagle Ford and Pearsall shales. We worked early in the year to increase our leasehold position in the area.
Additionally, we continued to participate in a joint venture that allowed us to earn acreage by carrying a partner
through completion in a series of wells. In mid-2009, we began operating on acreage where we had very high
working interests, in many cases a 100 percent. The encouraging results from our earlier tests led to an increase
in the number of wells drilled for 2009. To date, the results on our operated acreage have been very encouraging.
On large parts of our acreage, we have seen rich-gas and condensate in the production stream which enhances the
economics of these gas wells. We did not make any meaningful investments in properties along the Gulf Coast or
in the Gulf of Mexico during the year. Our last operated platform in the Gulf of Mexico was largely remediated
and abandoned in 2009 after being damaged by Hurricane Ike in 2008.
Production for the South Texas & Gulf Coast region in 2009 was 9.7 BCFE, a decrease of 32 percent
from the 14.3 BCFE produced in 2008. The largest contributor to the decline year over year was the result of our
sale of our interest in the Judge Digby Field in southern Louisiana at the end of 2008. Excluding the impact of
this divestiture, production declined approximately one percent year over year. Proved reserves at the end of
2009 were 53.2 BCFE, an increase of 21 percent from the 43.8 BCFE reported in the prior year. The increase in
proved reserves reflects drilling additions of 39.0 BCFE related entirely to our program in the Eagle Ford shale
and were offset by downward price revisions related to our Olmos gas program. On our operated acreage
targeting the Eagle Ford shale, we had seven proved developed wells which were producing at year-end. This
program is at an early stage of its development and accordingly at December 31, 2009, we are booking only
parallel offset locations to our producing wells as proved undeveloped locations. The result is a total of 14 proved
undeveloped locations being booked as of year-end at a total of 24.6 BCFE. Our operated Eagle Ford program is
the most significant asset in the South Texas & Gulf Coast region.
Our plans for 2010 in the South Texas & Gulf Coast region are focused exclusively on the Eagle Ford
shale. As of year-end, we have 250,000 net acres leased or optioned, which is an increase from our previously
reported total of 225,000 net acres. We operate roughly 168,000 of those net acres, most of which is at 100
percent working interest, with the balance of the acreage being located on joint venture acreage with an industry
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partner. We plan to drill 34 horizontal wells on our operated acreage in 2010. Part of our drilling program will be
aimed at further delineating the play in order to make infrastructure commitments later this year. We currently
are able to market all of our production and expect to do so in the future by working with midstream partners to
ensure we have adequate takeaway and processing capacity to meet our needs. We will also be conducting a
series of tests to help determine the ultimate spacing for the reservoir. Our operating partner plans to operate two
to three rigs during 2010 on our joint venture acreage where we have a net working interest of 25 percent.
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 major acquisition of oil
properties that targeted the Wolfberry tight oil play. 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 $76.5 million in the region in 2009 compared to $163.2 million in 2008. This
decrease in capital investment reflects the significant slowdown in our drilling activity during the first half of the
year in response to the low oil prices being realized late in 2008 and early in 2009. 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 also tested other exploration concepts in the Permian during the
year. Production in the region increased 9 percent over the prior year, from 13.8 BCFE in 2008 to 15.1 BCFE in
2009. Proved reserves as of the end of 2009 were 115.2 BCFE, which is a decrease of 26 percent from 2008 year-
end reserves of 155.9 BCFE. The decrease in our estimate of proved reserves relate to engineering revisions on
proved producing properties in our Wolfberry tight oil program. Well performance data collected during 2009
from our Sweetie Peck and Halff East assets which target the Wolfberry indicate that these assets are
underperforming our year-end 2008 decline forecasts. Accordingly, we have removed 37 BCFE from proved
reserves in the Permian region, primarily related to the Wolfberry tight oil program. We believe that a significant
portion of these reserves, while not meeting the criteria to be booked as proved reserves at year-end, are likely to
eventually be produced.
As of the end of December 2009, the Sweetie Peck assets in the Permian Basin collectively were the
highest value entity in the region. Sweetie Peck field had 182 producing wells at year-end. We have slightly over
20 proved undeveloped locations booked at Sweetie Peck at year-end. We also believe there are a meaningful
number of unbooked future drilling locations that we will be able to pursue in future years.
The largest drilling program planned for the Permian region in 2010 is in our Sweetie Peck tight oil assets
where we plan to drill 32 operated wells this year. Most of the development will take place on 80- and 40-acre
spaced locations. Despite the downward Wolfberry engineering revisions in our proved reserve estimates referred
to above, these projects continue to meet our economic standards for drilling, albeit at lower proved reserve
volumes. We will also continue to work on an exploratory program that began in 2009 and we plan to conduct a
modest drilling program in 2010, primarily using vertical wells.
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 2001 and early 2003
with significant property acquisitions from Choctaw, Burlington Resources, and Flying J. In recent years, we
have been divesting of non-core properties in the Rocky Mountain region in an effort to focus our human and
investment capital on the most impactful plays in that region.
We incurred costs of $51.2 million in 2009 for exploration, development, and acquisitions in the Rocky
Mountain region, compared to $190.3 million in 2008. Our 2009 budget in the Rocky Mountain region reflected
the low oil prices and the wide price differentials we experienced at the end of 2008. For much of 2009, we did
not have any operated rigs running in the region. Our capital investments were primarily focused on the Bakken
and Three Forks formations and were heavily weighted toward the back half of the year. Proved reserves for the
Rocky Mountain region were 260.3 BCFE at year-end compared with 261.4 BCFE as of the end of 2008. The
slight decrease in proved reserves is the result of selling 40.3 BCFE of proved reserves in the region during the
8
year, most of which related to the sale of non-strategic coalbed methane project at Hanging Woman Basin, offset
by net positive price and engineering revisions of 50.0 BCFE. Production in the Rocky Mountain region for 2009
was 33.3 BCFE. Total regional production was down five percent from 34.9 BCFE in 2008. Adjusting for the
effect of the divestitures, production in the region would have declined 1.3 BCFE, or four percent, year over year.
The Elm Coulee Field is the highest value field in the region at year-end 2009. The reserves in this field
are predominately oil, and the Bakken is the formation of primary interest. The field is largely developed with
only a handful of remaining drilling locations identified as proved undeveloped.
The Bakken and Three Forks formations in the Williston Basin will be our primary focus in 2010. We
plan to drill 17 horizontal wells targeting these formations in 2010. The majority will be located in our Bear Den
asset program in McKenzie and Williams counties in North Dakota where we have roughly 16,000 net acres.
Additionally, we have built a 70,000 net acre position with potential for the Bakken and Three Forks in
McKenzie, Williams, and Divide counties that we will test during 2010. We are currently drilling a test well in
Wyoming targeting the Niobrara formation as part of our ongoing exploration effort. We plan to evaluate our
results, as well as those of nearby competitors, during 2010.
Reserves
In December 2008, the SEC announced that it had approved revisions designed to modernize oil and gas
reporting requirements. A key revision to the rules pertains to commodity prices. The economic producibility of
reserves and discounted cash flows are now based on a 12-month average commodity price as opposed to a year-
end price in estimating reserves. The prices used in the calculation of proved reserve estimates as of
December 31, 2009, were $61.18 per Bbl and $3.87 per MMBTU for oil and natural gas, respectively. These
prices were 37 percent higher and 32 percent lower, respectively, than the year-end prices used to estimate 2008
proved reserves, and 23 percent and 33 percent lower, respectively, than prices that would have been used the
SEC’s previous methodology. If the SEC’s prior methodology had been used for year-end 2009 proved reserves,
the prices used would have been $79.36 per Bbl and $5.79 per MMBTU.
Additional revisions to the SEC rules provide for the use of new technology to estimate proved reserves.
Additionally, the definition of proved oil and gas reserves has been expanded to include non-traditional resources,
which focuses on the marketable product rather than the method of extraction. In addition to these regulatory
changes, in 2009 we began recording estimates of proved reserve volumes for properties that we believe are
reasonably certain to generate positive net cash flows on an undiscounted basis, that we have the intent to drill,
and which meet our internal economic criteria for drilling. Previously, we booked proved reserve volumes if the
properties showed a positive PV-10 value, we had the intent to drill, and the wells met our economic criteria.
The table below 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, 2009. We engaged Ryder Scott
Company, L.P. (―Ryder Scott‖) to review internal engineering estimates for at least 80 percent of the PV-10 value
of our proved reserves in 2009, 2008, and 2007, excluding our coalbed methane properties. For 2008 and 2007,
Netherland, Sewell and Associates, Inc. (―NSAI‖) prepared the reserve information for our coalbed methane
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 divested of all Hanging Woman Basin properties in the fourth
quarter of 2009.
We emphasize 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 authority or agency,
other than the SEC, since the beginning of the last fiscal year.
9
The ability to replace produced reserves is important to the sustainability of all exploration and
production companies. Our 2009 corporate ratio of reserves replaced through drilling activity was 100 percent.
There were no material acquisitions made in 2009. Four out of our five regions did not replace their respective
regional production for the year. The one exception, our South Texas & Gulf Coast region, replaced 400 percent
of its production for 2009 due to the strong results in the Eagle Ford shale. This metric is calculated using
information from the Oil and Gas Reserve Quantities section of Note 16 – 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 16 – 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.
Reserves data:
Proved developed
Oil (MMBbl)
Gas (Bcf)
BCFE
Proved undeveloped
Oil (MMBbl)
Gas (Bcf)
BCFE
Total Proved
Oil (MMBbl)
Gas (Bcf)
BCFE
Proved developed reserves %
Proved undeveloped reserves %
Reserve Value info (in thousands)
Proved developed PV-10
Proved undeveloped PV-10
Total proved PV-10 value
Standardized measure of discounted
future cash flows
Reserve replacement – drilling and
acquisitions, excluding revisions
2009
As of December 31,
2008
2007
48.1
342.0
630.3
5.7
107.5
141.9
53.8
449.5
772.2
82%
18%
47.1
433.2
715.8
4.3
124.2
149.7
51.4
557.4
865.5
83%
17%
68.3
426.6
836.3
10.5
186.9
250.2
78.8
613.5
1,086.5
77%
23%
$ 1,253,056
31,029
$ 1,284,085
$
$
1,214,380
51,005
1,265,385
$ 3,300,213
560,974
$ 3,861,187
1,015,967
1,059,069
2,706,914
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
174%
(93)%
(39)%
7.6
211%
248%
249%
10.1
100%
14%
55%
7.1
12-month period.
10
The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to
the PV-10 value (Non-GAAP). 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.
2009
As of December 31,
2008
(In thousands)
2007
Standardized measure of discounted
future net cash flows
$ 1,015,967
$
1,059,069
$ 2,706,914
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
732,997
515,953
724,840
419,544
2,321,983
2,316,637
$ 2,264,917
$
2,203,453
$ 7,345,534
(980,832)
(938,068)
(3,484,347)
PV-10 value
$ 1,284,085
$
1,265,385
$ 3,861,187
Proved Undeveloped Reserves
As of December 31, 2009, we had 141.9 BCFE of proved undeveloped reserves, which is a decrease of
7.8 BCFE or five percent compared with 149.7 of proved undeveloped reserves at December 31, 2008. A
negative revision of 19.1 BCFE was due to lower pricing in the gas weighted regions, particularly in the
ArkLaTex region where 16.4 BCFE of mostly Cotton Valley proved undeveloped reserves became uneconomic
using the new 12-month average pricing. We added 43.6 BCFE of proved undeveloped reserves through our
drilling program, 34.3 BCFE of which were extensions and discoveries, primarily in the Eagle Ford shale, as well
as an additional 9.3 BCFE of infill proved undeveloped reserves that were mostly concentrated in the Cotton
Valley and Bakken. During the year, 7.0 BCFE were sold in divestitures, primarily in our Rocky Mountain
region. We invested approximately $57 million to convert 18.6 BCFE of proved undeveloped reserves in 2009,
mainly in the Wolfberry properties in the Permian region and the Woodford shale in the Mid-Continent region.
We had a negative revision of 6.7 BCFE due to downward performance revisions in our Wolfberry properties in
the Permian region and 3.6 BCFE of proved undeveloped reserves were removed as a result of the five year
limitation on the number of years that a proved undeveloped reserve may remain on the books without being
developed. As of December 31, 2009, we have no material proved undeveloped reserves that have been on the
books in excess of five years. As of December 31, 2009, estimated future development costs relating to proved
undeveloped reserves are projected to be approximately $49 million, $129 million, and $56 million in 2010, 2011,
and 2012, respectively.
11
Alternate Pricing Scenario
The following table presents our December 31, 2009, reserves data and PV-10 value based on prices that
would have been used under the SEC’s previous methodology of estimating reserves using year-end pricing. If
the SEC’s prior methodology had been used for year-end 2009 proved reserves, the prices used would have been
$79.36 per barrel and $5.79 per MMBTU. All cost assumptions remain the same.
As of December 31, 2009
Reserves data:
Proved developed
Oil (MMBbl)
Gas (Bcf)
BCFE
Proved undeveloped
Oil (MMBbl)
Gas (Bcf)
BCFE
Total Proved
Oil (MMBbl)
Gas (Bcf)
BCFE
Proved developed reserves
Proved undeveloped reserves
Reserve Value info (in thousands)
Proved developed PV-10
Proved undeveloped PV-10
Total proved PV-10 value
Internal Controls Over Reserves Estimate
53.0
382.9
700.8
8.8
143.9
196.4
61.8
526.8
897.2
78%
22%
$
$
2,207,906
235,805
2,443,711
St. Mary’s policies regarding internal controls over the recording of reserves is structured to objectively
and accurately estimate our oil and gas reserves quantities and values in compliance with the SEC’s regulations.
Responsibility for compliance in reserves bookings is delegated to our reservoir engineering group, which is led
by our Vice President of Engineering and Evaluation.
Technical reviews are performed throughout the year by regional engineering and geologic staff who
evaluate all available geological and engineering data. This data in conjunction with economic data and
ownership information is used in making a determination of proved reserve quantities. The reserve process is
overseen by Dennis A. Zubieta, Vice President - Engineering and Evaluation for St. Mary. Mr. Zubieta joined
St. Mary in June 2000 as a Corporate Acquisition & Divestiture 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 and Gas Company (formerly known as Meridian Oil, Inc) from June 1988
to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta received a Bachelor of
Science degree in Petroleum Engineering from Montana Tech in May 1988. The regional technical staff does not
report directly to Mr. Zubieta; they report to either regional technical managers or directly to the regional manager
in their respective region. This is intended to promote objective and independent analysis within the reserves
process.
12
Third-party Reserves Audit
An independent audit is performed by Ryder Scott using their own engineering assumptions and
economic data provided by St. Mary. A minimum of 80 percent of the total calculated proved reserve PV-10
value is audited by Ryder Scott. In aggregate, the reserve values of the audited properties are required to be
within 10 percent of St. Mary’s valuations on both a corporate and regional level. Ryder Scott is an independent
petroleum engineering consulting firm that has been providing petroleum consulting services throughout the
world for over seventy years. The technical person at Ryder Scott primarily responsible for overseeing the
reserves audit is a Senior Vice President and holds a Bachelor of Science degree in Petroleum Engineering from
the University of Missouri at Rolla in 1970 and is a registered Professional Engineer in the States of Colorado and
Utah. He is also a member of the Society of Petroleum Engineers. The Ryder Scott report is included as
Exhibit 99.1.
In addition to a third party audit, our reserves are reviewed by senior management and the Audit
Committee of St. Mary’s Board of Directors. Senior management, which includes the President and Chief
Executive Officer, the Executive Vice President and Chief Operating Officer, and the Executive Vice President
and Chief Financial Officer, is responsible for reviewing and verifying that the estimate of proved reserves is
reasonable, complete, and accurate. The Audit Committee reviews the final reserves estimate in conjunction with
Ryder Scott’s audit letter. They may also meet with the key representative from Ryder Scott to discuss their
process and findings.
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
$
$
$
$
$
$
$
$
$
Years Ended December 31,
2008
2009
2007
6.3
71.1
109.1
17.3
194.8
298.8
6.6
74.9
114.6
18.1
204.7
313.1
6.9
66.1
107.5
18.9
181.0
294.5
54.40
3.82
5.65
$
$
$
92.99
8.60
10.99
$
$
$
67.56
6.74
8.48
56.74
5.59
6.94
1.33
0.19
0.37
$
$
$
$
$
$
75.59
8.79
10.11
1.46
0.19
0.71
$
$
$
$
$
$
62.60
7.63
8.71
1.31
0.14
0.58
13
Productive Wells
As of December 31, 2009, St. Mary had working interests in 2,046 gross (1,000 net) productive oil wells
and 3,154 gross (1,042 net) productive gas wells. Productive wells are either producing wells or wells capable of
commercial production although currently shut-in. Multiple completions in the same wellbore are counted as one
well. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas
to oil produced when it first commenced production, and such designation may not be indicative of current
production.
Subsequent to year end, we have closed or plan to close on several divestitures of non-core properties,
primarily in the Rocky Mountain region. Upon closing of these transactions, we will have divested 425 gross
(302 net) productive oil wells and 305 gross (93 net) productive gas wells.
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:
2009
Years Ended December 31,
2008
2007
Gross
Net
Gross
Net
Gross
Net
103
74
3
180
2
18
5
25
3
208
29.64
18.15
1.29
49.08
0.42
9.05
2.88
12.35
-
61.43
221
559
25
805
2
10
1
13
7
825
81.46
205.18
13.70
300.34
164
518
30
712
0.40
2.75
0.76
3.91
3
9
5
17
77.91
204.62
13.18
295.71
1.92
4.01
2.58
8.51
-
304.25
1
730
-
304.22
Development:
Oil
Gas
Non-productive
Exploratory:
Oil
Gas
Non-productive
Farmout or non-consent
Total(1)
(1) Does not include one and two gross wells completed on St. Mary’s fee lands during 2009 and 2008, respectively, in which we only
have royalty interests.
A productive well is an exploratory, development or extension well that is not a dry well. A dry well
(hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas
in sufficient quantities to justify completion as an oil or gas well.
As defined in the rules and regulations of the SEC, an exploratory well is a well drilled to find a new field
or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A
development well is part of a development project, which is defined as the means by which petroleum resources
are brought to the status of economically producible. The number of wells drilled refers to the number of wells
completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to
the installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to
the appropriate authority that the well has been abandoned.
In addition to the wells drilled and completed in 2009 included in the table above, as of
February 16, 2010, St. Mary is currently participating in the drilling of 25 gross wells, all of which are located in
the continental United States. We operate nine of these wells with the remaining 16 wells being operated by our
partners. On a net basis, we are drilling 7.6 net operated wells and are participating in 2.0 net non-operated
14
wells. With respect to completion activity, there are currently 19 wells in which we have an interest that are being
completed. We operate 13 of those on a gross basis (10.2 net) and is participating with industry partners in 6
gross (0.3 net) completion activities. The vast majority, if not all, of these operations relate to the drilling of wells
for primary production.
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, 2009. Undeveloped
acreage includes leasehold interests that may already have been classified as containing proved undeveloped
reserves.
Developed Acres (1)
Net
Gross
Undeveloped Acres (2)
Gross
Net
Total
Gross
Net
1,394
-
-
101,516
2,360
59,806
-
2,507
127,497
256,577
-
221,795
-
88,761
862,213
10,499
7,426
17,925
880,138
163
-
-
37,483
429
40,389
-
1,815
87,654
81,184
-
106,072
-
52,814
408,003
10,499
4,217
14,716
422,719
147
940
2,240
25,120
100,963
343,612
197,945
1,240
216,779
70,483
30,462
544,683
2,568
285,700
1,822,882
14,415
4,769
19,184
1,842,066
60
614
560
4,905
42,265
236,463
197,945
1,022
121,214
32,917
27,440
260,955
561
143,183
1,070,104
14,415
4,407
18,822
1,088,926
1,541
940
2,240
126,636
103,323
403,418
197,945
3,747
344,276
327,060
30,462
766,478
2,568
374,461
2,685,095
24,914
12,195
37,109
2,722,204
223
614
560
42,388
42,694
276,852
197,945
2,837
208,868
114,101
27,440
367,027
561
195,997
1,478,107
24,914
8,624
33,538
1,511,645
Arkansas
Colorado
Kansas
Louisiana
Mississippi
Montana
Nevada
New Mexico
North Dakota
Oklahoma
Pennsylvania
Texas
Utah
Wyoming
Louisiana Fee Properties
Louisiana Mineral Servitudes
Total (3)
(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.
(3) Subsequent to December 31, 2009, St. Mary divested certain non-core properties, which included leases covering approximately 26,100
and 25,100 developed gross and net acres, respectively, and 18,600 and 15,000 undeveloped gross and net acres, respectively.
Additionally, we entered into agreements to divest certain non-core properties, which included leases covering approximately 80,200 and
44,500 developed gross and net acres, respectively, and 63,700 and 31,000 undeveloped gross and net acres, respectively.
Delivery Commitments
As of December 31, 2009, there were no material delivery commitments. Subsequent to year end we are
subject to a certain gathering through-put contract that requires a minimum volume delivery of 15 Bcf by
January 1, 2013. We will be required to pay $0.18 Mcf for any shortfall in delivering the minimum volume of 15
Bcf. At the current time, the company does not have proved developed reserves to offset this contractual liability,
but fully intends to develop proved undeveloped reserves that will exceed the through-put commitment.
15
Major Customers
During 2009, sales to Teppco Crude Oil LLC individually accounted for 12 percent of our total oil and
gas production revenue. During 2008 and 2007, no customer individually accounted for ten percent or more of
our total oil and gas production revenue.
Employees and Office Space
As of February 16, 2010, we had 550 full-time employees. None of our employees are subject to a
collective bargaining agreement and we consider our relations with our employees to be good. As of
December 31, 2009, we lease approximately 79,000 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 22,000 square feet in
Shreveport, Louisiana; approximately 26,000 square feet in Houston, Texas; approximately 17,000 square feet in
Midland, Texas; approximately 36,000 square feet in Billings, Montana; approximately 6,000 square feet in
Williston, North Dakota; and approximately 2,000 square feet in Casper, Wyoming.
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 increased demand on storage volumes. Crude oil and the demand for
heating oil are also impacted by generally higher prices in the winter and the summer driving season – 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, particularly with respect to capturing prospective oil and
natural gas properties and oil and gas reserves. We believe 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 the location of our leasehold acreage, our exploration, drilling,
and production expertise and available technologies, and the experience and knowledge of our management and
industry partners enable us to compete effectively in our core operating and resource play areas. Notwithstanding
our talents and assets, we still face stiff competition from a substantial number of major and independent oil and
gas companies who 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 and services necessary for the drilling and completion of wells. Consequently, we may face shortages
16
or delays in securing these services from time to time. We are seeing signs of tightening rig availability, although
it is quite specific by region. The oil and natural gas industry also faces competition from alternative fuel sources,
including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may be
affected by future legislation and regulations as the U.S. develops new energy and climate-related policies.
Finally, we also compete for people. Throughout the industry, the need to attract and retain 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 compete effectively 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, or other developments, 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
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, 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.
In January 2010, the BLM announced that it will be issuing a new draft oil and gas leasing policy that will
require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources,
increased public engagement in the development of master leasing and development plans prior to leasing areas
where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. As the
policy has not yet been released, we are not able to determine the impact these potential leasing policy changes
may have on our business.
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.
17
Environmental, Health and Safety Regulations. Our operations are subject to stringent federal, state, and
local laws and regulations relating to the protection of the environment and human health and safety.
Environmental 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. Further, possible regulations related to global warming or climate change could have an adverse
effect on our operations and the demand for oil and natural gas. See ―Risk Factors – Risks Related to Our
Business - Possible regulations related to global warming or climate change could have an adverse effect on our
operations and the demand for oil and natural gas.‖
Hydraulic fracturing is a common process in our industry of creating artificial cracks, or fractures, in deep
underground rock formations through the pressurized injection of water, sand and other additives to enable oil or
natural gas to move more easily through the rock pores to a production well. This process is often necessary to
produce commercial quantities of oil and natural gas from many reservoirs, especially shale rock formations. We
routinely utilize hydraulic fracturing techniques in many of our reservoirs, and our shale resource programs utilize
or contemplate the utilization of hydraulic fracturing. Currently, regulation of hydraulic fracturing is primarily
conducted at the state level through permitting and other compliance requirements. Legislative and regulatory
efforts at the federal level and in some states have been made which could result in additional regulations and
permitting requirements. Those additional regulations and permitting requirements, as well as other regulatory
developments, could lead to significant operational delays and increased operating costs, and make it more
difficult to perform hydraulic fracturing.
Federal and state occupational safety and health laws require us to organize and maintain information
about hazardous materials used, released, or produced in our operations. Some of this information must be
provided to our employees, state and local governmental authorities, and local citizens. We are also subject to the
requirements and reporting framework set forth in the federal workplace standards.
To date we have not experienced any materially adverse effect on our operations from obligations under
environmental, health, and safety laws and regulations. We believe that we are in substantial compliance with
currently applicable environmental, health, and safety laws and regulations, and that continued compliance with
existing requirements would not have a materially adverse impact on us.
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
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Proved 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 or
climate change initiatives
The availability of economically attractive exploration, development, and property acquisition
opportunities and any necessary financing, including any constraints on the availability of
opportunities and financing due to distressed capital and credit market conditions
Our ability to replace reserves and sustain production
Unexpected drilling conditions and results
Unsuccessful exploration and development drilling
The risks of hedging strategies, including the possibility of realizing lower prices on oil and natural
gas sales as a result of commodity price risk management activities
The pending nature of reported divestiture plans for certain non-core oil and gas properties as well as
the ability to complete divestiture transactions
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, and uncertainties with respect to the amount of proceeds that may
be received from divestitures
The imprecise nature of oil and natural gas reserve estimates
Uncertainties inherent in projecting future rates of production from drilling activities and acquisitions
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Declines in the values of our oil and natural gas properties resulting in impairment charges and 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 these 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
and
Litigation, environmental matters, the potential impact of government regulations, and the use of
management estimates.
We caution you that forward-looking statements are not guarantees of future performance and that actual
results or performance may be materially different from those expressed or implied in the forward-looking
statements. Although we may from time to time voluntarily update our prior forward-looking statements, we
disclaim any commitment to do so except as required by securities laws.
Available Information
Our Internet website address is www.stmaryland.com. We routinely post important information for
investors on our website. Within our website’s investor relations section we make available free of charge our
annual 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.
Information on our website is not incorporated by reference into this Form 10-K and should not be
considered part of this document.
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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 developed reserves, exploratory well, field, proved reserves, and 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 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 volumetric
ratio of six Mcf of natural gas to one Bbl of oil.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the volumetric ratio of six Mcf of natural
gas to one Bbl of oil.
Developed reserves. With respect to reserves as of December 31, 2009, and dates thereafter, the applicable SEC
definition of developed reserves is reserves that can be expected to be recovered: (i) through existing wells with
existing equipment and operating methods or in which the cost of the required equipment is relatively minor
compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational
at the time of the reserves estimate if the extraction is by means not involving a well. With respect to reserves as
of dates prior to December 31, 2009, the applicable SEC definition of proved developed reserves was proved
reserves that can be expected to be recovered through existing wells with existing equipment and operating
methods.
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 commercial quantities.
Exploratory well. With respect to wells as of December 31, 2009, and dates thereafter, the applicable SEC
definition of exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir. With respect to wells as of dates prior to
December 31, 2009, the applicable SEC definition of exploratory well was 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 15 – Oil and Gas
Activities and Note 16 – 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.
21
As a result, the exploration costs incurred in earlier periods are not included in the amount of exploration costs
incurred during the period in which that set of proved reserves is added. In addition, consistent with industry
practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. Since the
additional development costs that will need to be incurred in the future before the proved undeveloped reserves
are ultimately produced are not included in the amount of costs incurred during the period in which those reserves
were added, those development costs in future periods will be reflected in the costs associated with adding a
different set of reserves. The calculations of various finding cost metrics are explained below.
Finding cost – Drilling, excluding revisions. Calculated by dividing the amount of costs incurred for
development and exploration activities, by the amount of estimated net proved reserves added through
discoveries, extensions, and infill drilling, during the same period.
Finding cost – Drilling, including revisions. Calculated by dividing the amount of costs incurred for
development and exploration activities, by the amount of estimated net proved reserves added through
discoveries, extensions, and infill drilling, and revisions of previous estimates during the same period.
Finding cost – Drilling and acquisitions, excluding revisions. Calculated by dividing the amount of costs
incurred for development, exploration and acquisition of proved properties, by the amount of estimated
net proved reserves added through discoveries, extensions, infill drilling and acquisitions during the same
period.
Finding cost – Drilling and acquisitions, including revisions. Calculated by dividing the amount of costs
incurred for development, exploration and acquisition of proved properties, by the amount of estimated
net proved reserves added through discoveries, extensions, and infill drilling, revisions of previous
estimates, and acquisitions 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, by the amount of estimated net proved reserves added
through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates less sales
of reserves during the same period.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Gross acre. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Horizontal wells. Wells which are drilled at angles greater than 70 degrees from vertical.
Lease operating expenses. The expenses incurred in the lifting of 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, maintenance, allocated overhead costs, and other expenses incidental to
production, but not including lease acquisition, drilling, or completion costs.
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 volumetric ratio of six
Mcf of natural gas to one Bbl of oil.
MMBOE. One million barrels of oil equivalent. Oil equivalents are determined using the volumetric ratio of six
Mcf of natural gas to one Bbl of oil.
Mcf. One thousand cubic feet, used in reference to natural gas.
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MCFE. One thousand cubic feet of natural gas equivalent. Natural gas equivalents are determined using the
volumetric ratio of six Mcf of natural gas to one Bbl of oil.
MMcf. One million cubic feet, used in reference to natural gas.
MMCFE. One million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the
volumetric ratio of six Mcf of natural gas 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.
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, based on prices used in
estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change
pursuant to contractual provisions), without giving effect to non-property related expenses such as general and
administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization,
discounted using an annual discount rate of ten percent. While this measure does not include the effect of income
taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does
provide an indicative representation of the relative value of the Company on a comparative basis to other
companies and from period to period.
Productive well. A well that is producing oil or natural gas or that is capable of commercial production.
Proved reserves. With respect to reserves as of December 31, 2009, and dates thereafter, the applicable SEC
definition of proved reserves is those quantities of oil and gas, which, by analysis of geoscience and engineering
data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from
known reservoirs, and under existing economic conditions, operating methods, and government regulations –
prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be
determined, and the price to be used is the average price during the 12-month period prior to the ending date of
the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month
price for each month within such period, unless prices are defined by contractual arrangements, excluding
escalations based upon future conditions. With respect to reserves as of dates prior to December 31, 2009, the
applicable SEC definition of proved reserves was 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, meaning prices and costs as of
the date the estimate is made.
Recompletion. A 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
23
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 16 – 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.
Reserve replacement – Drilling, excluding revisions. Calculated as a numerator comprised of the sum of
reserve extensions and discoveries and infill reserves in an existing proved field divided by production for
that same period. This metric is an indicator of the relative success a company is having in replacing its
production through drilling activity.
Reserve replacement – Drilling, including revisions. Calculated as a numerator comprised of the sum of
reserve extensions, discoveries, and infill reserves, and revisions and previous estimates in an existing
proved field divided by production for that same period. This metric is an indicator of the relative success
a company is having in replacing its production through drilling activity.
Reserve replacement – Drilling and acquisitions, excluding 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. This metric is an indicator of the
relative success a company is having in replacing its production through drilling and acquisition activities.
Reserve replacement – Drilling and acquisitions, including revisions. Calculated as a numerator
comprised of the sum of reserve acquisitions and reserve extensions, discoveries, and infill reserves, and
revisions and previous estimates in an existing proved field divided by production for that same period.
This metric is an indicator of the relative success a company is having in replacing its production through
drilling and acquisition activities.
Reserve replacement percentage – All in, excluding sales of reserves. The sum of reserve extensions and
discoveries, infill drilling, reserve acquisitions, and reserve revisions of previous estimates for a specified
period of time divided by production for that same period.
Reserve replacement percentage –All in, including sales of reserves. The sum of sales of reserves, infill
drilling, reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous
estimates for a specified period of time divided by production for that same period.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible 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 resources known to exist over a
large area expanse, which when compared to a conventional play typically has a lower expected geological and/or
commercial development risk.
Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross
income from 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.
24
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most
frequently occurring sedimentary rock.
Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to
proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 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.
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. With respect to reserves as of
December 31, 2009, and dates thereafter, the applicable SEC definition of undeveloped reserves provides that
undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted
indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer
time.
Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating
activities on the property and to share in the production, sales, and costs.
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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 impairments or
downward revisions of estimates of proved reserves if prices fall significantly.
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
Strengthening and weakening of the U.S dollar relative to other currencies
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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Continued weakness in economic conditions or uncertainty in financial markets may have material adverse
impacts on our business that we cannot predict.
U.S. and global economies and financial systems have recently experienced turmoil and upheaval
characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability,
inability to access capital markets, the bankruptcy, failure, collapse or sale of financial institutions, increased
levels of unemployment, and an unprecedented level of intervention by the U.S. federal government and other
governments. Although some portions of the economy appear to have stabilized and there have been signs of the
beginning of recovery, the extent and timing of a recovery, and whether it can be sustained, are uncertain.
Continued weakness in the U.S. or global economies could materially adversely affect our business and financial
condition. For example:
•
•
•
•
the demand for oil and natural gas in the U.S. has declined and may remain at low levels or further
decline if economic conditions remain weak, and continue to negatively impact our revenues,
margins, profitability, operating cash flows, liquidity and financial condition
the tightening of credit or lack of credit availability to our customers could adversely affect our ability
to collect our trade receivables
our ability to access the capital markets may be restricted at a time when we would like, or need, to
raise capital for our business, including for exploration and/or development of our reserves
our commodity hedging arrangements could become ineffective if our counterparties are unable to
perform their obligations or seek bankruptcy protection.
If we are unable to replace reserves, we will not be able to sustain production.
Our future operations depend on our ability to find, develop, or acquire oil and natural gas reserves that
are economically producible. 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 producible 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
developing and acquiring new reserves, and the orderly functioning of credit and capital markets. 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, secure
our acreage, or maintain production levels could be greatly limited.
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The debt and equity financing markets have recently been constrained due to the global and domestic
economic and financial downturn, and it is possible that circumstances may arise where one or more of the twelve
participating banks in our credit facility, at some point, may not be able to fulfill their portion of the lending
commitments to us under the facility. Adverse conditions in the credit markets may increase the cost of
borrowings and decrease our ability to access new sources of capital.
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 producible 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 on adjacent properties.
As of December 31, 2009, approximately 18 percent, or 142 BCFE, of our estimated proved reserves
were proved undeveloped, and approximately 9 percent, or 73 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, we estimate approximately $296 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 approximately $44 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
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expenditures for 2010 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 price
and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or
lower. For example, values of our reserves as of December 31, 2009, were estimated using a calculated 12-month
average sales price of $3.87 per MMBtu of natural gas (NYMEX Henry Hub spot price) and $61.18 per Bbl of oil
(NYMEX West Texas Intermediate spot price). We then adjust these base prices to reflect appropriate basis,
quality, and location differentials over that period in estimating our proved reserves. During 2009, our monthly
average realized natural gas prices, excluding the effect of hedging, were as high as $5.48 per Mcf and as low as
$2.96 per Mcf. For the same period, our monthly average realized oil prices before hedging were as high as
$70.31 per Bbl and as low as $30.37 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.
Reserve estimates as of December 31, 2009, have been prepared under the SEC’s new rules for oil and
gas reporting that are effective for fiscal years ending on or after December 31, 2009. These new rules require
SEC reporting companies to prepare their reserve estimates using, among other things, revised reserve definitions
and revised pricing based on 12-month unweighted first-day-of-the-month average pricing, instead of the prior
requirement to use pricing at the end of the period. The SEC has released only limited interpretive guidance
regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on
the new rules in the near future. The interpretation of these rules and their applicability in different situations
remains unclear in many respects. Changing interpretations of the rules or disagreements with our interpretations
could result in revisions to our reserve estimates or write-downs in our reserves.
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.
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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 producible reserves.
Oil and natural gas drilling and production activities are subject to numerous risks, including the risk that
no commercially producible oil or natural gas will be found. The cost of drilling and completing wells is often
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 commodity prices. The availability of drilling rigs can vary significantly from region to region at any
particular time. Although land drilling rigs can be moved from one region to another in response to changes in
levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for
the rigs that are available in that region. In addition, the recent economic and financial downturn has adversely
affected the financial condition of some drilling contractors, which may constrain the availability of drilling
services in some areas.
Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state,
local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits,
including delays 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.
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Drilling results in our newer shale plays, such as the Eagle Ford, Haynesville, and Marcellus 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, and we have less information with respect to
the ultimate recoverable reserves and the production decline rates in these shales than we have in other areas in
which we operate. 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. Moreover, the recent growth in
exploration in the Marcellus shale has drawn intense scrutiny from environmental interest groups, regulatory
agencies, and other governmental entities. As a result, we may face significant opposition to our operations in
that area that may make it difficult to obtain permits and other needed authorizations to operate or otherwise make
operating more costly or difficult than operating elsewhere.
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, although we have the present intent to do so, or if we will be able to produce oil or natural gas
from these or any other potential drilling locations.
Our future drilling activities may not be successful. Our overall drilling success rate or our drilling
success rate within a particular area may decline. In addition, we may not be able to obtain any options or lease
rights in potential drilling locations that we identify. 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, 2009, we were in a net accrued liability
position of approximately $81 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 of one or more counterparties defaulting on their obligations is heightened by the recent global
and domestic economic and financial downturn affecting many banks and other financial institutions, including
our counterparties and their affiliates. These circumstances may adversely affect the ability of our counterparties
to meet their obligations to us pursuant to hedge transactions, which could reduce our revenues and cash flows
from realized hedge settlements. 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
transactions use derivative instruments that may involve basis risk. Basis risk in a hedging contract can occur
when the change in the index upon which the hedge is based does not correlate well to the change in the index
upon which the hedged production is valued, thereby making the hedge less effective. For example, a change in
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the NYMEX price used for hedging certain volumes of production may not correlate exactly to the change in the
regional price 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 recent global and domestic economic and financial downturn.
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.
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 generally must write down the costs of each such field to the estimated discounted future net cash flows of that
field. Unproved properties are evaluated at the lower of cost or fair market value. As a result of significant oil
and natural gas price declines in the second half of 2008, 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. In addition, we incurred impairment of proved property write-downs and
impairment of unproved properties totaling $174.8 million and $45.4 million, respectively, during 2009.
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 $678 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 $900 million, which was determined as of September 29, 2009. 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. Additionally, the pending divestitures of non-core properties could result in a reduction of our borrowing
base.
Our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse
economic conditions, and make it more difficult for us to make payments on our debt.
As of December 31, 2009, we had $267 million, net of debt discount, of total long-term senior unsecured
debt outstanding under our 3.50% Senior Convertible Notes due 2027, and $188 million of secured debt
outstanding under our revolving credit facility. As of February 16, 2010, we had an outstanding balance of
$211.0 million drawn against our revolving credit facility, resulting in $467.0 million of available debt capacity
under our revolving credit facility assuming the borrowing conditions of this facility were met. Our long-term
debt represented 32 percent of our total book capitalization as of December 31, 2009.
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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, 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,
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 South
Texas & 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.
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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 for wind storms has become substantially more expensive, and
future availability and costs of coverage are uncertain.
Our operations are subject to complex laws and regulations, including environmental regulations that result in
substantial costs and other risks.
Federal, state, and local authorities extensively regulate the oil and natural gas industry. Legislation and
regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of
changes that may 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. Under certain 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.
Proposed federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in
increased costs and additional operating restrictions or delays.
The U.S. Congress is currently considering legislation that would amend the Safe Drinking Water Act to
eliminate an existing exemption from federal regulation of hydraulic fracturing activities and require the
disclosure of chemical additives used by the oil and gas industry in the hydraulic fracturing process. Hydraulic
fracturing is a common process in our industry of creating artificial cracks, or fractures, in deep underground rock
formations through the pressurized injection of water, sand and other additives to enable oil or natural gas to
move more easily through the rock pores to a production well. This process is often necessary to produce
commercial quantities of oil and natural gas from many reservoirs, especially shale rock formations. We
routinely utilize hydraulic fracturing techniques in many of our reservoirs, and our Eagle Ford, Haynesville,
Marcellus, and Woodford shale programs utilize or contemplate the utilization of hydraulic fracturing. Currently,
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regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other
compliance requirements. If adopted, the proposed amendment to the Safe Drinking Water Act could result in
additional regulations and permitting requirements at the federal level. In addition, various states are also
studying or considering various additional regulatory measures related to hydraulic fracturing. Additional
regulations and permitting requirements could lead to significant operational delays and increased operating costs,
and make it more difficult to perform hydraulic fracturing.
Proposed legislation to eliminate or reduce certain federal income tax incentives and deductions available to oil
and gas exploration and production companies could, if enacted into law, have a material adverse effect on our
results of operations and cash flows.
In 2009, the ―Oil Industry Tax Break Repeal Act of 2009‖ was introduced in the U.S. Senate. This bill
proposes amendments to the Internal Revenue Code of 1986 to eliminate or reduce certain federal income tax
incentives and deductions currently available to oil and gas exploration and production companies. The proposed
amendments include the elimination or reduction of current deductions for intangible drilling and development
costs, percentage depletion allowances, and the manufacturing deduction for oil and gas properties. President
Obama’s proposed Fiscal Year 2011 Budget also contemplates these proposed tax law amendments. If some or
all of these provisions are enacted into law, our effective tax rate and current income tax expense will increase,
potentially significantly, which would increase cash requirements to pay income tax thereby reducing cash flows
from operating activities, which in turn will reduce cash available for drilling and other exploration and
development activities.
Enactment of a Pennsylvania severance tax on natural gas could adversely impact the economic viability of
exploiting natural gas drilling and production opportunities in our Marcellus Shale resource play.
The Governor of the Commonwealth of Pennsylvania has proposed to its legislature the adoption of a
severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax is five percent of
the value of the natural gas at the wellhead, plus $0.047 per Mcf of natural gas severed. Our Marcellus Shale
acreage is located in Pennsylvania. If Pennsylvania adopts such a severance tax, it could impact the economic
viability of exploiting natural gas drilling and production opportunities in the Marcellus Shale.
Possible legislation and regulations related to global warming and climate change could have an adverse effect
on our operations and the demand for oil and natural gas.
On December 15, 2009, the U.S. Environmental Protection Agency (EPA) officially published its
findings that emissions of carbon dioxide, which is a byproduct of the burning of refined oil products and natural
gas, methane, which is a primary component of natural gas, and other ―greenhouse gases‖ present an
endangerment to human health and the environment because emissions of such gases are, according to the EPA,
contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow
the agency to proceed with the adoption and implementation of regulations that would restrict emissions of
greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA had
proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in
emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas
emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009,
the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse
gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. The adoption and
implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases
from, our equipment and operations could require us to incur increased costs to reduce emissions of greenhouse
gases associated with our operations and could adversely affect demand for the oil and natural gas that we
produce.
In addition, on June 26, 2009, the U.S. House of Representatives passed the ―American Clean Energy and
Security Act of 2009‖ (ACESA), which would establish an economy-wide cap-and-trade program to reduce U.S.
emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17% reduction in
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greenhouse gas emissions from 2005 levels by 2020, and just over an 80% reduction of such emissions by 2050.
Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions
allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit
greenhouse gases into the atmosphere. The cost of these allowances would be expected to escalate significantly
over time. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based
fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own
legislation for restricting domestic greenhouse gas emissions, and the Obama administration has indicated its
support of legislation to reduce greenhouse gas emissions through an emission allowance system. In addition,
several states have considered 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.
Although it is not possible at this time to predict when the U.S. Senate may act on climate change legislation or
how any bill passed by the Senate would be reconciled with ACESA, any future federal or state laws or
regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating
costs and could adversely affect the demand for the oil and natural gas that we produce.
The adoption of derivatives legislation by Congress and related regulations could have an adverse impact on our
ability to hedge risks associated with our business.
The U.S. Congress is currently considering legislation to increase the regulatory oversight of the over-the-
counter derivatives markets in order to promote more transparency in those markets, and impose restrictions on
certain derivatives transactions, which could affect the use of derivatives in hedging transactions. ACESA
contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA
would expand the power of the Commodity Futures Trading Commission (CFTC) to regulate derivative
transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such
derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded
authority over energy derivatives would terminate upon the adoption of general legislation covering derivative
regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to
determine whether to set limits on trading and positions in commodities with finite supply, particularly energy
commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether
position limits should be applied consistently across all markets and participants. In addition, the Treasury
Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and
all other major OTC derivative market participants to substantial supervision and regulation, including by
imposing conservative capital and margin requirements and strong business conduct standards. Derivative
contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher
capital and margin requirements. Although it is not possible at this time to predict whether or when Congress
may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled
with ACESA, any new laws or regulations in this area may result in increased costs and cash collateral
requirements for the types of oil and gas derivative instruments we use to hedge and otherwise manage our
financial risks related to swings in oil and gas commodity prices, may impose additional restrictions on our
trading and commodity positions, and could have an adverse effect on our ability to hedge risks associated with
our business and on the cost of our hedging activity.
Our ability to sell oil and natural gas and/or receive market prices for our oil and natural gas production may be
adversely affected by constraints on pipelines and gathering systems owned by others and various transportation
interruptions.
The marketability of our oil and natural gas production depends in part on the availability, proximity, and
capacity of pipeline transportation and gathering 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
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destruction of pipelines, and general economic conditions could adversely affect our ability to produce, gather,
and transport oil and natural gas.
In particular, if drilling in the Eagle Ford, Haynesville, and Marcellus shales continues to be successful,
the amount of natural gas being produced by us and others could exceed the capacity of the various gathering and
intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be
necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain
pipeline projects that are being considered for these areas may not be developed due to lack of financing. In
addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our
gas to interstate pipelines. In such event, we might have to shut in our wells to wait for a pipeline connection or
capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX, which
would adversely affect our results of operations and cash flows.
A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to
time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering
system access, field labor issues or strikes, or we might voluntarily curtail production in response to market
conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily
adversely affect our cash flows.
New technologies may cause our current exploration and drilling methods to become obsolete.
The oil and gas industry is subject to rapid and significant advancements in technology, including the
introduction of new products and services using new technologies. As competitors use or develop new
technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to
implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical
and personnel resources that allow them to enjoy technological advantages and may in the future allow them to
implement new technologies before we can. One or more of the technologies that we currently use or that we
may implement in the future may become obsolete. We cannot be certain that we will be able to implement
technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological
advancements consistent with industry standards, our operations and financial condition may be adversely
affected.
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, 2009 to February 16, 2010, the closing daily sales price of our common stock as reported
by the New York Stock Exchange ranged from a low of $11.58 per share to a high of $37.89 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.
37
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 16, 2010, 62,590,571 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 1,271,292 shares of our common stock were outstanding,
of which all were exercisable. These options are exercisable at prices ranging from $7.97 to $20.87 per share. In
addition, restricted stock units providing for the issuance of up to a total of 403,968 shares of our common stock
and 1,141,113 performance share awards (―PSAs‖) 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 16, 2010, there were 62,777,688 shares of common stock outstanding, which is net of 126,893 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.
38
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 2009.
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 16, 2010.
Name
Anthony J. Best
Javan D. Ottoson
A. Wade Pursell
Mark D. Mueller
Milam Randolph Pharo
Paul M. Veatch
Stephen C. Pugh
Kenneth J. Knott
Gregory T. Leyendecker
John R. Monark
Lehman E. Newton, III
David J. Whitcomb
Dennis A. Zubieta
Mark T. Solomon
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
60
51
44
45
57
43
51
45 Vice President – Business Development and Land and Assistant Secretary
52 Vice President and Regional Manager
57 Vice President – Human Resources
54 Vice President and Regional Manager
47 Vice President – Marketing
43 Vice President – Engineering and Evaluation
41
Controller
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. From November 2005 to
June 2006, Mr. Best was developing a business plan and securing capital commitments for a new exploration and
production entity. From 2003 to October 2005, Mr. Best was President and Chief Executive Officer of Pure
Resources, Inc., an independent oil and natural gas exploration and production company that was a subsidiary of
Unocal, where he managed all of Unocal’s onshore 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
39
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.
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 over 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, where his responsibilities included fiscal
performance, reserves, and all operational functions of the company. From April 2005 until its sale in August
2006, Mr. Mueller was Vice President and General Manager for Samson Canada Ltd., an oil and gas exploration
and production company that was a subsidiary of Samson Investment Company, where he was responsible for all
business units and the eventual sale of the company. Mr. Mueller joined Samson Canada Ltd. as Project Manager
in May 2003 to build a new basin-centered gas business unit and was Vice President from December 2003 to
August 2006. Prior to joining Samson, Mr. Mueller was West Central Alberta Engineering Manager for
Northrock Resources Ltd., a Canadian oil and gas company that was a wholly-owned subsidiary of Unocal
Corporation, in Calgary, Canada. From 1986 to 2003, Mr. Mueller held positions of increasing responsibility in
engineering and management for Unocal throughout North America and Southeast Asia.
Milam Randolph Pharo was appointed Senior Vice President and General Counsel in August 2008. He
joined St. Mary as Vice President – Land and Assistant Secretary in January 1996. In May 1998 he was
appointed Vice President – Land and Legal and Assistant Secretary. From 1979 until joining St. Mary, Mr. Pharo
served in private practice as an attorney specializing in oil and gas matters.
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 and 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 acquisitions and divestitures, operations and engineering with Burlington Resources, 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 and Regional Manager in July 2007. Mr.
Leyendecker joined St. Mary in December 2006 as Operations Manager for the South Texas & 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
40
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 from February 2006 to November 2006 for Enventure Global Technology, a provider of
solid expandable tubular technology.
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 May 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.
Lehman E. Newton, III joined St. Mary in December 2006 as General Manager for the Midland office and
was appointed Vice President and Regional Manager of the Permian region in June 2007. Mr. Newton has over
28 years of experience in engineering, operations, and business development roles in the exploration and
production industry. From November 2005 to November 2006 Mr. Newton served as Project Manager for one of
Chevron’s largest lower 48 projects. Mr. Newton joined Pure Resources in February 2003 as the Business
Development Manager and worked in that capacity until October 2005. Mr. Newton was a founding partner in
Westwin Energy, an independent Permian Basin 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 South Texas
& Gulf Coast region in Lafayette, LA and later assumed the position of South Texas & Gulf Coast Regional Land
Manager when the office was moved to Houston in March 2004. Mr. Knott has worked for 22 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 (formerly known as Meridian Oil, Inc.) from June 1988 to May 2000 in various
operations and reservoir engineering capacities.
41
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.
42
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 closing prices for the quarterly periods in 2009 and 2008, as
reported by the New York Stock Exchange:
Quarter Ended
December 31, 2009
September 30, 2009
June 30, 2009
March 31, 2009
December 31, 2008
September 30, 2008
June 30, 2008
March 31, 2008
High
$ 38.05
33.62
23.48
24.60
$ 35.81
65.58
65.00
39.95
Low
$ 29.80
17.13
12.05
11.21
$ 14.76
32.53
37.73
31.70
43
PERFORMANCE GRAPH
The following performance graph compares the cumulative return on St. Mary’s common stock, not
including dividend payments, for the period beginning December 31, 2004, and ending on December 31, 2009,
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
$300.00
$250.00
$200.00
$150.00
$100.00
$50.00
$-
12/31/2004
12/31/2005
12/31/2006
12/31/2007
12/31/2008
12/31/2009
SM
DJUSOS
SPX
―Performance Graph‖ shall be deemed to be ―furnished‖ but not ―filed‖ with the Securities and Exchange
Commission.
Holders. As of February 16, 2010, the number of record holders of St. Mary’s common stock was 111.
Based on inquiry, management believes that the number of beneficial owners of our common stock is
approximately 17,000.
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 2009. We expect that our practice of paying dividends on our common stock will continue,
although the payment of future dividends will continue to depend on our earnings, cash flow, capital
requirements, financial condition, and other factors. In addition, the payment of dividends is subject to covenants
in our credit facility, including the requirement that we maintain the level of our current ratio of current assets to
current liabilities 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 2009 and $6.2 million
in 2008.
Equity Incentive Compensation Plan. In May 2009, the shareholders approved an amendment to rename
the 2006 Equity Incentive Compensation Plan to the Equity Incentive Compensation Plan (the ―Equity Plan‖).
Restricted Shares. St. Mary has no restricted shares outstanding as of December 31, 2009, aside from
Rule 144 restrictions on shares for insiders, shares are subject to transfer restrictions under the provisions of the
Employee Stock Purchase Plan, and shares issued to directors under the Equity Plan.
44
Equity Compensation Plans. St. Mary has the 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, 2009:
(a)
(b)
Number of
securities to be
issued upon
exercise of
outstanding
options,
warrants, and
rights
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))
1,274,920
408,356
1,145,871
2,829,147
-
-
$
$
$
13.31
-
32.52
22.40
-
-
-
-
1,771,009
1,771,009
1,468,275
-
Plan category
Equity compensation plans approved by
security holders:
Equity Incentive Compensation Plan
Stock options and incentive stock
options (1)
Restricted stock (1)
Performance share awards (1)(3)
Total for Equity Incentive Compensation
Plan
Employee Stock Purchase Plan (2)
Equity compensation plans not approved
by security holders
Total for all plans
2,829,147
$
22.40
3,239,284
(1)
In May 2006 the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-
qualified stock options, incentive stock options, stock appreciation rights, 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 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 Equity
Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a Predecessor Plan immediately
prior to the effective date of the Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing
such grants or issuances. Our Board of Directors approved amendments to the Equity Plan on March 26, 2008, and the amended plan
was approved by stockholders at our annual stockholders’ meeting May 21, 2008. Our Board of Directors approved additional
amendments to the Equity Plan on March 26, 2009, and the amendments were approved by stockholders at our annual stockholders’
meeting on May 20, 2009. Awards granted in 2009, 2008, and 2007 under the Equity Plan were 1,016,931, 932,767, and 135,138,
respectively.
(2) Under the St. Mary Land & Exploration Company Employee Stock Purchase Plan (the ―ESPP‖), eligible employees may purchase
shares of our common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the
stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the six-month offering period, and shares
issued under the ESPP through December 31, 2009, are restricted for a period of 18 months from the date issued. Effective
January 1, 2010, shares issued under the ESPP will be restricted for a period six 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 86,308, 45,228, and 29,534 in 2009,
2008, and 2007, respectively.
(3) The PSAs represent the right to receive, upon settlement of the PSAs after the completion of a three-year performance measurement
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. The
performance criteria for the PSAs are based on a combination of our cumulative Total Shareholder Return (―TSR‖) for the
performance period and the relative measure of our TSR compared with the TSR an index comprised of certain peer companies for the
performance period. The current outstanding PSAs were granted on August 1, 2009, and 2008, and utilize a three-year performance
measurement period which began on July 1, 2009, and 2008, respectively. On July 1, 2009, the market value per share of our common
45
stock was $21.15, and on the date of grant the market value per share of our common stock was $23.87. On July 1, 2008, the market
value per share of our common stock was $62.51, and on the date of grant the market value per share of our common stock was
$43.11. The PSAs do not have an exercise price associated with them, but rather the $32.52 price shown in the above table represents
the weighted-average per share fair value as of December 31, 2009, calculated pursuant to ASC Topic 718, which is presented in order
to provide additional information regarding the potential dilutive effect of the PSAs as of December 31, 2009, in view of the share
price level at the beginning of the performance period which will be utilized to compute the TSR measurements for determination of
the number of shares to be issued upon settlement of the PSAs after completion of the three-year performance measurement period.
46
Issuer Purchases of Equity Securities. The following table provides information about purchases by the
Company or ―affiliated purchaser‖ (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the quarters
and year ended December 31, 2009, of shares of the Company’s common stock, which is the sole class of equity
securities registered by the Company pursuant to Section 12 of the Exchange Act.
PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS
Total Number
of Shares
Purchased
(1)(2)(3)(4)
58,688
341
412
30
86
21,391
21,507
Average Price
Paid per Share
$
$
$
$
$
$
$
13.60
18.69
24.86
35.36
34.10
35.34
35.33
January 1, 2009 –
March 31, 2009
April 1, 2009 -
June 30, 2009
July 1, 2009 -
September 30, 2009
October 1, 2009 -
October 31, 2009
November 1, 2009 -
November 30, 2009
December 1, 2009 -
December 31, 2009
Total October 1, 2009 -
December 31, 2009
Total Number of
Shares Purchased
as Part of Publicly
Announced
Program
Maximum
Number of
Shares that May
Yet be Purchased
Under the
Program(5)
-0-
-0-
-0-
-0-
-0-
-0-
-0-
3,072,184
3,072,184
3,072,184
3,072,184
3,072,184
3,072,184
3,072,184
Total
3,072,184
(1) Includes a total of 6,500 shares purchased by Anthony J. Best, St. Mary’s President and Chief Executive Officer, in open market
80,948
19.45
-0-
$
transactions that were not made pursuant to our stock repurchase program.
(2) Includes a total of 5,000 shares purchased by A. Wade Pursell, St. Mary’s Executive Vice President and Chief Financial Officer, in
open market transactions that were not made pursuant to our stock repurchase program.
(3) Includes a total of 10,000 shares purchased by William D. Sullivan, a Director of St. Mary, in open market transactions that were not
made pursuant to our stock repurchase program.
(4) Includes 59,448 shares withheld (under the terms of grants under the Equity Incentive Compensation Plan) to offset tax withholding
obligations that occur upon the delivery of outstanding shares underlying restricted stock units that were not made pursuant to our
stock repurchase program.
(5) In July 2006 our Board of Directors approved an increase in the number of shares that may be repurchased under the original August
1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, we have Board
authorization to repurchase 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to
time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain
provisions of St. Mary’s existing bank credit facility agreement and compliance with securities laws. Stock repurchases may be
funded with existing cash balances, internal cash flow, and borrowings under St. Mary’s bank credit facility. The stock repurchase
program may be suspended or discontinued at any time.
The payment of dividends and stock repurchases are subject to covenants in our bank credit facility, including the requirement that we
maintain certain levels of stockholders’ equity and the limitation that does not allow our annual dividend rate to exceed $0.25 per
share.
47
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.
2009
2008 (1)
Years Ended December 31,
2007 (1)
(1
(In thousands, except per share data)
2006
2005
Total operating revenues
$ 832,201
$ 1,301,301
$ 990,094
$ 787,701
$ 739,590
Net income (loss)
$
(99,370)
$
87,348
$ 187,098
$ 190,015
$ 151,936
Net income (loss) per share:
Basic
Diluted
$
$
(1.59)
(1.59)
$
$
1.40
1.38
$
$
3.02
2.90
$
$
3.38
2.94
$
$
2.67
2.33
Total assets at year end
$ 2,360,936
$ 2,697,247
$ 2,572,942
$ 1,899,097
$1,268,747
Long-term obligations:
Line of credit
Senior convertible notes,
net of debt discount
Cash dividends declared and
paid per common share
$ 188,000
$ 300,000
$ 285,000
$ 334,000
$
-
$ 266,902
$ 258,713
$ 251,070
$
99,980
$
99,885
$
0.10
$
0.10
$
0.10
$
0.10
$
0.10
(1) As Adjusted, see Note 5 to the Consolidated Financial Statements
48
Supplemental Selected Financial and Operations Data
2009
2008
Years Ended December 31,
2006
2007
(In thousands, except per share data)
2005
Balance Sheet Data
Total working capital (deficit)
Total stockholders’ equity
$
(87,625)
$ 973,570
$ 15,193
$1,162,509
$ (92,604)
$ 902,574
$
22,870
$ 743,374
$
$
4,937
569,320
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:
62,457
62,457
53.8
449.5
772.2
62,243
63,133
61,852
64,850
51.4
557.4
865.5
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
$ 756,601
$ 206,800
$ 304,201
76,036
$
$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
6.3
71.1
109.1
54.40
3.82
56.74
5.59
1.33
0.19
0.37
2.79
0.70
$
$
$
$
$
$
$
$
$
6.6
74.9
114.6
6.9
66.1
107.5
6.1
56.4
92.8
$
$
$
$
$
$
$
$
$
92.99
8.60
$
$
67.56
6.74
$
$
59.33
6.58
$
$
75.59
8.79
$
$
62.60
7.63
$
$
56.60
7.37
$
$
1.46
0.19
0.71
2.74
0.69
$
$
$
$
$
1.31
0.14
0.58
2.12
0.56
$
$
$
$
$
1.25
0.12
0.54
1.67
0.42
$
$
$
$
$
5.9
51.8
87.4
53.18
8.08
50.93
7.90
0.99
0.09
0.56
1.52
0.37
Provided by operations
Used in investing
Provided by (used in) financing
$ 436,106
$ (304,092)
$ (127,496)
$ 679,190
$ (673,754)
$ (42,815)
$ 632,054
$ (805,134)
$ 215,126
$ 467,700
$
$ (724,719) $
$
$ 243,558
409,379
(339,779)
(61,093)
49
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 the Rocky Mountain Williston Basin; the Mid-Continent Anadarko and Arkoma basins;
the Permian Basin; the productive formations of East Texas and North Louisiana; north central Pennsylvania; 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 deliver outstanding net asset value per share growth to our investors via attractive oil
and gas investments. 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 a 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 2009 we had the following financial and operational results:
Average daily gas production of 194.8 MMcf was down five percent from 2008. Average daily oil
production of 17.3 MBbl was down four percent from 2008. Average total equivalent daily
production was 298.8 MMCFE, which was down five percent from 2008.
Estimated proved reserves of 53.8 MMBbls of oil and 449.5 Bcf of natural gas, or 772.2 BCFE, as of
December 31, 2009. This was a decrease of 11 percent from year-end 2008 proved reserves of
865.5 BCFE and reflects the divestiture of 44.2 BCFE of non-strategic properties, 61.6 BCFE in net
downward performance revisions, and 12.0 BCFE of net positive price revisions. We had reserve
additions from extensions and discoveries and infill drilling of 109.6 BCFE.
We recorded a net loss of $99.4 million and diluted loss per share of $1.59 for the year ended
December 31, 2009. This compares with net income of $87.3 million, or $1.38 per diluted share, for
the year ended December 31, 2008.
Cash flow from operating activities of $436.1 million, a decrease of 36 percent from 2008.
Costs incurred for oil and gas producing activities for the year ended December 31, 2009, were
$419.0 million, compared with $857.7 million for the same period in 2008.
Our operations are generally funded first through cash flows from operating activities and then through
borrowings under our existing credit facility. The divestiture of non-core assets is also a potential source of
liquidity. 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 2009 we invested
$377.2 million for development and exploration and $41.7 million for leasehold.
50
A major determination of the value of our company is the value of our proved reserves. At year-end 2009
we had proved reserves of 772.2 BCFE of which 58 percent were natural gas and 82 percent were characterized as
proved developed. There were a number of changes that took effect in 2009 impacting the calculation of our
year-end proved reserves. The SEC instituted a number of revisions to its existing oil and gas reporting
requirements. A key revision to the rules pertains to the use of 12-month average pricing as opposed to year-end
pricing in estimating proved reserves. The prices used in the calculation of proved reserve estimates as of
December 31, 2009, were $61.18 per Bbl and $3.87 per MMBTU for oil and natural gas, respectively. These
prices were 23 percent and 33 percent lower, respectively, than the year-end prices that would have been used
under the SEC’s previous methodology. Additional changes in the SEC rules provide for the use of new
technology to determine proved reserves and the ability to include nontraditional resources in proved reserves. In
addition to these regulatory changes, in 2009 we began recording estimates of proved reserve volumes for
properties we believe are reasonably certain to generate positive net cash flows on an undiscounted basis, which
we have the intent to drill, and which meet our internal economic criteria for drilling even though they may have a
negative PV-10 value. Previously, we booked proved reserve volumes if the properties showed a positive PV-10
value, we had the intent to drill, and the wells met our economic criteria.
We added 109.6 BCFE from our drilling program during the year, with our emerging resource play in the
Eagle Ford shale in the Maverick Basin in South Texas contributing a significant portion of those additions. Our
programs targeting the Woodford shale in eastern Oklahoma and the Bakken/Three Forks formations in the North
Dakota portion of the Williston Basin also added meaningful additions in 2009. We sold 44.2 BCFE of proved
reserves during the year, with roughly 90 percent of those relating to the divestiture of our coalbed methane
project at Hanging Woman Basin along the border of Montana and Wyoming. The balance of the divested
properties sold in 2009 was non-strategic assets, which were spread across the company. We had a downward net
revision of 49.6 BCFE that consisted of 61.6 BCFE in net downward engineering revisions and a net positive
pricing revision of 12.0 BCFE. The largest portion of the performance revision relates to producing properties in
our Wolfberry tight oil program in the Permian Basin in West Texas. Well performance data collected during
2009 for Wolfberry assets at Sweetie Peck and Halff East indicated these assets are underperforming our year-end
2008 decline forecasts. Accordingly, we removed roughly 37 BCFE from proved reserves in the Permian region,
primarily related to the Wolfberry tight oil program. We believe that a significant portion of these reserves, while
not meeting the criteria to be booked as proved reserves at year-end, are likely to be produced eventually. We
also saw a downward performance revision of approximately 12 BCFE related to certain Cotton Valley assets in
our ArkLaTex region. Due to the pricing methodology changes noted above, we recognized positive price
revisions in our oil-weighted Rocky Mountain and Permian regions that offset negative price revisions we
recognized in the natural gas weighted Mid-Continent, ArkLaTex, and South Texas & Gulf Coast regions. Under
the previous methodology of using year-end pricing for the determination of proved reserves, we would have had
an increase of four percent in proved reserves to approximately 897 BCFE.
The PV-10 value of our proved reserves was $1.3 billion as of December 31, 2009. The after tax value of
$1.0 billion as represented by the standardized measure calculation is presented in Note 16 – 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.
51
Reserve Replacement, Finding Costs, and Growth
Like all oil and gas exploration and production companies, we face the challenge of growing oil and
natural gas reserves. An exploration and production company depletes part of its asset base with each unit of oil
or gas it produces. Our future growth will depend on our ability to economically add reserves in excess of
production.
The following table provides various reserve replacement and finding cost metrics for the year ended
December 31, 2009:
Drilling, excluding revisions
Drilling, including revisions
Drilling and acquisitions, excluding
revisions
Drilling and acquisitions, including
revisions
Acquisitions
All-in
Reserve Replacement
Percentage
Excluding
sales
Including
sales
100%
55%
100%
55%
N/M
55%
60%
14%
60%
14%
N/M
14%
Finding Cost per MCFE
Excluding
sales
$
$
3.44
6.29
Including
sales
$
5.77
$ 23.91
$
3.44
$
5.77
$
$
6.29
N/M
6.99
$ 23.92
N/M
$ 26.56
The following table provides three-year average reserve replacement and finding cost metrics for the
years ended December 31, 2009, 2008, and 2007:
Drilling, excluding revisions
Drilling, including revisions
Drilling and acquisitions, excluding
revisions
Drilling and acquisitions, including
revisions
Acquisitions
All-in
124%
48%
162%
85%
37%
85%
Reserve Replacement
Percentage
Excluding
sales
Including
sales
Finding Cost per MCFE
Excluding
sales
4.27
$
$ 11.07
Including
sales
5.77
$
$ 33.90
92%
16%
129%
$
3.68
$
4.60
53%
5%
53%
$
$
$
6.97
1.72
7.79
$ 11.22
$ 12.60
$ 12.53
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 annual production with
new reserves. 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 15 –
Oil and Gas Activities and Note 16 – 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.
52
Financial Standing and Liquidity
During and subsequent to the third quarter of 2008, specific issues related to the financial sector rippled
through the broader economy. The failure or takeovers of several large financial institutions adversely impacted
the wider equity, debt, and credit markets. Financial strength and liquidity became increasingly important as
investors considered the ability of companies to fund their planned levels of activity and to service their debt
obligations. In addition, fears of prolonged weakness in the global economy leading to anemic energy demand
resulted in a significant decline in oil and natural gas prices. As a result of these events, we entered 2009 with a
business plan designed to operate within our operating cash flow. We have maintained a disciplined approach
with our capital investments during the year, which, combined with higher operating cash flows than we
anticipated originally, have allowed us to maintain our strong financial position and reduce borrowings under our
credit facility. Our exploration and development program at the beginning of 2009 was designed to stay within
generated cash flow. We met this goal in 2009. We continue to believe we have adequate liquidity available to
us through our credit facility as discussed below under the caption Overview of Liquidity and Capital Resources.
Oil and Gas Prices
Our financial condition and the results of our operations 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 a given 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 either the average of the NYMEX West Texas Intermediate daily settlement 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, 2009,
2008, and 2007.
Crude Oil (per Bbl):
Average NYMEX WTI spot price
Realized price, before the effects of hedging
Net realized price, including the effects of hedging
Natural Gas (per Mcf):
Average NYMEX Henry Hub spot price
Realized price, before the effects of hedging
Net realized price, including the effects of hedging
For the Years Ended December 31,
2008
2009
2007
$
$
$
$
$
$
61.99
54.40
56.74
3.94
3.82
5.59
$
$
$
$
$
$
99.92
92.99
75.59
8.89
8.60
8.79
$
$
$
$
$
$
72.23
67.56
62.60
6.97
6.74
7.63
We expect future prices for oil and natural gas to be volatile. The comparative strength of the U.S. Dollar
will likely continue to impact crude prices just as changes in domestic industrial demand will continue to impact
the price of natural gas. The 12-month strip prices for NYMEX WTI crude and NYMEX Henry Hub gas as of
December 31, 2009, were $82.15 per Bbl and $5.87 per MMBTU, respectively; comparable prices as of February
16, 2010, were $79.43 per Bbl and $5.76 per MMBTU, respectively.
While changes in quoted NYMEX oil and 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 excludes the
effects of hedging. Our realized price is further impacted by the results of our hedging arrangements that are
settled in the respective periods. We refer to this price as our net realized price. For the year ended December 31,
2009, our net natural gas price realization was positively impacted by $125.9 million of realized hedge
settlements and our net oil price realization was positively impacted by $14.8 million of realized hedge
settlements.
53
Hedging Activities
Hedging is an important part of our financial risk management program. We have a Board-authorized
financial risk management policy that governs our practices related to hedging. The amount of production we
hedge is driven by the amount of debt on our consolidated balance sheet and the level of capital commitments and
long-term obligations we have in place. In the case of a significant acquisition of producing properties, we will
consider hedging a portion of the acquired production in order to protect the economics assumed in the
acquisition. With the hedges we have in place, we believe we have established a base cash flow stream for our
future operations, and our use of collars for a portion of the hedges allows us to participate in upward movements
in oil and gas prices while also setting a price floor for a portion of our production. 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.
We attempt to qualify our oil and gas derivative instruments as cash flow hedges for accounting purposes
under Accounting Standards Codification Topic 815. Changes in the value of our hedge positions are primarily
reflected in our consolidated balance sheets. A portion of the change in the value of our hedge positions is
recognized in our consolidated statements of operations due to the hedges being partially ineffective. We
recognized a $20.5 million in non-cash derivative loss for the year ended December 31, 2009.
The U.S. Congress is currently considering recent proposals to increase the regulatory oversight of the
over-the-counter derivatives markets in order to promote more transparency in those markets. Although we
cannot predict the ultimate outcome of these proposals, new regulations in this area may result in increased costs
and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and otherwise
manage our financial risks related to swings in oil and gas commodity prices.
2009 Highlights
Developments in emerging resource plays. During 2008, the Haynesville shale, the Eagle Ford shale, and
the Marcellus shale resource plays emerged as significant new sources of gas supply for the exploration and
production industry. We have exposure to each of these plays that, if successful, could provide for significant
future organic growth in reserves and production. The Haynesville shale emerged early in 2008 in northern
Louisiana and eastern Texas and quickly became the most active resource play in the country. Our position was
built as a result of prior leasing activity targeting the James Lime and Cotton Valley formations. Our Eagle Ford
shale position in the Maverick Basin in South Texas was built from 2007 through 2009 through a combination of
property acquisitions, leasing activity, and participation in a joint venture with industry partners. Late in 2008 we
entered into arrangements that allow us to earn or purchase acreage in the Marcellus shale in north central
Pennsylvania. During 2009 we worked to advance our understanding of these plays and move them closer to
development mode. The most progress was made in our Eagle Ford shale program in South Texas. We
successfully tested seven wells across our operated acreage position during the second half of 2009. The early
results from this program suggest wells at the southern end of our acreage will produce drier gas while wells
drilled further north will produce higher BTU-content gas and some condensate. We are currently booking only
the parallel offsets to producing wells as proved undeveloped locations. As a result, we believe meaningful
potential exists to grow proved reserves on our operated acreage with our planned drilling activity for 2010 and
increased understanding of how reliable technology will allow the play to be developed. On our joint venture
acreage in Dimmit County, Texas, we believe these wells will produce even higher amounts of condensate and oil
compared to our operated position. In the Haynesville shale program in the ArkLaTex region, a number of
successful wells were drilled around our acreage position in East Texas in 2009. We began horizontal drilling
early in 2010 when our 3D seismic analysis was completed. In our Marcellus shale program in north central
Pennsylvania, we drilled and completed our first two horizontal wells during 2009. Initial indications from the
well tests were encouraging. The gathering line that will connect these wells to sales is in the process of being
constructed.
Shift toward oil-weighted projects. As a result of continued downward pressure on natural gas prices and
an increase in oil prices, we began shifting capital investment dollars toward oil-weighted projects during the third
54
quarter. We saw an increase in activity in our Permian and Rocky Mountain regions as a result of this shift in
capital.
Borrowing base on credit facility maintained. On September 29, 2009, the borrowing base on our credit
facility was redetermined and maintained by our bank group at a value of $900 million.
Impairments. We recognized a pre-tax non-cash impairment of proved properties in the amount of $174.8
million in 2009. There was an impairment of proved properties in the amount of $302.2 million in 2008. A
significant decrease in the market price for natural gas, including differentials in effect at March 31, 2009, caused
the majority of the non-cash impairment. The largest portion of the change in 2009 was $97.3 million related to
assets located in the Mid-Continent region which were impacted by the lower March 31, 2009, prices referred to
above as well as wider than normal differentials. The ArkLaTex region was impacted by a $20.4 million
impairment related to downward pricing and engineering revisions. We incurred a $14.0 million impairment on
proved properties related to the write-down of certain assets located in the Gulf of Mexico for which we are
relinquishing our ownership interests.
During the year, we abandoned or impaired $45.4 million related to unproved properties. The largest
specific components of the 2009 impairment and abandonment related to the Floyd Shale acreage located in
Mississippi and acreage in Oklahoma. The remaining write-offs were related to acreage we believe we will not be
able to hold due to current allocations of capital and to acreage that we do not believe will be prospective.
Lastly, we incurred inventory write-downs of $14.2 million for the year ended December 31, 2009 in
order to present inventory at the lower of cost or market value. The market value of tubular goods and other
inventory items that were purchased in 2008 when prices for these goods were considerably higher declined over
the course of 2009 as a result of lower levels of activity throughout the industry.
Divestitures. We continue to optimize our portfolio of assets as part of our overall strategy to focus on
concentrated resource plays. As part of this strategy, on December 18, 2009, we completed the divestiture of our
non-strategic coalbed methane project at Hanging Woman Basin located in the Rocky Mountain region. Total
cash received was $23.3 million, which is subject to customary post-closing adjustments. During 2009 we
recorded an $11.4 million gain on divestiture activity, which included the gain from the Hanging Woman Basin
divestiture, as well as other smaller divestitures.
Production results. The table below details the regional breakdown of our 2009 production.
ArkLaTex
Mid-
Continent
South
Texas &
Gulf Coast
Permian
Rocky
Mountain
Total(1)
2009 Production:
Oil (MBbl)
Gas (MMcf)
Equivalent (MMCFE)
Avg. Daily Equivalents
(MMCFE/per day)
Relative percentage
(1) Totals may not add due to rounding
124
14,167
14,912
274
34,380
36,026
40.8
14%
98.7
33%
407
7,255
9,696
26.6
9%
1,845
4,075
15,148
3,678
11,229
33,295
6,328
71,106
109,077
41.5
14%
91.2
30%
298.8
100%
In 2009 our production and oil and gas production revenues have outperformed our initial budget for 2009
due to stronger than anticipated production results from our Mid-Continent and Permian regions. Please refer to
Comparison of Financial Results and Trends between 2009 and 2008 below for additional discussion on
production.
55
Net Profits Plan. For the year ended December 31, 2009, the change in the value of this liability resulted
in a non-cash benefit of $7.1 million compared with a $34.0 million benefit for the same period in 2008.
Decreases in oil and gas commodity prices 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.
Payments made from the Net Profits Plan have been expensed as compensation costs in the amounts of
$19.9 million, $36.3 million, and $31.9 million for the years ended December 31, 2009, 2008, and 2007,
respectively. Additionally, we accrued cash payments under the Net Profits Plan of $724,000 for the year ended
December 31, 2009, as a result of sales proceeds during the fourth quarter of 2009. For the year ended
December 31, 2008, we accrued for cash payments under the Net Profits Plan of $15.1 million as a result of sales
proceeds from the Abraxas and Greater Green River Basin divestitures. These cash payments are accounted for as a
reduction in the gain (loss) on divestiture activity in the accompanying consolidated statements of operations. There
were no significant cash payments made or accrued for under the Net Profits Plan as a result of divestitures during
2007.
The recurring 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 from the Net Profits Plan are
now being categorized as general and administrative expense as compared to exploration expense. This is a
function of the normal departure of employees who previously contributed to our exploration efforts. 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 equity awards. 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, 2009, 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. In 2009 we made adjustments to the discount rate used
for Net Profits Plan pools not in payout. Additionally, we changed the price assumption used for estimating the
liability from a 36-month combination of historical and future prices to one using NYMEX strip prices at the end
of the respective period.
Outlook for 2010
The general economic outlook for the country has improved compared to this time a year ago. We
successfully weathered a tough 2009, and in the process advanced a number of potential resource plays and
improved our financial condition.
As we enter 2010, we are well positioned both financially and operationally. Early in 2009, we extended
the maturity of our revolving credit facility and subsequently paid down outstanding borrowings on that facility
during the year. At the end of 2009, we had almost $500 million available under the revolving credit facility. We
have no debt maturities until 2012. Additionally, we believe access to the capital markets has improved
significantly since last year and that we could access capital through the public markets if necessary. From an
operational standpoint, we believe 2010 has the potential to be a promising year for us. We will be building upon
our successful testing programs from 2009. We have moved the Eagle Ford shale program much closer to
development mode, and it will receive the largest portion of our capital budget this year. We will also be
allocating more capital toward oil and rich natural gas projects given their higher returns in the current
56
environment. Specifically, we will be drilling more Wolfberry tight oil and Bakken/Three Forks wells in the
Permian and Rocky Mountain regions, respectively. We recently began drilling horizontal wells in the
Haynesville shale. We continue to monitor service costs as the recent uptick in industry activity threatens to push
rates for the drilling and completion of wells higher than the levels we saw in 2009.
57
Financial Results of Operations and Additional Comparative Data
We recorded a net loss for the year ended December 31, 2009 of $99.4 million or $(1.59) per diluted
share compared to 2008 results of net income of $87.3 million or $1.38 per diluted share.
The table below provides information regarding selected production and financial information for the
quarter ended December 31, 2009, and the immediately preceding three quarters. Additional details of per MCFE
costs are contained later in this section.
For the Three Months Ended
December 31,
2009
September 30,
2009
June 30,
2009
March 31,
2009
(In millions, except production sales data)
Production (BCFE)
Oil and gas production revenue, excluding the
effects of hedging
Realized oil and gas hedge gain
Gain (loss) on divestiture activity
Lease operating expense
Transportation costs
Production taxes
DD&A
Exploration
Impairment of proved properties
Abandonment and impairment of unproved
properties
Impairment of materials inventory
General and administrative
Bad debt recovery
Change in Net Profits Plan liability
Unrealized derivative (gain) loss
Net income (loss)
Percentage change from previous quarter:
Production (BCFE)
Oil and gas production revenue, excluding the
effects of hedging
Realized oil and gas hedge gain
Gain (loss) on divestiture activity
Lease operating expense
Transportation costs
Production taxes
DD&A
Exploration
Impairment of proved properties
Abandonment and impairment of unproved
properties
Impairment of materials inventory
General and administrative
Bad debt recovery
Change in Net Profits Plan liability
Unrealized derivative (gain) loss
Net income (loss)
26.1
$ 187.6
13.4
$
22.1
$
34.3
$
5.2
$
13.3
$
75.1
$
13.4
$
21.6
$
$
$
$
$
$
$
$
25.2
0.8
20.7
(5.2)
7.0
3.2
1.0
(1)%
23%
(53)%
(296)%
-%
(2)%
48%
12%
(15)%
21,500%
425%
(62)%
-%
N/A
3%
(22)%
(123)%
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
26.4
152.7
28.3
(11.3)
34.3
5.3
9.0
67.0
15.7
0.1
4.8
2.1
20.8
-
6.8
4.1
(4.4)
(6)%
5%
(35)%
(969)%
(4)%
15%
(3)%
(5)%
(19)%
(98)%
(59)%
(22)%
14%
N/A
183%
(64)%
(47)%
28.2
28.4
$ 145.3
43.3
$
1.3
$
35.6
$
4.6
$
9.3
$
70.4
$
19.5
$
6.0
$
$
$
$
$
$
$
$
11.6
2.7
18.2
-
2.4
11.3
(8.3)
(1)%
11%
(22)%
317%
(14)%
(16)%
2%
(23)%
43%
(96)%
197%
(69)%
11%
N/A
(110)%
528%
(91)%
$ 130.4
55.6
$
(0.6)
$
41.2
$
5.5
$
9.1
$
91.7
$
$
13.6
$ 147.0
$
$
$
$
$
$
$
3.9
8.6
16.4
-
(23.3)
1.8
(87.6)
(5)%
(32)%
24%
(106)%
(14)%
(10)%
(23)%
(4)%
(23)%
(50)%
(89)%
N/A
32%
N/A
(71)%
(115)%
(31)%
58
Changes in production volumes, oil and gas production revenues, and costs reflect the cyclical and highly
volatile nature of our industry. As a result of the effects of lower commodity prices, we have seen reduced
activity among many exploration and production companies over the past year which has led to lower lease
operating costs over the last two quarters. We believe that industry activity may be stabilizing to a point where
these costs no longer have much room to decline further. Production taxes are largely dependent on the prices we
receive for oil and natural gas. Depreciation, depletion, and amortization generally had been pressured upward in
recent years as production related to properties acquired or developed in a higher cost environment became a
larger percentage of our production mix. During 2009, we have seen our DD&A rate fluctuate as a result of
impairments and changes to our underlying proved reserve volumes, both of which have been affected by the
swings in commodity prices we have seen this year. Additionally, the accounting treatment for assets that are
classified as assets held for sale also impacted our DD&A rate since properties held for sale are no longer
depreciated. A portion of our general and administrative expense is tied to the net revenues we generate, which
are driven in large part by the realized commodity prices we receive for our production. The Net Profits Plan and
a portion of our current short-term incentive compensation are tied to net revenues and therefore are subject to
variability.
A year to year overview of selected reserve, production and financial information, including trends:
Selected Operations Data (In thousands, except sales price, volumes, and per MCFE amounts):
As of and for the Years Ended December 31,
2008
2007
2009
Percent Change Between
2009/2008
2008/2007
Total proved reserves
Oil (MMBbl)
Natural gas (Bcf)
BCFE
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
53.8
449.5
772.2
6.3
71.1
109.1
17.3
194.8
298.8
51.4
557.4
865.5
6.6
74.9
114.6
18.1
204.7
313.1
78.8
613.5
1,086.5
6.9
66.1
107.5
18.9
181.0
294.5
$ 359,075
397,526
$ 756,601
$ 500,062
658,242
$1,158,304
$ 432,375
504,202
$ 936,577
$ 145,463
20,657
40,680
$ 206,800
$ 167,384
22,205
81,766
$ 271,355
$ 140,389
15,529
62,290
$ 218,208
$
$
56.74
5.59
$ 75.59
8.79
$
$
$
$
$
$
62.60
7.63
8.71
(1.31)
(0.14)
(0.58)
(0.56)
6.12
2.12
1
$
$
6.94
(1.33)
(0.19)
(0.37)
(0.70)
4.35
$
$
$
10.11
(1.46)
(0.19)
(0.71)
(0.69)
7.06
2.74
59
(11)%
(20)%
(5)%
7%
(5)%
6%
(35)%
24%
(24)%
(25)%
(36)%
(31)%
(9)%
-%
(48)%
1%
(38)%
2%
24%
21%
15%
16%
11%
36%
22%
23%
15%
29%
Depletion, depreciation and amortization
$
2.79
(1) Includes the effects of our hedging activities.
We present per MCFE information because we use this information to evaluate our performance relative
to our peers and to identify and measure trends we believe require analysis. Volatility in commodity prices has
impacted our operating margins. The decrease in our equivalent realized price for production has corresponded
with the significant downward move in commodity prices over the last year. While our cost structure has
improved over the past year, it has not moved to the same degree. Our operating profit of $4.35 per MCFE for the
year ended December 31, 2009, decreased 38 percent from the $7.06 per MCFE we realized for the comparable
period in 2008.
Average daily production for the year ended December 31, 2009, decreased to 298.8 MMCFE compared
with 313.1 MMCFE for the same period in 2008. For the year ended December 31, 2009, our average net
realized price decreased by $3.17 per MCFE to $6.94 per MCFE from the same period in 2008. Lower
commodity prices were the principal driver of the decrease in 2009. Unit costs decreased for the year ended
December 31, 2009, as lease operating expense decreased $0.13 per MCFE to $1.33 per MCFE and production
taxes decreased $0.34 per MCFE to $0.37 per MCFE. Production taxes are highly correlated to commodity
prices, and a portion of our general and administrative expense is linked to our profitability and cash flow.
Transportation costs remained steady at $0.19 per MCFE for the years ended December 31, 2009, and 2008.
For the year ended December 31, 2009, depletion, depreciation, amortization, and asset retirement
obligation accretion expense, increased $0.05 per MCFE to $2.79 per MCFE compared with the same period in
2008. The depletion, depreciation, and amortization increase is a result of a decrease in proved reserves used to
calculate DD&A in the first quarter of 2009, please refer to additional DD&A discussion above. Exploration
expense for the year ended December 31, 2009, was $62.2 million, which was four percent higher than the
$60.1 million incurred during the comparable period in 2008. Geological and geophysical expense increased $6.0
million due to an increase in the amount spent for seismic analysis. Exploratory dry hole expense increased $1.0
million. These increases were offset by a $4.9 million decrease in exploration overhead due to a decrease in Net
Profits Plan payments resulting from decreased oil and gas commodity prices.
Proved reserves decreased 11 percent to 772.2 BCFE at December 31, 2009, from 865.5 BCFE at
December 31, 2008. Please see Note 16 – 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.
Financial information (In thousands, except per share amounts):
As of and for the Years Ended December 31,
2007
2008
2009
Percent Change Between
2009/2008
2008/2007
Working capital (deficit)
Long-term debt
Stockholders’ equity
Net income
(87,625)
$
$ 454,902
$ 973,570
(99,370)
$
Basic net income per common share
Diluted net income per common share
$
$
(1.59)
(1.59)
$ 15,193
$ 558,713
$1,162,509
$ 87,348
$
$
1.40
1.38
$ (92,604)
$ 536,070
$ 902,574
$ 187,098
$
$
3.02
2.90
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
62,457
62,457
62,243
63,133
61,852
64,850
$ 436,106
$ (304,092)
$ 679,190
$ (673,754)
$ 632,054
$ (805,134)
(677)%
(19)%
(16)%
(214)%
(214)%
(215)%
-%
(1)%
(36)%
(55)%
116%
4%
29%
(53)%
(54)%
(52)%
1%
(3)%
7%
(16)%
activities
$ (127,496)
$ (42,815)
$ 215,126
198%
(120)%
60
We present this table as a summary of information relating to key indicators of financial condition and
operating performance that we believe are important.
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 our 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. We have in-the-money stock options,
unvested RSUs, and PSAs that may be potentially dilutive securities. Both basic and diluted earnings per share
are presented in the table above. There were no potentially dilutive shares related to in-the-money stock options,
unvested RSUs, and PSAs included in the diluted earnings per share calculation for the year ended
December 31, 2009, as we recorded a net loss for the period. 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 2009, 2008, and 2007
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 189,740 shares of common stock in
2009, 868,372 shares in 2008, and 733,650 shares in 2007 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, and 792,216 shares in
2007 through our stock repurchase plan. Additionally, the number of RSUs that vested in 2009, 2008, and 2007
were 211,092, 291,659, and 268,123, respectively.
Additional Comparative Data in Tabular Format:
Oil and Gas Production Revenues:
Increase (decrease) in oil and gas production revenues, net
Change Between Years
2009 and 2008
2008 and 2007
of hedging (in thousands)
$
(401,703)
$
221,727
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
$
$
$
$
(18.85)
(25)%
(287)
(4)%
(3.20)
(36)%
(3,804)
(5)%
12.99
21%
(292)
(4)%
1.16
15%
8,849
13%
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,
2008
43%
57%
2009
47%
53%
2007
46%
54%
35%
65%
35%
65%
61
39%
61%
Information regarding the effects of oil and gas hedging activity:
2009
Years Ended December 31,
2008
2007
Oil Hedging
Percentage of oil production hedged
Oil volumes hedged (MBbl)
Increase (Decrease) in oil revenue
Average realized oil price per Bbl before hedging
Average realized oil price per Bbl after hedging
52%
3,306
$ 14.8 million
54.40
$
56.74
$
61%
4,022
$(115.1 million)
92.99
$
75.59
$
66%
4,565
$(34.3 million)
67.56
$
62.60
$
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
45%
34.3 million
$ 125.9 million
3.82
5.59
46%
36.4 million
$ 14.0 million
8.60
$
8.79
$
46%
32.5 million
$ 58.7 million
6.74
$
7.63
$
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
2009
Years Ended December 31,
2008
2007
$
$
20.2
7.8
34.2
62.2
$
$
14.2
6.8
39.1
60.1
$
$
17.0
14.4
27.3
58.7
Comparison of Financial Results and Trends between 2009 and 2008
Oil and gas production revenue. Production decreased five percent to 109.1 BCFE for the year ended
December 31, 2009, compared with 114.6 BCFE for the year ended December 31, 2008. Production for the year
ended December 31, 2009, includes approximately 5.1 BCFE related to non-core properties divested throughout
2009. Adjusting for divestitures of non-core properties that were sold in the last two years, production on
retained properties declined slightly from 104.5 BCFE in 2008 to 104.0 BCFE in 2009. 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)
(9.9)
8.5
(12.4)
3.7
(4.2)
(14.3)
ArkLaTex
Mid-Continent
South Texas & Gulf Coast
Permian
Rocky Mountain
Total
$
Pre-Hedge
Oil and Gas
Revenue Added
(Lost)
(In millions)
(115.0)
(142.1)
(97.0)
(79.1)
(210.2)
(643.4)
$
$
Production
Costs Increase
(Decrease)
(In millions)
(1.1)
(16.4)
(13.8)
(1.7)
(31.6)
(64.6)
$
Daily production decreased by approximately 14.3 MMCFE during 2009 compared to 2008. Production
decreased between these two periods as a result of decreased levels of capital investment throughout 2009 and the
lack of contribution in 2009 from properties that were sold in the second half of 2008. The largest regional
62
increase between 2009 and 2008 occurred in the Mid-Continent region as a result of success in the horizontal
Woodford shale program in the Arkoma Basin and strong results from our Deep Springer program in the
Anadarko Basin. Production growth in the Permian region is the result of continued development of Wolfberry
assets at Sweetie Peck and Halff East. The decrease in the South Texas & Gulf Coast region’s production is
primarily a result of the loss of production from the Judge Digby Field due to an exchange of assets that occurred
in late 2008. The ArkLaTex decrease is due to natural decline and decreased levels of capital investment in the
region by us and our partners, particularly at the Elm Grove Field. The Rocky Mountain region realized a slight
decline as a result of its more mature production decline profile and modest capital investment.
Realized oil and gas hedge gain (loss). We recorded a net realized hedge gain of $140.6 million for the
year ended December 31, 2009, mainly related to favorable settlements on gas hedges. For the year ended
December 31, 2008, we recorded a net realized hedge loss of $101.1 million mainly due to unfavorable
settlements on oil hedges. Please refer to our discussion above under the heading Oil and Gas Prices.
Marketed gas system revenue and expense. Marketed gas system revenue decreased $18.9 million to
$58.5 million for the year ended December 31, 2009, compared with $77.4 million for the comparable period of
2008. Concurrent with the decrease in marketed gas system revenue, marketed gas system expense decreased
$14.6 million to $57.6 million for the year ended December 31, 2009, compared with $72.2 million for the
comparable period of 2008. We expect that marketed gas system revenue and expense will continue to trend with
increases and decreases in production and our price realizations before the impact of hedging.
Gain (loss) on divestiture activity. We recorded a gain on divestiture activity of $11.4 million for the year
ended December 31, 2009, compared with $63.6 million for the comparable period of 2008. The 2009 gain is
mainly related to the Hanging Woman Basin divestiture that closed in December of 2009, which is subject to
normal post-closing adjustments and is expected to be finalized during the first quarter of 2010. The 2008 gain is
mainly related to the Abraxas divestiture that closed in January 2008. We expect to continue to evaluate potential
divestitures of non-strategic properties.
Oil and gas production expense. Total production costs decreased $64.6 million or 24 percent to
$206.8 million for the year ended December 31, 2009, compared with $271.4 million in 2008. Total oil and gas
production costs per MCFE decreased $0.47 to $1.89 for the year ended December 31, 2009, compared with
$2.36 in 2008. This decrease is comprised of the following:
A $0.34 decrease in production taxes on a per MCFE basis due to the decrease in realized prices
between periods. We expect production taxes to trend with commodity prices.
A $0.11 decrease in recurring lease operating expense on a per MCFE basis is related to reductions in
recurring LOE that stems from the slowdown in activity in the exploration and production industry, as
well as the broader economy.
A $0.02 decrease in overall workover LOE on a per MCFE basis is related to a reduction in the
amount of workovers that were performed given the slowdown in activity in the exploration and
production industry.
Transportation costs on a per MCFE basis remained flat year over year.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A
decreased $10.1 million, or three percent, to $304.2 million in 2009 compared with $314.3 million in 2008.
DD&A expense per MCFE increased two percent to $2.79 in 2009 compared to $2.74 in 2008. The decrease in
absolute DD&A reflects lower total production volumes in 2009 compared to 2008. Our DD&A expense per
MCFE decreased due to the significant decrease in our carrying value of our properties as a result of proved
property impairments that we incurred in the fourth quarter of 2008 and the first quarter of 2009. Proved property
impairments and changes in underlying proved reserve volumes will continue to be affected by the swings in
commodity prices.
63
Exploration. Exploration expense increased $2.1 million or four percent to $62.2 million in 2009
compared with $60.1 million for 2008. The increase is due to a $1.0 million increase in exploratory dry hole
expense and a $6.0 million increase in geological and geophysical expense due to an increase in the amount spent
on seismic. We anticipate that we will continue to acquire seismic data into 2010 in order to minimize risk with
respect to the acreage in our emerging resource plays with the expectation that we can optimize their future
development. These increases were offset by a $4.9 million decrease in exploration overhead expense due to a
decrease in Net Profits Plan payments as a result of decreased oil and gas commodity prices. We expect
payments made under the Net Profits Plan to trend with commodity prices.
Impairment of proved properties. We recorded a $174.8 million impairment of proved oil and gas
properties in 2009 compared to $302.2 million in 2008. A significant decrease in commodity prices, including
differentials, during the first quarter of 2009 caused the majority of the non-cash impairment. The largest portion
of the impairment in 2009 was $97.3 million related to assets located in the Mid-Continent region which were
impacted at the end of the first quarter by low natural gas prices and wider than normal differentials. The
ArkLaTex region was impacted by a $20.4 million impairment related to negative pricing and engineering
revisions. We incurred a $14.0 million impairment on proved properties related to the write-down of certain
assets located in the Gulf of Mexico in which we are relinquishing our ownership interests. We generally expect
proved property impairments will be more likely to occur in periods of low commodity prices.
Abandonment and impairment of unproved properties. During 2009, we abandoned or impaired
$45.4 million of unproved properties compared with $39.0 million for 2008. The largest specific components of
the 2009 impairment and abandonment related to the Floyd Shale acreage located in Mississippi and acreage in
Oklahoma. Additionally, we incurred write-offs related to acreage we believe we will not keep based on our
current capital allocation plans or related to acreage that we do not believe will be prospective. We generally
expect impairments of unproved properties to be more likely to occur in periods of low commodity prices since
fewer dollars will be available for exploratory and development efforts.
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. We had no goodwill impairment in 2009.
Impairment of materials inventory. We recorded a $14.2 million impairment of materials inventory for
the year ended December 31, 2009. There were no impairments recorded in 2008. The inventory impairment was
caused by a decrease in the value of tubular goods and other raw materials. Impairments of materials inventory
are impacted by fluctuations in the materials cost environment and increases and decreases in development and
exploration activity, which generally trend with commodity prices.
General and administrative. General and administrative expense decreased $3.5 million or four percent
to $76.0 million for the year ended December 31, 2009, compared with $79.5 million for the same period in 2008.
G&A increased $0.01 to $0.70 per MCFE for the year ended December 31, 2009, compared to $0.69 per MCFE
for the same period in 2008.
General and administrative expense decreased due to an $11.3 million decrease in cash payments made
under the Net Profits Plan. As a result of the lower price realization we received in 2009 compared to 2008, the
payouts from this plan were meaningfully smaller than those paid out in the prior year. We expect payments
made under the Net Profits Plan to trend with commodity prices.
Compensation related costs allocated to general and administrative expense increased in 2009. The
largest increases were for headcount related costs, such as salary, benefits, and payroll taxes, which increased
$10.6 million for the year ended December 31, 2009, when compared with the same period in 2008. A significant
driver of this headcount increase had been the conversion from contract lease operators to internal lease operators
which began to take place in 2008. Stock compensation was also up $ 3.3 million year over year as a result of
layering in the second year of stock compensation amortization from our PSA long-term incentive program.
64
COPAS overhead reimbursements were $6.4 million higher for the year ended December 31, 2009, compared
with the same period in 2008.
Bad debt expense (recovery). We recorded a recovery of bad debt expense of $5.2 million in 2009. 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.
Change in Net Profits Plan liability. For the year ended December 31, 2009, this non-cash item was a
$7.1 million benefit compared to $34.0 million benefit for the same period in 2008. Significant decreases in oil
and gas commodity prices 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. We expect the change in
this liability to trend with commodity prices.
Unrealized derivative (gain) loss. We recognized a loss of $20.5 million for the year ended
December 31, 2009, compared to a gain of $11.2 million for the same period in 2008. This non-cash item is
driven by the change in the value of our hedge position, as well as the portion of that position that is considered
ineffective for accounting purposes. Please refer to our discussion under the heading Oil and Gas Prices.
Other expense. Other expense increased $3.1 million to $13.5 million for the year ended
December 31, 2009, compared with $10.4 million for the same period in 2008. During the year ended December
31, 2009, we incurred $1.5 million of expense related to the assignment of a drilling rig contract in our Rocky
Mountain region. We also incurred a loss related to hurricanes of $8.3 million for the year ended December 31,
2009, compared with a loss related to hurricanes of $7.0 million for the same period in 2008.
Income tax benefit (expense). Income tax benefit totaled $60.1 million for 2009 compared to tax expense
of $57.4 million for 2008, resulting in effective tax rates of 37.7 percent and 39.7 percent, respectively. The
effects of individual components of our tax rate can vary between periods resulting in fluctuations. The effective
rate change from 2008 primarily reflects the impact of goodwill impairment in that year, but changes in the mix of
the highest marginal state tax rates and differing effects of other permanent differences, including the impact
between years of the domestic production activities deduction and percentage depletion, also had an effect. Our
current income tax benefit in 2009 is $20.4 million compared to current income tax expense of $19.2 million in
2008. These amounts are 34 percent and 33 percent, respectively, of the total income tax benefit or expense for
each period. Our 2009 current income tax benefit reflects creation of a net operating loss which we can carry back
to one or more prior tax years to obtain a refund. In future years, creation of net operating losses may not create
current tax benefits. During 2009 we observed with interest U.S. Congressional legislative activity relating to
possible changes in taxation of our industry. If the proposed legislation, which would reduce or eliminate current
tax deductions for intangible drilling costs, the domestic production activities deduction, and percentage depletion
allowance passes, we would expect our effective tax rate and the cash tax portion of our income tax expense to
increase in the year the legislation becomes effective.
65
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
South Texas & 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 South Texas & 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 was the result of continued development
of the Wolfberry assets at Sweetie Peck and Halff East. The declines in production in the Mid-Continent and
Rocky Mountain regions were the result of the divestiture of non-core properties in these regions, which resulted
in a smaller production base for 2008.
Realized oil and gas 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.
Other revenue. Other revenues decreased $6.6 million to $2.1 million for the year ended
December 31, 2008, compared with $8.7 million for 2007. The decrease was due primarily to a $5.2 million gain
recognized in 2007 associated with a global insurance settlement attributed to Hurricane Rita.
Gain (loss) on divestiture activity. 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 2008.
66
Oil and gas production expense. 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 was 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 wells completed in 2008 that had 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 was related to higher
costs, particularly in oil-weighted regions, for items such as fuel and fluid disposal and an increase in
the South Texas & 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 South Texas & 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 was 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 reflected the costs of production facilities
in the offshore Gulf Coast that had increased significantly in recent years and that started 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.
Exploration. Exploration expense increased $1.4 million or two percent to $60.1 million in 2008
compared with $58.7 million for 2007. The increase was 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 South Texas & Gulf
Coast region, as well as for gas properties in the Rocky Mountain region.
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 related to
acreage that we believed we either would not be able to hold in the current period of limited capital availability or
to acreage that we did not believe would be prospective.
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.
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 resulted in an increase in base employee
67
compensation, including taxes and benefits, of approximately $23.9 million between 2008 and 2007. A
significant driver of this headcount increase had 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 payments.
Additionally, an increased percentage of the distribution dollars under the Net Profits Plan associated with general
and administrative expense contributed to a $4.4 million increase in the current period realized expense in 2008
compared with the same period in 2007.
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 resulted 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. Our 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.
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.
Income tax benefit (expense). Income tax expense totaled $57.4 million for 2008 and $109.0 million for
2007, resulting in effective tax rates of 39.7 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.
Our current income tax expense in 2008 was $19.2 million compared to $17.6 million in 2007. These
amounts were 33 percent and 16 percent of the total income tax expense for the respective periods.
Overview of Liquidity and Capital Resources
In order 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.
Sources of cash
Based on our current outlook, we expect our generated cash flow from operations in 2010 plus proceeds
from our pending Rocky Mountain oil and other non-core asset divestiture packages to fund our exploration and
development budget for 2010. Accordingly, we do not expect to access the capital markets in 2010. Throughout
2009, we identified and marketed non-core oil and gas properties. Net cash proceeds from transactions that
closed in 2009, after commission costs, were $39.9 million. Subsequent to year end, we closed the Wyoming
portion of our Rocky Mountain oil package and we plan to close the remaining North Dakota portion by the end
of the first quarter of 2010. We anticipate we will continue to evaluate our property base to identify and divest of
properties we consider non-core to our strategic goals.
68
Our primary sources of liquidity are the cash flows provided by operating activities, use of our credit
facility, 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 and by significant fluctuations in oil and gas prices, operating costs, and
volumes produced all of which affect us and our industry. 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 our oil and gas
sales through the use of derivative contracts. The borrowing base on our credit facility could be reduced as a
result of lower commodity prices or sales of non-core producing properties. Historically, decreases in market
prices have limited our industry’s access to the capital markets. We believe the public debt markets are currently
accessible. Equity and convertible debt issuances are also available to us as alternative financing sources. We do
not anticipate the need to raise public debt or equity financing in the near term, however these are options we
would consider under the appropriate circumstances. We intend to rely on our credit facility for borrowings.
Current credit facility
On April 14, 2009, we entered into an amended $1.0 billion senior secured revolving credit facility with
twelve participating banks. The initial borrowing base was set at $900 million. On September 29, 2009, the
lending group redetermined our reserve-backed borrowing base under the credit facility at $900 million. We have
been provided a $678 million commitment amount by the bank group. The new amended credit facility
agreement has a maturity date of July 31, 2012. Management believes that the current commitment is sufficient
for our liquidity needs. To date, we have experienced no issues drawing upon our credit facility. No individual
bank participating in the credit facility represents more than 16 percent of the lending commitments under the
credit facility. We monitor the credit environment closely and have frequent discussions with the lending group.
As of February 16, 2010, we had $467.0 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. Outstanding loans reduce the amount available under the commitment amount on a dollar-for-
dollar basis, as do letters of credit. Borrowings under the facility are secured by mortgages on the majority of our
oil and gas properties and a pledge of the common stock of our material subsidiary companies.
Our weighted-average interest rate paid in 2009 was 5.4 percent and included fees paid on the unused
portion of the credit facility’s aggregate commitment amount and amortization of deferred financing costs and the
debt discount. We decreased our net borrowings from the previous year by $112.0 million when comparing the
ending 2009 and 2008 balance sheet amounts. A decrease in the average outstanding credit facility balance
throughout 2009, plus a decrease in interest rates, was offset by higher applicable margins, higher commitment
fees on the unused portion of our credit facility and amortization of upfront financing costs and the 3.50% Senior
Convertible Notes debt discount. This resulted in interest expense of $28.9 million in 2009 compared with $27.0
million in 2008.
We are subject to customary covenants under our credit facility, including limitations on dividend
payments and requirements to maintain certain financial ratios, which include debt to 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, 2009, our debt to EBITDA ratio and current ratio as defined by our
credit agreement, were 1.10 and 2.75, respectively. We are in compliance with all covenants under this credit
facility and expect to be in compliance for at least 12 months.
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
69
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 2009 we spent $379.3 million of cash on capital development and $76,000 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. Our capital and exploration expenditures in 2010 will be funded with current year
operating cash flows and proceeds from the divestiture of non-core assets. 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, investing 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.
As of the filing date of this report we have Board authorization to repurchase up to 3,072,184 shares of
our common stock under our stock repurchase program. Shares may be repurchased from time to time in open
market transactions or privately negotiated transactions subject to market conditions and other factors including
certain provisions of our existing bank credit facility agreement, compliance with securities laws, and the terms
and provisions of our stock repurchase program. There were no share repurchases in 2009.
Current proposals to fund the federal budget include eliminating or reducing current tax deductions for
intangible drilling costs, the domestic production activities deduction, and percentage depletion. Legislation
modifying or eliminating these deductions would have the immediate effect of reducing operating cash flows
thereby reducing funding available for our exploration and development capital programs and those of our peers
in the industry. These funding reductions could have a significant adverse effect on drilling in the United States
for a number of years.
In 2009 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.
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 (Used in ) Operating
Activities
Net Cash Provided By Investing Activities
Net Cash Used In Financing Activities
Amount of Changes
Between
Percent of Change
Between
2009/2008
$(243,084)
$ 369,662
$ (84,681)
2008/2007
$ 47,136
$ 131,380
$( 257,941)
2009/2008
(36)%
(55)%
198%
2008/2007
7%
(16)%
(120)%
70
Analysis of cash flow changes between 2009 and 2008
Operating activities. Cash received from oil and gas production revenues, net of the realized effects of
hedging, decreased $438.5 million to $751.8 million for the year ended December 31, 2009. The decrease was
the result of a five percent decrease in production and a 31 percent decrease in our net realized price after
hedging, resulting in a 35 percent decrease in production revenue. Included in the 2009 oil and gas production
revenue amounts is $140.6 million of net realized hedging gains. We received $9.9 million in income tax refunds
in 2009 compared to payments of $17.3 million during 2008.
Investing activities. Cash used for investing activities decreased $369.7 million for the year ended
December 31, 2009, compared with the same period in 2008. Cash outflows for 2009 capital expenditures for
development and exploration activities decreased $367.3 million or 49 percent to $379.3 million, which reflects a
reduced level of activity as a result of lower commodity prices. Total cash outflow for 2009 related to the
acquisition of oil and gas properties decreased $81.7 million or 100 percent to $76,000. We had no significant
acquisitions of oil and gas properties in 2009, compared with the acquisition of Carthage Field properties during
2008. Proceeds from an insurance settlement relating to Hurricane Ike were $16.8 million for the year ended
December 31, 2009, compared with the same period in 2008 when we received no proceeds from insurance
settlements. Proceeds from the sale of oil and gas properties for the year ended December 31, 2009, decreased
$139.0 million compared to the same period in 2008. Current year proceeds received from the sale of oil and gas
properties relate to non-core properties located in the Rocky Mountain region that were divested of in the fourth
quarter of 2009. The majority of the 2008 proceeds related to non-core properties sold to Abraxas in the first
quarter of 2008.
Financing activities. Net repayments to our credit facility increased $127.0 million for the year ended
December 31, 2009, compared to 2008. We spent $11.1 million on debt issuance costs for our amended credit
facility during the year ended December 31, 2009. We did not incur any debt issuance costs during 2008. Our
income tax benefit attributable to the exercise of stock awards decreased $13.9 million in the year ended
December 31, 2009, compared with 2008. We received $8.8 million less in proceeds from the sale of common
stock in 2009, than in 2008. Additionally, we invested $77.2 million less to repurchase shares of our common
stock during 2009, than in 2008.
We had $10.6 million in cash and cash equivalents and a working capital deficit of $87.6 million as of
December 31, 2009, compared to $6.1 million in cash and cash equivalents and working capital of $15.2 million
as of December 31, 2008.
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
was $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 $107.6 million or 17 percent to $746.6 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 2008 as
compared to 2007.
Financing activities. Net repayments to our credit facility decreased $64.0 million for the year 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 awards increased $3.9 million to $13.9 million for the year ended December 31, 2008, compared with the
71
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.
Capital Expenditures
The following table sets forth certain historical information regarding the costs incurred by us in our oil
and gas producing activities.
Development costs
Exploration costs
Acquisitions
Proved properties
Unproved properties – acquisitions of
proved properties (1)
Unproved properties - other
2009
For the Years Ended December 31,
2008
(In thousands)
$ 587,548
92,199
$ 592,275
111,470
2007
$ 223,108
154,122
76
51,567
161,665
-
41,677
$ 418,983
43,274
83,078
$ 857,666
23,495
38,436
$ 927,341
Total, including asset retirement obligations(2)(3)
)
(1) 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.
(2) Includes capitalized interest of $1.9 million, $4.7 million, and $6.7 million for the years ended December 31 2009, 2008, and 2007,
respectively.
(3) Includes amounts relating to estimated asset retirement obligations of $(805,000), $15.4 million, and $27.6 million for the years ended
December 31 2009, 2008, and 2007, 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. 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.
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 $188.0 million of floating-rate debt outstanding as of December 31, 2009. Our fixed-rate debt
outstanding, net of debt discount, at this same date was $266.9 million. As of December 31, 2009, we do not have
any interest rate hedges in place to mitigate potential risks.
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 for natural gas, for oil, and in combination
for the years presented, inclusive of the impact of hedging. 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
income taxes. General and administrative expenses have not been adjusted. To fund the capital expenditures we
72
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 decrease
in average realized sales price:
2009
For the Years Ended December 31,
2008
(In thousands)
2007
Oil
Natural Gas
Total
$ 29,523
11,874
$ 41,397
$ 27,818
37,288
$ 65,106
$ 25,248
29,998
$ 55,246
We enter into hedging transactions in order to reduce the impact of fluctuations in commodity prices.
Please refer to Note 10 – Derivative Financial Instruments of Part IV, Item 15 of this report for additional
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. 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 and long-term
commitments we have made. In the case of a significant acquisition of producing properties, we will consider
hedging a portion of the anticipated production in order to protect the economics assumed at the time of the
acquisition. As of December 31, 2009, and through the date of this filing, our hedged positions of anticipated
production through 2012 totaled approximately 6 million Bbls of oil, 63 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.
73
The following table describes the volumes, average contract prices, and fair value of contracts we have in
place as of December 31, 2009. We seek to minimize basis risk and index the majority of our oil contracts to
NYMEX WTI prices and the majority of 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
First quarter 2010
Second quarter 2010
Third quarter 2010
Fourth quarter 2010
2011
2012
All oil swap contracts
Oil Collars
Weighted-
Average
Contract
Price
(per Bbl)
$
$
$
$
$
$
69.92
69.46
68.77
66.06
67.06
82.19
Volumes
(Bbls)
468,000
426,000
393,000
309,000
1,164,000
1,051,400
3,811,400
Fair Value at
December 31, 2009
Asset/(Liability)
(in thousands)
(4,777)
$
(5,180)
(5,513)
(5,457)
(20,977)
(5,503)
$
(47,407)
Contract Period
First quarter 2010
Second quarter 2010
Third quarter 2010
Fourth quarter 2010
2011
All oil collars
NYMEX WTI
Volumes
(Bbls)
337,500
341,000
344,500
344,500
1,236,000
2,603,500
Weighted-
Average
Floor
Price
(per Bbl)
$ 50.00
$ 50.00
$ 50.00
$ 50.00
$ 50.00
Weighted-
Average
Ceiling
Price
(per Bbl)
$ 64.91
$ 64.91
$ 64.91
$ 64.91
$ 63.70
Fair Value at
December 31, 2009
Asset/(Liability)
(in thousands)
(5,264)
(6,198)
(6,916)
(7,378)
$
(29,707)
(55,463)
$
74
Gas Contracts
Gas Swaps
Contract Period
First quarter 2010
IF ANR OK
IF CIG
IF EL PASO
IF HSC
IF NGPL
IF NNG VENTURA
IF PEPL
IF RELIANT
IF TETCO STX
NYMEX Henry Hub
Second quarter 2010
IF ANR OK
IF CIG
IF EL PASO
IF HSC
IF NGPL
IF NNG VENTURA
IF PEPL
IF RELIANT
IF TETCO STX
NYMEX Henry Hub
Third quarter 2010
IF ANR OK
IF CIG
IF EL PASO
IF HSC
IF NGPL
IF NNG VENTURA
IF PEPL
IF RELIANT
IF TETCO STX
NYMEX Henry Hub
Fourth quarter 2010
IF ANR OK
IF CIG
IF EL PASO
IF HSC
IF NGPL
IF NNG VENTURA
IF PEPL
IF RELIANT
IF TETCO STX
NYMEX Henry Hub
Volumes
(MMBtu)
160,000
210,000
400,000
2,270,000
460,000
380,000
410,000
1,150,000
270,000
990,000
150,000
200,000
390,000
1,870,000
430,000
360,000
170,000
1,250,000
250,000
960,000
70,000
240,000
370,000
1,350,000
500,000
360,000
230,000
1,190,000
230,000
960,000
140,000
270,000
370,000
590,000
430,000
360,000
520,000
1,350,000
180,000
840,000
Weighted-
Average
Contract
Price
(per MMBtu)
Fair Value at
December 31, 2009
Asset/(Liability)
(in thousands)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
6.38
5.40
6.94
9.05
5.69
5.72
5.27
5.33
5.66
7.38
5.31
5.16
6.00
7.80
5.23
5.71
5.23
5.10
5.64
6.75
5.64
5.38
6.33
8.03
5.43
5.89
5.56
5.37
5.81
6.94
$
$
$
$
$
$
$
$
$
$
$
8.25
5.97
5.87
6.43
8.61
5.61
6.34
5.92
5.71
6.23
7.52
75
$
136
10
587
7,778
82
(60)
(102)
(135)
28
1,719
(3)
13
264
4,297
(31)
68
(9)
(270)
45
1,144
6
13
264
3,119
(47)
55
7
(151)
37
1,132
4
15
190
1,483
(124)
24
23
(219)
33
1,083
Gas Swaps (continued)
Contract Period
Volumes
(MMBtu)
Weighted-
Average
Contract
Price
(per MMBtu)
Fair Value at
December 31, 2009
Asset/(Liability)
(in thousands)
2011
IF ANR OK
IF CIG
IF EL PASO
IF HSC
IF NGPL
IF NNG VENTURA
IF PEPL
IF RELIANT
IF TETCO STX
NYMEX Henry Hub
2012
IF ANR OK
IF CIG
IF EL PASO
IF NGPL
IF NNG VENTURA
IF PEPL
IF RELIANT
IF TETCO STX
500,000
1,030,000
1,780,000
360,000
1,040,000
1,200,000
1,830,000
4,510,000
1,420,000
2,130,000
360,000
1,020,000
850,000
660,000
620,000
2,730,000
2,440,000
660,000
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
6.10
5.96
6.35
9.01
6.09
6.36
6.04
6.13
6.51
6.72
6.18
5.77
6.04
6.34
6.51
6.25
6.22
6.30
23
217
510
859
42
34
39
494
465
909
(11)
(160)
(139)
94
(35)
316
9
(16)
All gas swap contracts
48,420,000
$
26,158
76
Gas Collars
Contract Period
Volumes
(MMBtu)
First quarter 2010
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
Second quarter 2010
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
Third quarter 2010
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
Fourth quarter 2010
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
2011
IF CIG
IF HSC
IF PEPL
NYMEX Henry Hub
All gas collars
510,000
150,000
1,230,000
60,000
510,000
150,000
1,235,000
60,000
510,000
150,000
1,240,000
60,000
510,000
150,000
1,240,000
60,000
1,800,000
480,000
4,225,000
120,000
14,450,000
Weighted-
Average
Floor
Price
(per MMBtu)
Weighted-
Average
Ceiling
Price
(per MMBtu)
Fair Value at
December 31, 2009
Asset/(Liability)
(in thousands)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
4.85
5.57
5.31
6.00
4.85
5.57
5.31
6.00
4.85
5.57
5.31
6.00
4.85
5.57
5.31
6.00
5.00
5.57
5.31
6.00
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
7.08
7.88
7.61
8.38
7.08
7.88
7.61
8.38
7.08
7.88
7.61
8.38
7.08
7.88
7.61
8.38
6.32
6.77
6.51
7.25
$
65
46
302
27
177
84
639
49
121
72
518
46
(23)
38
247
28
(360)
(63)
(786)
15
$
1,242
77
Natural Gas Liquid Contracts
Natural Gas Liquid Swaps
Weighted-
Average
Contract
Price
(per Bbl)
$ 46.73
$ 46.28
$ 46.20
$ 46.16
$ 43.20
$ 43.70
Fair Value at
December 31, 2009
Asset/(Liability)
(in thousands)
$
(770)
(364)
(339)
(424)
(2,334)
(1,181)
Volumes
(approx. Bbls)
206,000
191,000
179,000
169,000
480,000
214,000
First quarter 2010
Second quarter 2010
Third quarter 2010
Fourth quarter 2010
2011
2012
All natural gas liquid swaps
1,439,000
$
(5,412)
Please see Note 10 – Derivative Financial Instruments in Part IV, Item 15 of this report for additional
information regarding our oil and gas hedges.
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
$ 498.2
61.1
302.8
$ 10.1
27.8
92.1
$ 488.1
9.7
125.1
$
-
5.3
59.9
$
-
18.3
25.7
Total
$ 862.1
$ 130.0
$ 622.9
$ 65.2
$ 44.0
This table includes the remaining unfunded portion of our estimated pension liability of $9.5 million even
though we recognize that we cannot determine with accuracy the timing of future payments. The Company is not
required to make a contribution to the Pension Plan in 2010. We made contributions of $2.0 million, $2.5 million,
and $2.2 million in 2009, 2008, and 2007, respectively, towards the pension liability. The table also includes
$166.1 million in other long-term liabilities that represents six years of undiscounted forecasted payments for the
Net Profits Plan. Payments are expected to gradually decrease for the years beyond what is shown in this table.
The amounts recorded on the consolidated balance sheets reflect all future Net Profits Plan payments and 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 2012. 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 prior to its expiration date. For purposes of this table, we assume we will net
share settle the 3.50% Senior Convertible Notes. Accordingly, $22.7 million of interest payments related to the
3.50% Senior Convertible Notes are included in the long-term debt line in table above. We have excluded asset
retirement obligations because we are not able to accurately predict the precise timing of these amounts. Pension
78
liabilities, asset retirement obligations, and Net Profits Plan are discussed in Note 8 – Pension Benefits, Note 9 –
Asset Retirement Obligations, and Note 7 – Compensation Plans of Part IV, Item 15 of this report.
This table also includes estimated oil and natural gas derivative payments of $119.4 million based on
future market prices as of December 31, 2009. This amount represents only the cash outflows; it does not include
estimated oil and gas derivative receipts of $38.0 million that would be paid based on December 31, 2009, market
prices. The net liability of $81.4 million represents cash flows from the intrinsic value of our collar arrangements
and differs in amount from our recorded fair value, which as of December 31, 2009, was a net liability of $80.9
million. The fair value considers time value, volatility, and the risk of non-performance for us and for our
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 and 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.
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, 2009, 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
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 due to 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, please refer to Note 1 – Summary of Significant Accounting Policies, Note 9 – Asset
Retirement Obligations, and Note 16 – Disclosures about Oil and Gas Producing Activities in Part IV, Item 15 of
this report.
Proved Oil and gas reserve quantities. Estimated reserve quantities and the related estimates of future net
cash flows are critical estimates for our company because they affect the perceived value of an exploration and
production company. Additionally, they are used in comparative financial analysis ratios and are used as the basis
for the most significant accounting estimates in our financial statements. Those 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 prices and costs, including transportation, quality
differentials, and basis differentials, applicable to each period to the estimated quantities of proved oil and gas
reserves remaining to be produced as of the end of that period. Expected cash flows are discounted 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 Accounting Standards Codification Topic 932
Extractive Activities – Oil and Gas requires a ten percent discount rate to be applied. Although reserve estimates
79
are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than
those of established producing oil and gas properties, we make a considerable effort in estimating our reserves,
including using independent reserve engineering consultants. We expect that periodic reserve estimates will
change in the future as additional information becomes available and as oil and gas prices and operating and
capital costs change. We evaluate and estimate our proved 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 the reserve
estimates change.
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 from 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,
2008
BCFE
Change
2007
BCFE
Change
2009
BCFE
Change
Revisions resulting from price changes
Revisions resulting from performance
Total
12.0
(61.6)
(49.6)
(199.7)
(44.5)
(244.2)
34.5
6.4
40.9
We have added 282.8 BCFE of reserves over a three-year period, excluding divestitures. A 99.7 BCFE
decrease in reserves was a result of changes in engineering estimates based on the performance of our oil and gas
properties. A 153.2 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 may
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:
BCFE
Change
(25.1)
A 10% decrease in pricing
A 10% decrease in proved
undeveloped reserves
(14.2)
2009
For the Years Ended December 31,
2008
2007
Percentage
Change
BCFE
Change
Percentage
Change
BCFE
Change
Percentage
Change
(3)%
(2)%
(120.8)
(14)%
(15.0)
(2)%
(16.3)
(25.0)
(2)%
(2)%
Additional reserve information can be found in the reserve table and discussion included in Items 1 and 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
80
resources. We derive our revenue primarily from the sale of produced natural gas, natural gas liquids, 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 approximately $8 million in 2009.
Crude oil and natural gas hedging. Our crude oil and natural gas hedging contracts are intended to and
usually do qualify for cash flow deferral hedge accounting under Accounting Standards Codification Topic 815.
Under this guidance a majority of the gain or loss from a contract qualifying as a cash flow hedge is deferred from
recognition in the consolidated statement of operations. The realized gain or loss reflected in the consolidated
statement of operations is based on actual hedge contract settlements. If our natural gas and crude oil hedge
contracts did not qualify for hedge accounting treatment or if we chose not to use 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 few years. The
amounts recorded to accumulated other comprehensive income (loss) of $103.3 million of loss, $223.5 million of
income, and $170.0 million of loss for 2009, 2008, and 2007, respectively, would have increased or decreased net
income after tax if our hedges did not qualify as cash flow deferral hedges under Accounting Standards
Codification Topic 815.
Change in Net Profits Plan Liability. We record the estimated liability of future payments for our Net
Profits Plan. The estimated liability is calculated based on a number of assumptions, including estimates of
proved 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 discount 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 its
estimate of fair value, which is determined by applying a discount rate 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 $174.8 million
impairment of proved oil and gas properties in 2009. A significant decrease in commodity prices and increase in
81
differentials during the first quarter of 2009 caused the majority of the non-cash impairment. The largest portion
of the impairment in 2009 was $97.3 million related to assets located in the Mid-Continent region that were
significantly impacted by lower prices and wider than normal differentials.
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 Accounting Standards
Codification Topic 740. 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 use and actual amounts we report are recorded in the
periods in which we file our income tax returns. These adjustments and changes in our estimates of asset
recovery and liability settlement could have an impact on our results of operations. A one percent change in our
effective tax rate would have changed our calculated income tax benefit by $675,000 for the year ended
December 31, 2009.
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, 2009, and 2008, our underfunded status was
$9.4 million and $8.2 million, respectively. The increase in underfunding from 2008 to 2009 was primarily
attributable to lower discount rates, which were 6.6 percent in 2008 and 6.1 percent in 2009. Our pension plan
assets increased from $6.6 million at December 31, 2008, to $9.1 million at December 31, 2009. On an Employee
Retirement Income Security Act basis, the Company’s pension plan remains fully funded at January 1, 2010. We
are not required to make any contributions to the pension plan in 2010. For additional information please refer to
Note 8 – Pension Benefits in Part IV, Item 15 of this report.
Accounting Matters
Please refer to Note 5 – Long-term Debt, Note 8 – Pension Benefits, Note 10 - Derivative Financial
Instruments, Note 11 – Fair Value Measurements, Note 16 – Disclosures about Oil and Gas Producing Activities,
and the section entitled ―Recently Issued Accounting Standards‖ under Note 1 – Summary of Significant
Accounting Policies for additional information on the recent adoption of new authoritative accounting guidance in
Part IV, Item 15 of this report.
Environmental
St. Mary’s compliance with applicable environmental regulations has to date not resulted in significant
capital expenditures or material adverse effects on our liquidity or results of operations. We believe we are in
substantial compliance with environmental regulations and do not currently anticipate that material future
expenditures will be required under the existing regulatory framework. However, we are unable to predict the
impact that compliance with future laws or regulations, such as those currently being considered as discussed
below, may have on future capital expenditures, liquidity, and results of operations.
The U.S. Congress is currently considering legislation that would amend the Safe Drinking Water Act to
eliminate an existing exemption from federal regulation of hydraulic fracturing activities. Hydraulic fracturing is
a common process in our industry of creating artificial cracks, or fractures, in deep underground rock formations
through the pressurized injection of water, sand and other additives to enable oil or natural gas to move more
easily through the rock pores to a production well. This process is often necessary to produce commercial
quantities of oil and natural gas from many reservoirs, especially shale rock formations. We routinely utilize
hydraulic fracturing in many of our reservoirs, and our Eagle Ford, Haynesville, Marcellus, and Woodford shale
82
programs utilize or contemplate the utilization of hydraulic fracturing. Currently, regulation of hydraulic
fracturing is primarily conducted at the state level through permitting and other compliance requirements. If
adopted, the proposed amendment to the Safe Drinking Water Act could result in additional regulations and
permitting requirements at the federal level. Those additional regulations and permitting requirements, as well as
other regulatory developments at the state level, could lead to significant operational delays and increased
operating costs, and could make it more difficult to perform hydraulic fracturing.
Climate Change
Climate change has become the subject of an important public policy debate. While climate change
remains a complex issue, scientific research suggests that an increase in greenhouse gas emissions may pose a risk
to society and the environment. The oil and natural gas exploration and production industry is a source of certain
greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on the combustion of fossil
fuels or the venting of natural gas could have a significant impact on our future operations. We are actively
monitoring the following climate change related issues:
Impact of Legislation and Regulation. The commercial risk associated with the exploration and
production of fossil fuels lies in the uncertainty of government-imposed climate change legislation, including cap
and trade systems, and regulations that may affect us, our suppliers, and our customers. The cost of meeting these
requirements may have an adverse impact on our financial condition, results of operations and cash flows, and
could reduce the demand for the oil and natural gas that we produce. The U.S. Congress and several states are
considering adopting climate change legislation. However, the current state of development of many state and
federal climate change regulatory initiatives makes it difficult to predict with certainty the future impact on us,
including accurately estimating the related compliance costs that we may incur.
Impact of U.S. Participation in International Accords. The U.S. has participated in international
discussions to develop a treaty or other agreement to require reductions in greenhouse gas emissions after 2012,
and has indicated that it wishes to associate itself with the Copenhagen Accord, which includes a non-binding
commitment to reduce greenhouse gas emissions. While no specific new international climate change accord has
been adopted that would affect our current operating locations, the current state of development of many
initiatives makes it difficult to assess the timing or effect of any pending discussions of future accords or predict
with certainty the future costs that we may incur in order to comply with any applicable requirements from future
international treaties or regulations.
Indirect Consequences of Regulation or Business Trends. We believe that there are both risks and
opportunities arising from climate change issues. See Items 1 and 2. Business and Properties – Government
Regulations, and the following risk factors listed in Item 1A. Risk Factors –
• We are subject to operating and environmental risks and hazards that could result in substantial
losses.
• Our operations are subject to complex laws and regulations, including environmental regulations
that result in substantial costs and other risks.
• Possible legislation and regulations related to global warming and climate change could have an
adverse effect on our operations and the demand for oil and natural gas.
In terms of opportunities, the regulation of greenhouse gas emissions and the introduction of alternative
incentives, such as enhanced oil recovery, carbon sequestration and low carbon fuel standards, could benefit us in
a variety of ways. For example, although climate change legislation could reduce the overall demand for the oil
and natural gas that we produce, the relative demand for natural gas may increase since the burning of natural gas
produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if
renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants may
provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel
standards, natural gas may become a more attractive transportation fuel. More than 60% of our 2009 production
83
on an MCFE basis was natural gas. Market-based incentives for the capture and storage of carbon dioxide in
underground reservoirs, particularly in oil and natural gas reservoirs, could also benefit us through the potential to
obtain greenhouse gas emission allowances or offsets from or government incentives for the sequestration of
carbon dioxide.
Physical Impacts of Climate Change on our Costs and Operations. There has been public discussion that
climate change may be associated with extreme weather conditions such as more intense hurricanes,
thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Extreme weather conditions can
increase our costs, and damage resulting from extreme weather may not be fully insured. However, the extent to
which climate change may lead to increased storm or weather hazards affecting our operations is difficult to
identify at this time. See Item 1A. Risk Factors – We are subject to operating and environmental risks and
hazards that could result in substantial losses.
84
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.
85
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, 2009. 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, 2009.
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, 2010
/s/ A. WADE PURSELL
A. Wade Pursell
Executive Vice President and Chief Financial Officer
February 23, 2010
86
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, 2009, 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, 2009, 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, 2009, of the
Company and our report dated February 23, 2010, expressed an unqualified opinion on those financial statements
and included explanatory paragraphs regarding the Company’s adoption of new accounting standards.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 23, 2010
87
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 ―Structure of the Board of Directors,‖
―Proposal 1 - Election of Directors,‖ and ―Corporate Governance‖ in St. Mary’s definitive proxy statement for the
2010 annual meeting of stockholders to be filed within 120 days from December 31, 2009. 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 2010 annual
meeting of stockholders to be filed within 120 days from December 31, 2009.
ITEM 11.
EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the information provided under the
captions, ―Executive Compensation‖ and ―Director Compensation‖‖ in St. Mary’s definitive proxy statement for
the 2010 annual meeting of stockholders to be filed within 120 days from December 31, 2009.
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 2010 annual
meeting of stockholders to be filed within 120 days from December 31, 2009.
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,‖ and ―Corporate Governance,‖ in St. Mary’s definitive
proxy statement for the 2010 annual meeting of stockholders to be filed within 120 days from December 31,
2009.
88
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 2010 annual meeting of stockholders to be filed within 120 days from
December 31, 2009.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a) (2) Financial Statements and Financial Statement Schedules:
PART IV
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of 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 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)
Purchase and Sale Agreement dated December 17, 2009 and effective as of November 1, 2009,
between Legacy Reserves Operating LP and St. Mary Land and Exploration Company
Purchase and Sale Agreement dated January 7, 2010 and effective as of November 1, 2009, between
Sequel Energy Partners LP, Bakken Energy Partners, LLC, Three Forks Energy Partners, LLC and St.
Mary Land and Exploration Company
2.2
2.3
2.4
2.5*
2.6*
89
Exhibit
Number Description
3.1
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)
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 10.7 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 10.10 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 10.50 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)
3.2
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†
90
Exhibit
Number Description
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, 2002 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)
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)
10.16
10.19
10.17†
10.15†
10.18†
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.)
10.23
10.21
10.22
10.20
91
Exhibit
Number Description
10.24
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
10.27†
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)
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 10.1 to the registrant’s
Current Report on Form 8-K filed on May 4, 2006 and incorporated herein by reference)
10.28†
10.29†
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)
92
Exhibit
Number Description
10.39
Third Amended and Restated Credit Agreement dated April 14, 2009 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 Current Report on Form 8-K filed on
April 20, 2009, and incorporated herein by reference)
Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment,
Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank,
National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit
10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by
reference)
Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of
April 14, 2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20,
2009, and incorporated herein by reference)
Equity Incentive Compensation Plan as Amended and Restated as of March 26, 2009 (filed as Exhibit
10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2009)
St. Mary Land & Exploration Company Form of Performance Share and Restricted Stock Unit Award
Agreement (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter
ended June 30, 2009, and incorporated herein by reference)
St. Mary Land & Exploration Company Form of Performance Share and Restricted Stock Unit Award
Notice (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 2009, and incorporated herein by reference)
Third Amendment to St. Mary Land & Exploration Company Employee Stock Purchase Plan dated
September 23, 2009 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the
quarter ended September 30, 2009, and incorporated herein by reference)
10.40
10.41
10.42†
10.43†
10.44†
10.45†
10.46*† Fourth Amendment to St. Mary Land & Exploration Company Employee Stock Purchase Plan dated
December 29, 2009
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
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-
99.1*
Oxley Act of 2002
Ryder Scott Audit Letter
*
**
†
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.
93
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, 2009 and 2008, and the related consolidated statements of
operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the three years in
the period ended December 31, 2009. 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, 2009 and 2008, and the results of
their operations and their cash flows for each of the three years in the period ended December 31, 2009, in
conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of oil and gas
reserve estimation and related required disclosures in 2009 with the implementation of new accounting guidance.
As discussed in Note 5 to the consolidated financial statements, the Company changed its method of accounting
for convertible debt in 2009.
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, 2009, 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, 2010, expressed an unqualified
opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 23, 2010
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 $- in 2009 and $16,788 in 2008
Refundable income taxes
Prepaid expenses and other
Derivative asset
Deferred income taxes
Total current assets
Property and equipment (successful efforts method), at cost:
Land
Proved oil and gas properties
Less - accumulated depletion, depreciation, and amortization
Unproved oil and gas properties, net of impairment allowance
of $66,570 in 2009 and $42,945 in 2008
Wells in progress
Materials inventory, at lower of cost or market
Oil and gas properties held for sale less accumulated depletion,
depreciation, and amortization
Other property and equipment, net of accumulated depreciation
of $14,550 in 2009 and $13,848 in 2008
Other noncurrent assets:
Derivative asset
Restricted cash subject to Section 1031 Exchange
Other noncurrent assets
Total other noncurrent assets
December 31,
2009
2008
(As adjusted, Note 5)
$
10,649
-
$
6,131
1,002
116,136
32,773
14,259
30,295
4,934
209,046
1,371
2,797,341
(1,053,518)
132,370
65,771
24,467
145,392
14,404
2,127,598
8,251
-
16,041
24,292
157,690
13,161
22,161
111,649
-
311,794
1,350
2,969,722
(947,207)
168,817
90,910
40,455
1,827
13,458
2,339,332
21,541
14,398
10,182
46,121
Total Assets
Current liabilities:
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued expenses
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, net of unamortized
discount of $20,598 in 2009, and $28,787 in 2008
Asset retirement obligation
Asset retirement obligation associated with oil and gas properties held for sale
Net Profits Plan liability
Deferred income taxes
Derivative liability
Other noncurrent liabilities
Total noncurrent liabilities
Commitments and contingencies
Stockholders' equity:
Common stock, $0.01 par value: authorized - 200,000,000 shares;
issued: 62,899,122 shares in 2009 and 62,465,572 shares in 2008;
outstanding, net of treasury shares: 62,772,229 shares in 2009
and 62,288,585 shares in 2008
Additional paid-in capital
Treasury stock, at cost: 126,893 shares in 2009 and 176,987 shares in 2008
Retained earnings
Accumulated other comprehensive income (loss)
Total stockholders' equity
$
2,360,936
$
2,697,247
$
236,242
53,929
6,500
-
296,671
$
254,811
501
-
41,289
296,601
188,000
266,902
60,289
18,126
170,291
308,189
65,499
13,399
1,090,695
629
160,516
(1,204)
851,583
(37,954)
973,570
300,000
258,713
108,755
238
177,366
354,328
27,419
11,318
1,238,137
625
141,283
(1,892)
957,200
65,293
1,162,509
Total Liabilities and Stockholders' Equity
$
2,360,936
$
2,697,247
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)
2009
For the Years
Ended December 31,
2008
2007
(As adjusted, Note 5)
$
615,953
140,648
58,459
11,444
5,697
832,201
$
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
Operating revenues and other income:
Oil and gas production revenue
Realized oil and gas hedge gain (loss)
Marketed gas system revenue
Gain (loss) on divestiture activity (Note 3)
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 materials inventory
Impairment of goodwill
General and administrative
Bad debt expense (recovery)
Change in Net Profits Plan liability
Marketed gas system expense
Unrealized derivative (gain) loss
Other expense
Total operating expenses
206,800
304,201
62,235
174,813
45,447
14,223
-
76,036
(5,189)
(7,075)
57,587
20,469
13,489
963,036
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
218,208
227,596
58,686
-
4,756
-
-
60,149
-
50,823
42,485
5,458
2,522
670,683
319,411
746
(24,046)
296,111
(109,013)
Income (loss) from operations
(130,835)
171,201
Nonoperating income (expense):
Interest income
Interest expense
Income (loss) before income taxes
Income tax benefit (expense)
227
(28,856)
(159,464)
60,094
485
(26,950)
144,736
(57,388)
Net income (loss)
$
(99,370)
$
87,348
$
187,098
Basic weighted-average common shares outstanding
Diluted weighted-average common shares outstanding
62,457
62,457
62,243
63,133
61,852
64,850
Basic net income (loss) per common share
$
(1.59)
$
1.40
$
3.02
Diluted net income (loss) per common share
$
(1.59)
$
1.38
$
2.90
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 (LOSS)
(In thousands, except share amounts)
Balances, December 31, 2006
Comprehensive income, net of tax:
Net income (As adjusted, Note 5)
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
3.50% Senior Convertible Notes conversion feature
Stock-based compensation expense
Common Stock
Shares
55,251,733
Amount
$
553
Additional
Paid-in
Capital
Treasury Stock
Shares
Amount
Retained
Earnings
$
38,940
(250,000)
$
(4,272)
$
695,224
Accumulated
Other
Comprehensive
Income (Loss)
$
12,929
Total
Stockholders'
Equity
$
743,374
-
-
-
-
-
-
29,534
-
-
-
-
-
-
-
-
-
-
-
-
-
919
7,692,295
77
106,854
302,370
733,650
-
1,250
3
7
-
-
(4,569)
19,011
41,843
8,915
-
-
-
-
-
-
-
-
-
(792,216)
-
(25,957)
187,098
-
-
-
(6,284)
-
-
-
-
-
-
-
-
-
32,504
-
-
1,180
-
-
-
-
-
-
-
(154,497)
(15,470)
70
-
-
-
-
-
-
-
-
187,098
(154,497)
(15,470)
70
17,201
(6,284)
(25,957)
919
106,931
(4,566)
19,018
41,843
10,095
Balances, December 31, 2007 (As adjusted, Note 5)
64,010,832
$
640
$
211,913
(1,009,712)
$
(29,049)
$
876,038
$
(156,968)
$
902,574
Comprehensive income, net of tax:
Net income (As adjusted, Note 5)
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
87,348
-
-
-
(6,186)
-
-
-
-
-
-
-
177,005
46,463
(1,207)
-
-
-
-
-
-
-
87,348
177,005
46,463
(1,207)
309,609
(6,186)
(77,150)
-
1,055
(6,905)
24,700
14,812
Balances, December 31, 2008 (As adjusted, Note 5)
62,465,572
$
625
$
141,283
(176,987)
$
(1,892)
$
957,200
$
65,293
$
1,162,509
Comprehensive loss, net of tax:
Net loss
Change in derivative instrument fair value
Reclassification to earnings
Minimum pension liability adjustment
Total comprehensive loss
Cash dividends, $ 0.10 per share
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,
including income tax cost of RSUs
Sale of common stock, including income
tax benefit of stock option exercises
Stock-based compensation expense
-
-
-
-
-
86,308
156,252
189,740
1,250
-
-
-
-
-
-
1
1
2
-
-
-
-
-
1,515
(1,951)
1,592
18,077
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
50,094
-
688
(99,370)
-
-
-
(6,247)
-
-
-
-
-
(35,977)
(67,344)
74
-
-
-
-
-
(99,370)
(35,977)
(67,344)
74
(202,617)
(6,247)
1,516
(1,950)
1,594
18,765
Balances, December 31, 2009
62,899,122
$
629
$
160,516
(126,893)
$
(1,204)
$
851,583
$
(37,954)
$
973,570
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:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
(Gain) loss on divestiture activities
Depletion, depreciation, amortization,
and asset retirement obligation liability accretion
Exploratory dry hole expense
Impairment of proved properties
Abandonment and impairment of unproved properties
Impairment of materials inventory
Impairment of goodwill
Stock-based compensation expense*
Bad debt expense (recovery)
Change in Net Profits Plan liability
Unrealized derivative (gain) loss
Loss related to hurricanes
(Gain) loss on insurance settlement
Amortization of debt discount and deferred financing costs
Deferred income taxes
Plugging and abandonment
Other
Changes in current assets and liabilities:
Accounts receivable
Refundable income taxes
Prepaid expenses and other
Accounts payable and accrued expenses
Excess income tax benefit associated with stock awards
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
Receipts from restricted cash
Deposits to restricted cash
Receipts from short-term investments
Deposits to short-term investments
Other
Net cash used in investing activities
Cash flows from financing activities:
Proceeds from credit facility
Repayment of credit facility
Repayment of short-term note payable
Debt issuance costs related to credit facility
Excess income tax benefit associated with stock awards
Proceeds from issuance of senior convertible debt, net of
deferred financing cost
Proceeds from sale of common stock
Repurchase of common stock
Dividends paid
Other
Net cash (used in) provided by financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
2009
For the Years Ended December 31,
2008
2007
(As adjusted, Note 5)
$
(99,370)
$
87,348
$
187,098
(11,444)
304,201
7,810
174,813
45,447
14,223
-
18,765
(5,189)
(7,075)
20,469
8,301
-
12,213
(39,735)
(26,396)
3,382
46,743
(19,612)
(6,626)
(4,814)
-
436,106
16,789
39,898
(379,253)
(76)
14,398
-
1,002
-
3,150
(304,092)
2,072,500
(2,184,500)
-
(11,074)
-
-
3,110
-
(6,247)
(1,285)
(127,496)
(63,557)
314,330
6,823
302,230
39,049
-
9,452
14,812
16,735
(34,040)
(11,209)
6,980
2,296
9,344
38,164
(9,168)
3,875
(14,327)
(12,228)
(1,504)
(12,348)
(13,867)
679,190
-
178,867
(746,586)
(81,823)
-
(14,398)
170
-
(9,984)
(673,754)
2,571,500
(2,556,500)
-
-
13,867
-
11,888
(77,202)
(6,186)
(182)
(42,815)
367
227,596
14,365
-
4,756
-
-
10,095
-
50,823
5,458
-
(5,243)
5,413
91,418
(12,393)
1,896
(6,557)
6,751
19,375
40,769
(9,933)
632,054
5,948
495
(639,010)
(182,883)
-
-
1,450
(1,168)
10,034
(805,134)
822,000
(871,000)
(4,469)
-
9,933
280,657
10,007
(25,904)
(6,284)
186
215,126
4,518
6,131
10,649
$
(37,379)
43,510
6,131
$
42,046
1,464
43,510
$
* Stock-based compensation expense is a component of exploration expense and general and administrative expense on
the consolidated statements of operations. For the years ended December 31, 2009, 2008, and 2007, respectively,
$6.3 million, $5.8 million, and $3.2 million of stock-based compensation expense was included in exploration expense.
For the years ended December 31, 2009, 2008, and 2007, respectively, $12.5 million, $9.0 million, and $6.9 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
$
17,884
$
21,976
$
22,816
Cash paid (refunded) for income taxes
$
(9,857)
$
17,326
$
(1,156)
2009
For the Years
Ended December 31
2008
(In thousands)
2007
In August 2009 and 2008, the Company granted 725,092 and 465,751 Performance Share Awards to
employees as equity-based compensation pursuant to the Company's Equity Incentive Compensation
Plan. The total fair value of the issuances equaled $25.8 million and $12.3 million, respectively.
The Company did not grant any Performance Share Awards in 2007.
For the years ended December 31, 2009, 2008, and 2007, the Company issued 241,745, 428,407, and 102,634
restricted stock units, respectively, to employees as equity-based compensation, pursuant to the
Company's Equity Incentive Compensation Plan. The total fair value of the issuances was $5.8 million, $23.4
million, and $3.3 million, respectively.
For the years ended December 31, 2009, 2008, and 2007, $109.0 million, $116.5 million, and $116.9 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, 2009, 2008, and 2007, the Company issued 50,094, 23,113, and 32,504
shares, respectively, of common stock from treasury to its non-employee directors pursuant to the
Company's Equity Incentive Compensation Plan. The Company recorded compensation expense related
to these issuances of approximately $688,000, $1,041,000, and $983,500 for the years ended December 31,
2009, 2008, and 2007, respectively.
For the years ended December 31, 2009, 2008 and 2007, the Company converted 215,700, 678,197, and 427,059
RSU's relating to awards granted in previous years. The Company and a majority of grant participants
mutually agreed to net share settle the awards to cover income and payroll tax withholding as provided
for in the plan documents and award agreements. As a result, the Company issued 156,252, 482,602, and
302,370 net shares of common stock associated with these grants for the years ended December 31, 2009, 2008,
and 2007, respectively. The remaining 59,448, 195,595, and 124,689, shares were withheld to satisfy income and
payroll tax withholding obligations that occurred upon the delivery of the shares underlying those RSU's.
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 vested
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 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.
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, 2009
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.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of the Company and its wholly-
owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the
United States and the instructions to Form 10-K and regulation S-X. Subsidiaries that are not wholly-owned are
accounted for using full consolidation by the equity or cost methods as appropriate. Equity method investments
are included in other noncurrent assets in the accompanying consolidated balance sheets. Intercompany accounts
and transactions have been eliminated. In connection with the preparation of the consolidated financial statements
of St. Mary and in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards
Codification (“ASC”) Topic 855, “Subsequent Events” (“ASC Topic 855”) the Company evaluated subsequent
events after the balance sheet date of December 31, 2009, through the filing of this report, February 23, 2010. For
additional information regarding ASC, please refer to the section titled Recently Issued Accounting Standards
within Note 1 – Summary of Significant Accounting Policies.
On January 1, 2009, the adoption of new authoritative accounting guidance under FASB ASC Topic 470,
“Debt” (“ASC Topic 470”) required retrospective application. As a result, prior period balances presented have
been adjusted to reflect the period-specific effects of applying ASC Topic 470. Please refer to Note 5 – Long-
term Debt for additional information regarding adoption.
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 proved oil and gas reserve quantities provide the basis for the
calculation of depletion, depreciation, and amortization (“DD&A”), impairment of proved properties, and the Net
Profits Interest Bonus Plan (“Net Profits Plan”) liability, each of which represents a significant component of the
accompanying consolidated financial statements.
Cash and Cash Equivalents
The Company considers all liquid investments purchased with an initial maturity of three months or less
to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-
term nature of these instruments.
Short-term Investments
As of December 31, 2008, the Company held $1.0 million of short-term investments, which 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, 2009, the Company held no short-term
investments.
F-7
Accounts Receivable and Concentration of Credit Risk
The Company’s accounts receivables consist mainly of receivables from oil and gas purchasers 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 and is
influenced by the general economic conditions of the industry. The Company records an allowance for doubtful
accounts on a case by case basis once there is evidence that collection is not probable. Receivables are not
collateralized. As of December 31, 2009, the Company had no allowance for doubtful accounts recorded. As of
December 31, 2008, the Company had $16.8 million recorded as allowance for doubtful accounts. For additional
discussion on allowance for doubtful accounts, please refer to 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, 2009, and 2008, the Company had
$2.3 million and $4.8 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 6 separate counterparties for its oil and gas commodity derivatives. The
counterparties to the Company’s derivative instruments are highly-rated entities with corporate credit ratings at or
exceeding BBB+ and Baa1 classifications by Standard & Poor’s and Moody’s, respectively. Ratings represent
minimum investment grade ratings.
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 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, 2009, and 2008, the Company’s capitalized proved oil and gas
properties included $77.8 million and $102.3 million, respectively, of estimated salvage value.
The Company follows guidance under FASB ASC Topic 932, “Extractive Activities – Oil and Gas”
(“ASC Topic 932”) when accounting for suspended well costs. For additional discussion, please see the heading
Suspended Well Costs in Note 15 –Oil and Gas Activities.
Impairment of Proved and Unproved Properties
Producing oil and gas property costs are evaluated for impairment and reduced to fair value, which is
expected future discounted cash flows, if the sum of expected undiscounted future cash flows is less than net book
value pursuant to FASB ASC Topic 360, “Property, Plant, and Equipment” (“ASC Topic 360”). 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 for the first five years, adjusted for basis
differentials. At the end of the first five years a flat terminal price is used. Future operating costs are also
F-8
adjusted as deemed appropriate for these estimates. An impairment write down is recorded 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, 2009, and 2008, the Company recorded proved property impairment
expense of $174.8 million and $302.2 million, respectively. The Company did not incur any proved property
impairment write-downs during 2007. In the first quarter of 2009, the Company incurred impairment on proved
properties of $97.3 million related to assets located in the Mid-Continent region due to a significant decrease in
the market price for natural gas and wider than normal differentials. In the fourth quarter of 2009, the Company
incurred impairment on proved properties of $20.4 million related to assets located in the ArkaLaTex region due
to decreased natural gas prices and engineering revisions. The Company incurred an additional impairment on
proved properties of $14.0 million during the year related to the write-down of certain assets located in the Gulf
of Mexico in which the Company is relinquishing its ownership interests in order to satisfy its abandonment
obligations. Approximately $154.0 million of the 2008 impairment write-down relates to the Olmos assets in
South Texas that were acquired as part of the 2007 Rockford and Catarina acquisitions. The remaining 2008
impairment came from proved properties in the Gulf of Mexico, the Greater Green River Basin in Wyoming, and
the Company’s Hanging Women Basin coalbed methane project.
For the years ended December 31, 2009, 2008, and 2007, the Company recorded expense related to the
abandonment and impairment of unproved properties of $45.4 million, $39.0 million, and $4.8 million,
respectively. The largest specific components of the 2009 impairment related to the Floyd Shale acreage located
in Mississippi and acreage in Oklahoma. The largest specific component of the 2008 impairment related to
acreage within the Olmos shallow gas formation in South Texas.
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 accompanying
consolidated statements 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.
Materials Inventory
The Company’s materials inventory is primarily comprised of tubular goods to be used in future drilling
or repair operations. Materials inventory is valued at the lower of cost or market and totaled $24.5 million and
$40.5 million at December 31, 2009, and 2008, respectively. The Company incurred net materials inventory
write-downs for year ended December 31, 2009, of $14.2 million as a result of the decrease in value of tubular
goods. There were no materials inventory write-downs for the years ended December 31, 2008, and 2007.
Assets Held for Sale
In accordance with ASC Topic 360, 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 in the consolidated balance sheets. For additional discussion on assets held for sale,
please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale.
F-9
Other Property and Equipment
Other property and equipment such as office furniture and equipment, buildings, and computer hardware
and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives
of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is
calculated using 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.
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
Petroleum, Inc. in January 2005. The Company conducted an impairment review annually or more frequently if
impairment indicators arose. The Company fully impaired its goodwill at December 31, 2008.
Restricted Cash
Proceeds from certain sales of oil and gas properties are held in escrow and restricted for future
acquisitions under tax-free exchange agreements. 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.
Intangible Assets
As of December 31, 2009, and 2008, the Company’s other noncurrent assets in the accompanying
consolidated balance sheets include $380,000 and $1.4 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. Intangible assets of the Company are amortized using the units-of-production method and are evaluated
for impairment if such indicators arise.
Cash Settlement Balancing
The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized
on all gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the
property. An asset or liability is recognized to the extent that there is an imbalance in excess of the remaining gas
reserves on the underlying properties. The Company’s gas imbalance position at December 31, 2009, and 2008,
respectively, resulted in the recording of $1.8 million to accounts receivable as of both dates and $1.2 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 qualify as and to be designated as cash flow hedges. 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 on derivatives, please see Note 10 – Derivative Financial Instruments.
F-10
Net Profits Plan
The Company records the estimated fair value of future payments under the Net Profits Plan as a
noncurrent liability in the accompanying consolidated balance sheets. 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 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 refer to the heading Net Profits Plan in Note 7 – Compensation Plans.
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. For additional discussion, please refer to Note 9 – Asset Retirement
Obligations.
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.
Major Customers
During 2009 the Company had one customer individually account for 12 percent of the Company’s total
oil and gas production revenue. During 2008 and 2007 no customer individually accounted for more than ten
percent of the Company’s total oil and gas production revenue.
F-11
Stock Based Compensation
At December 31, 2009, the Company had stock-based employee compensation plans that included RSUs,
PSAs, stock awards, 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 and were fully vested as of
December 31, 2008. The Company records expense associated with the fair value of stock-based compensation in
accordance with FASB ASC Topic 718, “Compensation – Stock Compensation” (“ASC 718”). The Company
used the modified-prospective method to record compensation expense associated with stock options that were
outstanding and unvested as of January 1, 2006. The Company records compensation expense associated with the
issuance of RSUs and PSAs based on the estimated fair value of these grants as determined at the time of grant.
Income Taxes
The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are
recognized based on the tax effects of temporary differences between the carrying amount on the financial
statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These
differences will result in taxable income or deductions in future years when the reported amount of the asset or
liabilities are recorded or settled, respectively. When appropriate the Company records 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 weighted-
average basic common shares outstanding include vested RSUs. 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, contingent 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, 3.50% Senior
Convertible Notes, and PSAs. In accordance with FASB ASC Topic 260, “Earnings Per Share,” when there is a
loss from continuing operations, all potentially dilutive shares will be anti-dilutive. As such, there were no
dilutive shares for the year ended December 31, 2009. 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,
2008
2009
2007
Dilutive
Anti-dilutive
-
1,152,127
890,189
330,231
1,441,556
-
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 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, 2009, 2008, and 2007.
F-12
On August 1, 2009, and 2008, the Company granted 725,092 and 465,751 PSAs, respectively, for the
three-year performance periods ending June 30, 2012, and 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 based on the Company’s absolute stock price
performance and a comparison of the Company’s stock price performance to an index 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. Based on the Company’s cumulative total
shareholder return (“TSR”) and the relative measure of the Company’s TSR compared with the cumulative TSR
of the index of its peers, there would have been potentially dilutive shares related to PSAs as of
December 31, 2009. However, no dilutive shares related to PSAs were included in the diluted earnings per share
calculation for the year ended December 31, 2009, because the Company recorded a loss for the period. There
were no potentially dilutive shares related to PSAs included in the diluted earnings per share calculation for the
years ended December 31, 2008, and 2007. For additional discussion on PSAs, please see the heading
Performance Share Awards Under the Equity Incentive Compensation Plan in Note 7 – Compensation Plans.
The following table sets forth the calculations of basic and diluted earnings per share.
Net income (loss)
$
(99,370)
$
87,348
$
187,098
2009
For the Years Ended December 31,
2007
2008
(In thousands, except per share amounts)
Adjustments to net income (loss) 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 (loss) adjusted for the effect of dilution
$
Basic weighted-average common shares outstanding
Add: dilutive effect of stock options, unvested
RSUs, and PSAs
Add: dilutive effect of 5.75% Senior Convertible
Notes using the if-converted method
Add: dilutive effect of 3.50% Senior Convertible
Notes
Diluted weighted-average common shares outstanding
Basic net income (loss) per common share
Diluted net income (loss) per common share
Comprehensive Income
$
-
-
-
(99,370)
62,457
-
-
$
-
-
-
87,348
62,243
890
-
-
63,133
1,285
(13)
(469)
187,901
61,852
1,441
1,557
-
64,850
3.02
2.90
-
62,457
(1.59)
(1.59)
$
$
$
$
1.40
$
1.38
$
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 minimum pension liability adjustment that was
recognized as a component of net periodic benefit cost. Comprehensive income is presented net of income taxes
in the accompanying consolidated statements of stockholders’ equity and comprehensive income (loss).
F-13
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, 2007
Before tax income (loss)
Tax benefit (expense)
After deferred tax income (loss)
$ (272,655)
102,688
$ (169,967)
$
$
119
(49)
70
$
$
(272,536)
102,639
(169,897)
For the year ended December 31, 2008
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
For the year ended December 31, 2009
Before tax income (loss)
Tax benefit (expense)
After deferred tax income (loss)
$ (165,684)
62,363
$ (103,321)
$
$
119
(45)
74
$
$
(165, 565)
62,318
(103,247)
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 $188.0 million and $300.0 million in loans outstanding under its revolving
credit agreement as of December 31, 2009, and 2008, respectively. 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 recorded at fair value and
changes in fair value run through accumulated other comprehensive income in the accompanying consolidated
balance sheets to the extent they are effective. Considerable judgment is required to develop estimates of fair
value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the
sale or refinancing of such instruments.
Industry Segment and Geographic Information
The Company operates exclusively in the exploration and production segment. All of the Company’s
operations are conducted in the continental United States. The Company 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 discretely in the accompanying consolidated statements of operations.
F-14
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, 2009, 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.
Recently Issued Accounting Standards
New authoritative accounting guidance under FASB ASC Topic 105, “Generally Accepted Accounting
Principles” (“ASC Topic 105”) established the FASB Accounting Standards Codification as the source of
authoritative U.S. GAAP recognized by the FASB to be applied to nongovernmental entities. ASC Topic 105
also states that rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under federal
securities laws are also sources of authoritative GAAP for SEC registrants. ASC Topic 105 supersedes existing
FASB, American Institute of Certified Public Accountants, Emerging Issues Task Force, and related literature.
All other accounting literature is considered non-authoritative. ASC Topic 105 changes the way the Company
cites authoritative guidance within the Company’s financial statements and accounting policies. The new
authoritative guidance under ASC Topic 105 became effective for periods ending on or after September 15, 2009,
and did not have a material impact on the Company’s consolidated financial statements.
New authoritative accounting guidance under FASB ASC Topic 805, “Business Combinations” (“ASC
Topic 805”) 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. ASC Topic 805 changes the way the Company accounts for acquisitions of proved oil and gas
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 fair value changes between the effective and
closing dates of acquisitions, and will require possible recognition of goodwill given differences between the
purchase price and fair value of acquired assets. ASC Topic 805 further amends the initial recognition and
measurement, subsequent measurement and accounting, and disclosures of assets and liabilities arising from
contingencies in a business combination. The new authoritative guidance under ASC Topic 805 became effective
for the Company on January 1, 2009, and the impact on the Company’s consolidated financial statements will
largely be dependent on the size and nature of the business combinations completed. The Company has not made
any significant acquisitions of oil and gas properties since adoption.
New authoritative accounting guidance under FASB ASC Topic 810, “Consolidation”
(“ASC Topic 810”) established accounting and reporting standards that require non-controlling interests to be
reported as a component of equity along with any changes in the parent’s ownership interest. The new
authoritative guidance under ASC Topic 810 became effective for the Company on January 1, 2009, and did not
have a material impact on the Company’s consolidated financial statements.
New authoritative accounting guidance under FASB ASC Topic 825, “Financial Instruments” (“ASC
Topic 825”) requires the Company to include disclosures about the fair value of its financial instruments
whenever it issues financial information for interim reporting periods and annual reporting periods, whether
recognized or not recognized in the consolidated balance sheets. The new authoritative guidance under ASC
Topic 825 became effective for the Company on April 1, 2009, and did not have a material impact on the
Company’s consolidated financial statements.
F-15
New authoritative accounting guidance under ASC Topic 855 established general standards of accounting
for and disclosures of events that occur after the balance sheet date but before financial statements are issued or
are available to be issued. ASC Topic 855 requires companies to disclose the date through which the Company
evaluated subsequent events, the basis for that date, and whether that date represents the date the financial
statements were issued. The new authoritative guidance under ASC Topic 855 became effective for the Company
on April 1, 2009, and did not have a material impact on the Company’s consolidated financial statements.
In December 2008 the 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 was developed by several petroleum industry
organizations and is a widely accepted standard for the management of petroleum resources. Key revisions
include a requirement to use 12-month average pricing determined by averaging the first of the month prices for
the preceding 12 months rather than year-end pricing for estimating proved reserves, the ability to include
nontraditional resources in reserves, the ability to use new technology for determining proved reserves, and
permitting disclosure of probable and possible reserves. The Company adopted these new rules and
interpretations as of December 31, 2009.
The FASB aligned ASC Topic 932, with all of the aforementioned SEC requirements by issuing ASC
Update 2010-03. The new authoritative guidance became effective for the Company’s 2009 Annual Report on
Form 10-K and has been fully adopted by the Company as of December 31, 2009.
In January 2010 the FASB issued ASC Update 2010-06, “Fair Value Measurements and Disclosures”
(“ASC Update 2010-06”) that requires additional disclosures surrounding transfers in and out of Levels 1 and 2,
inputs and valuation techniques used to value Level 2 and 3 measurements, and push down of previously
prescribed fair value disclosures to each class of asset and liability for Levels 1, 2, and 3. This new authoritative
guidance is effective for interim and annual reporting periods beginning after December 15, 2009. The Company
will apply the new authoritative guidance in the Company’s March 31, 2010, Quarterly Report on Form 10-Q.
ASC Update 2010-06 also requires that purchases, sales, issuances, and settlements for Level 3 measurements be
disclosed. This portion of the new authoritative guidance is effective for interim and annual reporting periods
beginning after December 15, 2010. The Company will apply this new authoritative guidance in the Company’s
March 31, 2011, Quarterly Report on Form 10-Q. The adoption of ASC Update 2010-06 will not have a material
impact on the Company’s financial statements.
Please refer to Note 5 – Long-term Debt, Note 8 – Pension Benefits, Note 10 - Derivative Financial
Instruments, Note 11 – Fair Value Measurements, and Note 16 – Disclosures about Oil and Gas Producing
Activities for additional information on the recent adoption of new authoritative accounting guidance.
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
State severance tax refunds
Other
Total accounts receivable
As of December 31,
2009
2008
(In thousands)
$ 80,085
29,719
253
4,638
1,441
$ 116,136
$ 84,583
56,493
8,829
5,049
2,736
$ 157,690
F-16
Accounts payable and accrued expenses are comprised of the following:
As of December 31,
2009
2008
(In thousands)
Accrued drilling costs
Revenue and severance tax payable
Accrued lease operating expense
Accrued property taxes
Accrued interest
Accrued compensation
Trade payables
Plug and abandonment liability
Accrued marketed gas system expense
Settled hedge payable
Other
$ 100,960
33,370
13,760
4,747
3,198
23,607
11,633
23,665
8,313
1,637
11,352
Total accounts payable and accrued expenses
$ 236,242
Note 3 – Acquisitions, Divestitures, and Assets Held for Sale
Hanging Woman Basin Divestiture
$ 111,397
42,520
20,328
4,889
2,794
18,613
25,629
7,281
8,892
-
12,468
$ 254,811
In December 2009 the Company completed the divestiture of certain non-strategic coalbed methane
properties located in the Hanging Woman Basin in the Rocky Mountain region. The cash received at closing,
including a $2.0 million deposit, net of commission costs, was $23.3 million. The final sales price is subject to
normal post-closing adjustments and is expected to be finalized during the second quarter of 2010. The estimated
gain on sale related to the divestiture is approximately $12.9 million and may be impacted by the previously
mentioned post-closing adjustments. The Company determined that this sale did not qualify for discontinued
operations accounting under FASB ASC Topic 205, “Presentation of Financial Statements” (“ASC Topic 205”).
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 as the second step of a reverse 1031 exchange. The
cash received at closing, net of commission costs, was $21.9 million. The final sales price is subject to normal
post-closing adjustments and is expected to be finalized during 2010. The estimated gain on sale related to the
divestiture is approximately $900,000, net of commission costs and Net Profit Plan payments, and may be
impacted by the previously mentioned post-closing adjustments. The Company determined that this sale did not
qualify for discontinued operations accounting under ASC Topic 205.
Abraxas Divestiture
In January 2008 the Company completed the divestiture of certain non-strategic oil and gas properties as
the second step of a reverse 1031 exchange. The sold properties were located primarily in the Rocky Mountain
and Mid-Continent regions, and were sold to Abraxas Petroleum Corporation and Abraxas Operating, LLC. The
final sales price, net of commission costs, was $129.4 million. The final gain on sale related to the divestiture was
approximately $53.4 million, net of commission costs and Net Profit Plan payments. The Company determined
that this sale did not qualify for discontinued operations accounting under ASC Topic 205.
F-17
Carthage Acquisition
In March 2008, the Company acquired oil and gas properties as the first step of a reverse 1031 exchange.
These properties are located primarily in the Carthage Field in Panola County, Texas and were purchased 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.
Assets Held for Sale
In accordance with ASC Topic 360, assets are classified as held for sale when the Company commits to a
plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon
classification as held for sale, long-lived assets are no longer depreciated or depleted and a measurement for
impairment is performed to expense any excess of carrying value over fair value less costs to sell. Subsequent
changes to estimated fair value less the cost to sell will impact the measurement of assets held for sale for assets
for which fair value is determined to be less than the carrying value of the assets.
As of December 31, 2009, the accompanying consolidated balance sheets includes $145.4 million in book
value of assets held for sale, net of accumulated depletion, depreciation, and amortization. The corresponding asset
retirement obligation liability of $18.1 million is also separately presented. The above assets held for sale and asset
retirement obligation liability amounts include certain non-core properties located primarily in the Rocky Mountain
region that the Company began marketing in the third quarter of 2009, as well as a new package of properties
located in our South Texas and Gulf Coast region. The Company determined that these sales do not qualify for
discontinued operations accounting under ASC Topic 205.
In December 2009, St Mary reached an agreement for the partial sale of its previously announced
divestiture package, of certain non-strategic oil and gas properties located in the Rocky Mountain region to
Legacy Reserves Operating LP. The transaction has an effective date of November 1, 2009. Subsequent to year
end, on February 17, 2010, the Company completed this divestiture. Total cash received, before commission
costs, was $125.2 million, of which $6.5 million was received as a deposit in December 2009 and is separately
presented on the accompanying consolidated balance sheets. The cash received is subject to normal post-closing
adjustments and settlements.
Subsequent to year end, St Mary reached an agreement for the sale of the North Dakota portion of its
previously announced divestiture package of certain non-strategic oil and gas properties located in the Rocky
Mountain region to Sequel Energy Partners L.P. for $137.0 million in cash, subject to normal closing and post-
closing adjustments. The agreement has an effective date of November 1, 2009, and is anticipated to close in
March 2010, subject to customary closing conditions.
In the third quarter of 2009, St. Mary reclassified a portion of the assets previously classified as held for sale
to assets held and used, as these assets were no longer being actively marketed. In accordance with ASC Topic 360,
the Company must measure the assets at the lower of the assets carrying amount before the assets were classified as
held for sale, adjusted for any depreciation and depletion expense that would have been recognized had the assets
been continuously classified as held and used, or the assets fair value at the subsequent date that the decision not
to actively market the assets was determined. As a result of this measurement the Company recognized a
$9.8 million loss on unsuccessful sale of properties, which is included in gain (loss) on divestiture activity in the
accompanying consolidated statements of operations.
F-18
Note 4 – Income Taxes
The provision for income taxes consists of the following:
Current income tax (benefit)
Federal
State
Deferred income tax expense (benefit)
Total income tax expense (benefit)
Effective tax rates
For the Years Ended December 31,
2009
2008
2007
(In thousands)
$ (21,926)
1,567
(39,735)
$ (60,094)
37.7%
$ 17,863
1,361
38,164
$ 57,388
39.7%
$ 15,136
2,459
91,418
$ 109,013
36.8%
As a result of the exercise of stock options, the Company reduced its income tax payable in 2008 and
2007. The excess income tax benefit to the Company associated with stock awards was $13.9 million in 2008 and
$9.9 million in 2007. There was no income tax benefit associated with stock awards in 2009.
The components of the net deferred tax liabilities 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
State tax net operating loss carryforward or carryback
Stock compensation
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,
2009
2008
(In thousands)
$
$
$
$
419,585
-
1,937
1,378
422,900
63,902
21,107
10,915
9,647
17,277
122,848
(3,203)
119,645
303,255
(1,366)
6,300
308,189
32,773
(168)
$
$
$
$
433,536
42,407
2,450
3,635
482,028
66,800
1,072
7,215
7,291
7,179
89,557
(3,146)
86,411
395,617
(42,766)
1,477
354,328
13,136
25
At December 31, 2009, the Company had estimated state net operating loss carryforwards of
approximately $259 million expiring between 2010 and 2019. The Company has a federal AMT credit carry
forward of $2.1 million which will not expire, and other state tax credits of $285,000 which expire between 2010
and 2029. The majority of the Company’s valuation allowance relates to state net operating loss carryforwards,
F-19
state tax credits, and state and federal income tax benefit amounts which the Company anticipates will expire
before they can be utilized. Permanent items included in the calculation of income tax for certain states are
anticipated to impact the Company’s ability to deduct operating losses and realize federal income tax deduction
benefits in certain states and the Company has adjusted its valuation allowances accordingly. A small 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.
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, 2008 impairment of
goodwill, and other permanent differences, as follows:
Federal statutory tax (benefit)
Increase (decrease) in tax resulting from
For the Years Ended December 31,
2008
2009
(In thousands)
2007
$ (55,812)
$ 50,526
$103,555
State tax (benefit) (net of federal benefit)
Goodwill
Change in valuation allowance
Statutory depletion
Domestic production activities deduction
Other
Income tax expense (benefit) from operations
(5,141)
-
56
(189)
-
992
$ (60,094)
4,669
3,308
(409)
(294)
(275)
(137)
$ 57,388
5,111
-
896
(407)
(384)
242
$109,013
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 or dispositions 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 2006. The Internal Revenue Service initiated an audit of the Company’s
2005 tax year in 2008 and concluded the audit in the first quarter of 2009 with a refund to the Company of
$278,000 plus interest of $41,000. Related amended state income tax returns were filed in the second quarter of
2009. There was no change to the provision for income tax expense as a result of the examination. In the fourth
quarter of 2009 the Company received a refund of $5.0 million dollars related to its 2008 income tax return. At
December 31, 2009 the Company is awaiting a $5.5 million dollar refund related to filing an amended return for
its 2006 tax year reflecting a net operating loss carry back from the Company’s 2008 tax year. The Company’s
remaining receivable balance reflects its intention to carry back a net operating loss generated in 2009 to prior
years.
At December 31, 2008, the Company recognized an impairment of goodwill recorded as part of the Agate
Petroleum, Inc. acquisition in 2005. The tax benefit is not calculated upon the recognition of this expense. For
additional discussion please refer to the section titled Goodwill within Note 1 – Summary of Significant
Accounting Policies. This resulted in a 2.2 percent increase in the Company’s effective tax rate for the year ended
December 31, 2008. The Company received $1.0 million in the first quarter of 2008 for income tax refunds and
accrued interest resulting from a carry-over of minimum tax credits to its 2003 tax year.
F-20
The Company adopted the uncertainty provision of FASB ASC Topic 740, “Income Taxes” 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 an 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 2009 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, 2009, 2008, and 2007.
The total amount recorded for unrecognized tax benefits is presented below:
For the Years Ended December 31,
2009
2008
2007
Beginning balance
Additions for tax positions of prior years
Reductions for lapse of statute of limitations
$
994
231
(341)
$
(In thousands)
957
173
(136)
Ending balance
$
884
$
994
$ 1,112
233
(388)
$
957
Note 5 – Long-term Debt
Revolving Credit Facility
The Company executed a Third Amended and Restated Credit Agreement on April 14, 2009. This
amended revolving credit facility replaced the previous facility. The Company incurred $11.1 million of deferred
financing costs in association with the amended credit facility. 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.
The credit facility specifies a maximum loan amount of $1.0 billion and has a maturity date of July 31, 2012. The
authorized borrowing base under the credit facility 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. On September 29, 2009, the lending group redetermined and maintained the
Company’s reserve-backed borrowing base under the credit facility at an amount of $900 million. The Company
has an aggregate commitment amount of $678 million under the credit facility. The Company must comply with
certain covenants under the terms of its 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 as of December 31, 2009, and through the date of this filing. Interest and commitment fees are
accrued based on the borrowing base utilization grid below. Eurodollar loans accrue interest at the London
Interbank Offered Rate (“LIBOR”) plus the applicable margin from the utilization table, and Alternative Base
Rate (“ABR”) and swingline loans accrue interest at Prime plus the applicable margin from the utilization table.
Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in
interest expense in the accompanying consolidated statements of operations.
Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage
Eurodollar Loans
ABR Loans or Swingline Loans
Commitment Fee Rate
<25%
2.000%
1.000%
0.500%
25% <50%
2.250%
1.250%
0.500%
50% <75%
2.500%
1.500%
0.500%
75%
2.750%
1.750%
0.500%
F-21
The Company had $211.0 million, $188.0 million, and $300.0 million in outstanding loans under its
revolving credit agreement on February 16, 2010, December 31, 2009, and 2008, respectively. The Company had
$467.0 million, $489.4 million, and $200.0 million of available borrowing capacity under this facility as of
February 16, 2010, December 31, 2009, and 2008, respectively. The Company had a single letter of credit
outstanding in the amount of $569,000 as of December 31, 2009. This letter of credit reduced the amount
available under the commitment amount on a dollar-for-dollar basis. There was no letter of credit outstanding as
of February 16, 2010.
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 and 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. As of
December 31, 2009, the notes and underlying shares had been registered under a shelf registration statement.
Subsequent to year end the Company deregistered the shelf registration statement for the 3.50% Senior
Convertible Notes. 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.
F-22
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.
New authoritative accounting guidance under FASB ASC Topic 470
Effective January 1, 2009, the new authoritative accounting guidance under ASC Topic 470 required
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 debt in a manner that reflects the entity’s nonconvertible debt
borrowing rate when interest cost is recognized in subsequent periods. ASC Topic 470 applies to the Company’s
3.50% Senior Convertible Notes. Under the adoption provisions of ASC Topic 470, the Company retrospectively
applied its provisions and restated the Company’s consolidated financial statements for prior periods.
Under the provisions of ASC Topic 470, $42.0 million of the carrying value of the 3.50% Senior
Convertible Notes was recorded as additional paid-in capital as of the April 4, 2007, issuance date. This amount
represents the equity component of the proceeds from the 3.50% Senior Convertible Notes, calculated assuming a
7.0% discount rate, which is the estimate of what the Company’s borrowing rate for a similar debt instrument
without the conversion feature would have been at the date of the issuance of the 3.50% Senior Convertible
Notes. Upon retrospective application, the adoption resulted in a $6.8 million decrease in the Company’s retained
earnings at December 31, 2008, which was comprised of non-cash interest expense of $10.8 million, net of
capitalized interest of $2.2 million, less deferred taxes of $4.0 million, for the period from April 4, 2007, through
December 31, 2008. The following table presents the December 31, 2008, consolidated balance sheet line items
as adjusted and as originally reported:
Proved oil and gas properties
Senior Convertible Notes
Noncurrent deferred income taxes
Additional paid-in capital
Retained earnings
As of December 31, 2008
As Adjusted
As Originally
Reported
(In thousands)
$ 2,969,722
258,713
354,328
141,283
957,200
$ 2,967,491
287,500
358,334
99,440
964,019
F-23
As of December 31, 2009, and 2008, the carrying value of the equity component was $42.0 million. The
principal amount of the 3.50% Senior Convertible Notes, the unamortized debt discount, and the net carrying
amounts were as follows:
Senior Convertible Notes
Unamortized debt discount
Net carrying amount of the 3.50%
Senior Convertible Notes
As of
December 31, 2009
As of
December 31, 2008
(As Adjusted)
(In thousands)
$
287,500
(20,598)
$ 287,500
(28,787)
$
266,902
$ 258,713
The Company amortized $8.2 million, $7.6 million, and $5.4 million of the debt discount for the
years ended December 31, 2009, 2008, and 2007, respectively. Accumulated amortization related to the
debt discount was $21.2 million and $13.0 million for the years ended December 31, 2009, and 2008,
respectively. The remaining unamortized debt discount will be amortized through March 2012 using the
interest method.
The consolidated statements of operations were retrospectively adjusted compared to previously reported
amounts as follows:
For the Year Ended
December 31, 2008
For the Year Ended
December 31, 2007
As Adjusted
As Originally
Reported
As Originally
As Adjusted
Reported
(In thousands, except per share amounts)
Interest expense
Income tax expense
Net income
Basic net income per
common share
Diluted net income per
common share
$
$
$
26,950
57,388
87,348
1.40
1.38
$
$
$
20,275
59,858
91,553
1.47
1.45
$
$
$
24,046
109,013
187,098
3.02
2.90
$
$
$
19,895
110,550
189,712
3.07
2.94
Weighted-Average Interest Rate Paid and Capitalized Interest
The weighted-average interest rate paid in 2009, 2008, and 2007, was 5.4 percent, 5.8 percent, and
6.7 percent, respectively, including commitment fees paid on the unused portion of the credit facility aggregate
commitment, amortization of deferred financing costs, amortization of debt discount, amortization of the
contingent interest embedded derivative associated with the 5.75% Senior Convertible Notes for 2007, and the
effect of interest rate swaps. The average outstanding loan balance in 2009 increased in comparison to the
average outstanding loan balance in 2008, while the rates associated with the balances decreased. The decrease is
attributed to significantly lower LIBOR and Prime rates in 2009 compared to 2008. Capitalized interest costs for
the Company for the years ended December 31, 2009, 2008, and 2007, were $1.9 million, $4.7 million, and
$6.7 million, respectively.
F-24
Note 6 – Commitments and Contingencies
The Company has entered into various operating leases, which include drilling rig contracts, of
approximately $20.5 million, office space leases including maintenance of approximately $34.5 million,
compressor contracts of approximately $2.7 million, and vehicle leases of approximately $2.3 million. The
annual minimum lease payments for the next five years and thereafter are presented below:
Years Ending December 31,
2010
2011
2012
2013
2014
Thereafter
Total
(In thousands)
$
$
27,779
6,438
3,249
2,973
2,367
18,275
61,081
The Company leases office space under various operating leases with terms extending as far as
May 31, 2022. Rent expense, net of sublease income, was $2.3 million, $2.4 million, and $1.9 million in 2009,
2008, and 2007, respectively. The Company also leases office equipment under various operating leases. As of
December 31, 2009, the Company has a sublease through May 2012 with payments due to St. Mary of $185,000
per year through 2011 and $62,000 in 2012. This sublease was terminated on January 15, 2010.
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 pending 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 based on a performance measurement framework whereby selected
eligible employee participants may be awarded an annual cash bonus. The plan document provides that no
participant may receive an annual bonus under the plan of more than 200 percent of his or her base salary. As the
plan is currently administered, any awards under the plan are based on Company and regional performance, and
are then further refined by individual performance. The Company accrues cash bonus expense based upon the
Company’s current year’s performance. Included in general and administrative and exploration expense in the
accompanying consolidated statements of operations are $7.8 million, $6.4 million, and $3.6 million of cash
bonus expense related to the specific performance year for the years ended December 31, 2009, 2008, and 2007,
respectively.
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
disclosure requirements for all equity awards still outstanding.
In May 2006 the stockholders approved the 2006 Equity Incentive Compensation Plan, which was
subsequently renamed the Equity Incentive Compensation Plan (the “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 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
F-25
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
pursuant to the 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 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 Equity Plan was approved by the Company’s stockholders at the 2008 annual stockholders’
meeting held on May 21, 2008. The Equity Plan was further amended at the 2009 annual stockholders’ meeting
held on May 20, 2009.
As of December 31, 2009, 1.8 million shares of common stock remained available for grant under the
Equity Plan. The issuance of a direct share benefit such as an outright grant of common stock, a grant of a
restricted share, a RSU grant, or a PSA grant, counts as 1.43 shares against the number of shares available to be
granted under the Equity Plan. At the end of a three-year performance period a final multiplier ranging between
zero and two is applied to each PSA 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 2.86 shares
against the number of shares available to be granted under the Equity Plan. Stock option grants count as one
share for each instrument granted against the number of shares available to be granted under the Equity Plan. The
Company has outstanding stock option awards under the Predecessor Plans.
Performance Share Awards Under the Equity Incentive Compensation Plan
In 2007, PSAs became the primary form of long-term equity incentive compensation replacing standalone
RSU grants and awards of interest in pools under the Net Profits Plan. PSAs represent the right to receive a share
of the Company’s common stock which can be multiplied by a factor ranging from zero to two times the number
of PSAs granted on the award date depending on the Company’s performance after completion of a three-year
performance period. The performance criteria for the PSAs are based on a combination of the Company’s
cumulative TSR for the performance period and the relative measure of the Company’s TSR compared with the
cumulative TSR of an index comprised of certain peer companies for the performance period.
On August 1, 2009, the Company granted 725,092 PSAs with a performance period ending
June 30, 2012. The PSAs will vest 1/7th on August 1, 2010, 2/7ths on August 1, 2011, and 4/7ths on
August 1, 2012. The fair value of the Company’s PSAs granted on August 1, 2009, was $25.8 million and is
being recognized as general and administrative and exploration expense over the vesting period of the award.
On August 1, 2008, the Company granted 465,751 PSAs with a performance period ending
June 30, 2011. The PSAs will vest 1/7th on August 1, 2009, 2/7ths on August 1, 2010, and 4/7ths on
August 1, 2011. The fair value of the Company’s PSAs granted on August 1, 2008, was $12.3 million and is
being recognized as general and administrative and exploration expense over the vesting period of the award.
In measuring compensation expense related to the grant of PSAs, the Company estimates the fair value of
the award on the grant date. The fair value of PSAs is measured by 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 prices of its
peers will take over the three-year performance period. By using a stochastic simulation the Company can create
multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences 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.
F-26
A summary of the status and activity of PSAs for the years ending December 31, 2009, and 2008, is
presented in the following table:
Non-vested at beginning of year
Granted
Vested(1)
Forfeited
PSAs
464,333
725,092
(76,781)
(43,554)
2009
2008
Weighted-
Average
Grant-Date
Fair Value
$
$
$
$
26.48
35.59
27.20
28.62
Weighted-
Average
Grant-Date
Fair Value
-
26.48
-
26.48
$
$
$
$
PSAs
-
465,751
-
(1,418)
Non-vested at end of year
(1) The number of shares vested represents 1/7th of the August 1, 2008, PSA grant assuming a one multiplier. The final number of shares
1,069,090
464,333
32.52
26.48
$
$
vested may vary depending on the ending three-year multiplier, which ranges from zero to two.
The total fair value of PSAs that vested during the year ended December 31, 2009, was $1.8 million.
General and administrative and exploration expense recorded for PSAs was $9.3 million and $2.5 million for the
years ended December 31, 2009, and 2008, respectively. As of December 31, 2009, there was $25.0 million of
total unrecognized expense related to PSAs, which is being amortized through 2012.
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 the same Company performance formula used to determine the annual cash bonus. RSUs were also
issued in 2008 as the Company transitioned to using PSAs as the primary long-term equity incentive
compensation awards and again in 2009 as a component of the Company’s long-term equity incentive
compensation program.
The Company issued 241,745 RSUs on August 1, 2009, with a weighted-average grant-date fair value of
$23.87 with a total fair value of $5.8 million. These RSUs vest 1/7th on August 1, 2010, 2/7ths on August 1, 2011,
and 4/7ths on August 1, 2012 and is being recognized as general and administrative and exploration expense over
the vesting period of the award.
St. Mary issued 265,373 RSUs on June 30, 2008, as a transitional award to employees when the Company
moved from the legacy equity incentive compensation plan to the new PSA program. The total fair value
associated with this issuance was $17.2 million as measured on the grant date. The granted RSUs vest one third
on each date of December 15th 2008, 2009, and 2010. General and administrative and exploration expense is
recorded over the vesting period of the award.
The Company issued 158,744 RSUs on February 28, 2008, related to 2007 performance, and 78,657
RSUs on February 28, 2007, related to 2006 performance. The total fair value associated with these issuances
was $6.0 million for the 2008 grant and $2.5 million for the 2007 issuance as measured on the respective grant
dates. These granted RSUs vested 25 percent immediately upon grant and 25 percent on each of the first three
anniversary dates of the grant. The fair values of these awards are being recognized as general and administrative
and exploration expense over the vesting period of the awards.
The Company issued an additional 4,290 and 23,977 RSUs to certain employees during 2008 and 2007,
respectively. The total fair value associated with the 2008 and 2007 issuances was $164,000 and $803,000,
respectively, as measured on the respective grant dates. These grants have various vesting schedules.
F-27
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. On December 31,
2007 the Company eliminated the restriction period that extends beyond the vesting period so shares are now
issued without restriction upon vesting, rather than on the third anniversary of the award for all awards granted
after 2005. Therefore the fair value of a RSU award granted after December 31, 2007, is equal to the market
value of the underlying stock on the date of the grant. This change fell within the safe harbor adoption provisions
of the 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. The majority of
the awards were modified by mutual election, and as such, the incremental value associated with removal of this
restriction period was $556,000 and is being amortized over the remaining respective service periods for these
awards.
For grants made beginning with the 2006 grant period, the Company is using the accelerated amortization
method whereby approximately 48 percent of the total estimated compensation expense is recognized in the first
year of the vesting period. As of December 31, 2009, a total of 408,356 RSUs were outstanding, of which 1,233
were vested. The total general and administrative and exploration expense associated with RSUs for the years
ended December 31, 2009, 2008, and 2007, was $7.9 million, $11.0 million, and $8.4 million, respectively. As of
December 31, 2009, there was $10.0 million of total unrecognized expense related to unvested RSU awards and is
being amortized through 2012.
During 2009, 2008, and 2007, the Company converted 215,700, 678,197, and 427,059 RSUs,
respectively. The Company and the majority of grant participants mutually agreed to net share settle the awards
to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a
result, the Company issued net shares of common stock of 156,252; 482,602; and 302,370 for 2009, 2008, and
2007, respectively. The remaining 59,448, 195,595, and 124,689 shares were withheld to satisfy income and
payroll tax withholding obligations that occurred upon the delivery of the shares underlying those RSUs for 2009,
2008, and 2007, respectively.
In accordance with ASC Topic 718, when measuring compensation expense related to the grant of RSUs
the Company estimates 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 with restriction
periods beyond the vesting dates were 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 prior to January 1, 2008, 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 Year Ended
December 31, 2007
4.5%
0.3%
32.0%
3
F-28
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 2009, 2008, and 2007, the Company issued
1,250, 3,750, and 1,250 worth of guaranteed and contingent shares with associated fair values of $45,000,
$142,000, and $45,000, respectively. The fair value of these awards is being 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 vested one half on December 15, 2009, and the other half will vest on
December 15, 2010. The fair value of this award was $600,005 and is being recorded as compensation expense
over the vesting period. For the years ended December 31, 2009, and 2008, the Company recorded general and
administrative and exploration expense of $358,000 and $115,000, respectively, related to this award.
A summary of the status and activity of non-vested stock awards and RSUs for the years ending
December 31, 2009, 2008, and 2007, is presented below:
2009
2008
2007
Stock
Awards
and RSUs
Weighted-
Average
Grant-Date
Fair Value
Stock
Awards
and RSUs
Weighted-
Average
Grant-Date
Fair Value
Stock
Awards
and RSUs
Weighted-
Average
Grant-Date
Fair Value
Non-vested at beginning
of year
Granted
Vested
Forfeited
402,297
241,745
(211,092)
(25,827)
$ 48.24
$ 23.87
$ 46.26
$ 50.35
289,385
443,903
(291,659)
(39,332)
$ 32.26
$ 53.81
$ 22.92
$ 37.82
506,161
102,634
(268,123)
(51,287)
$ 28.92
$ 32.45
$ 25.94
$ 31.77
Non-vested at end of
year
407,123
$ 34.67
402,297
$ 48.24
289,385
$ 32.26
The total fair value of RSUs that vested during the years ended December 31, 2009, 2008, and 2007, was
$4.9 million, $9.4 million, and $9.8 million, respectively.
ASC Topic 718 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 vested RSUs
and exercised options in excess of the deferred tax asset attributable to stock compensation costs for such RSUs
and options. The Company has recorded $13.9 million and $9.9 million of excess tax benefits for the years ended
December 31, 2008, and 2007, respectively, as cash inflows from financing activities. The Company recorded no
excess tax benefits for the year ended December 31, 2009. Cash received from exercises under all share-based
payment arrangements for the years ended December 31, 2009, 2008, and 2007, was $1.6 million, $10.8 million,
and $9.1 million, respectively.
F-29
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 granted 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. 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 years ended December 31, 2008, and 2007, the Company recognized general and
administrative and exploration expense of $17,000 and $437,000, respectively, related to stock options that were
outstanding and unvested upon adoption of ASC Topic 718 on January 1, 2006. There was no expense associated
with stock options or unvested stock options outstanding for the year ended December 31, 2009.
A summary of activity associated with the Company’s Stock Option Plans during the last three years is
presented in the following table:
Weighted -
Average
Shares
Exercise Price
Aggregate
Intrinsic
Value
For the year 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 year 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
For the year ended December 31, 2009
Outstanding, start of year
1,509,710
$
12.69
Granted
Exercised
Forfeited
Outstanding, end of year
-
(189,740)
(45,050)
1,274,920
-
8.40
13.38
13.31
$
$
$
$ 26,684,106
Vested, or expected to vest, end of year
1,274,920
$
13.31
$ 26,684,106
Exercisable, end of year
1,274,920
$
13.31
$ 26,684,106
F-30
A summary of additional information related to options outstanding as of December 31, 2009, follows:
Options Outstanding and Exercisable
Number
Of Options
Outstanding
and
Exercisable
Weighted-
Average
Remaining
Contractual
Life
192,230
176,035
13,080
143,378
204,202
30,593
126,839
188,531
141,400
58,632
1,274,920
2.0 years
2.6 years
2.4 years
3.0 years
3.5 years
3.8 years
3.5 years
4.0 years
1.0 years
5.0 years
Range of
Exercise Prices
$ 7.97
11.95
12.08
12.50
12.53
13.39
13.65
14.25
16.66
20.87
Total
- $ 10.86
- 12.03
- 12.08
- 12.50
- 12.66
- 13.39
- 13.65
- 14.25
- 16.66
- 20.87
Weighted-
Average
Exercise
Price
$ 10.05
11.99
12.08
12.50
12.58
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.
Director Shares
In 2009, 2008, and 2007, the Company issued 50,094, 23,113, and 32,504 shares, respectively, of
restricted common stock from treasury to its non-employee directors pursuant to the Company’s Equity Plan. The
Company recorded general and administrative and exploration expense related to the issuances of shares to non-
employee directors of $688,000, $1.0 million, and $984,000 for the years ended December 31, 2009, 2008, and
2007, respectively.
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 six-month offering period, and shares issued under the ESPP through
December 31, 2009, are restricted for a period of 18 months from the date issued. Effective January 1, 2010,
shares issued under the ESPP will be restricted for a six month period from the date issued. The ESPP is intended
to qualify under Section 423 of the IRC. The Company has set aside 2,000,000 shares of its common stock to be
available for issuance under the ESPP, of which 1,468,275 shares are available for issuance as of December 31,
2009. Shares issued under the ESPP totaled 86,308 in 2009, 45,228 in 2008, and 29,534 in 2007. Total proceeds
to the Company for the issuance of these shares was $1.5 million in 2009, $1.1 million in 2008, and $919,000 in
2007.
F-31
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 during the periods reported were estimated using the following
weighted-average assumptions:
Risk free interest rate
Dividend yield
Volatility factor of the expected market
price of the Company’s common stock
Expected life (in years)
For the Years Ended December 31,
2007
2008
2009
4.1%
1.2%
0.3%
0.3%
0.2%
0.5%
95.1%
0.5
81.5%
0.5
27.2%
0.5
The Company expensed $848,000, $307,000, and $260,000 for the years ended December 31, 2009,
2008, and 2007, respectively, based on the estimated fair value of grants on the respective grant dates.
401(k) Plan
The Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee
Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute up to 60
percent of their base salaries. 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 $2.5 million, $2.0 million, and $1.5 million for the years ended December 31, 2009, 2008,
and 2007, respectively. No discretionary contributions were made by the Company to the 401(k) Plan for any of
these years.
Net Profits Plan
Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during a
year were designated within a specific pool. Key employees recommended by senior management and designated
as participants by the 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. In December 2007 the Board discontinued the creation of new pools under the Net
Profits Plan. Consequently, the 2007 Net Profits Plan pool was the last pool established by the Company. All
pools are fully vested as of December 31, 2009.
Cash payments made under the Net Profits Plan that have been recorded as either general and
administrative expense or exploration expense are detailed in the table below:
General and administrative expense
Exploration expense
Total
For the Years Ended December 31,
2008
2009
2007
$
$
18,399
1,463
19,862
(In thousands)
$
$
29,713
6,604
36,317
$
$
25,030
6,881
31,911
F-32
Additionally, the Company made cash payments under the Net Profits Plan of $724,000 for the year ended
December 31, 2009, as a result of sales proceeds from properties sold during the fourth quarter of 2009. For the year
ended December 31, 2008, the Company made cash payments under the Net Profits Plan of $15.1 million as a result
of sales proceeds from the Abraxas and Greater Green River Basin divestitures. The cash payments are accounted
for as a reduction in the gain (loss) on divestiture activity in the accompanying consolidated statements of
operations. There were no significant cash payments made under the Net Profits Plan as the result of property
divestitures during 2007.
The Company records changes in the present value of estimated future payments under the Net Profits Plan
as a separate line item in the accompanying 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 made by the Company. 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 do not provide ongoing exploration support to the Company.
For the Years Ended December 31,
2008
2009
2007
General and administrative expense (benefit)
Exploration expense (benefit)
Total
$
$
(6,572)
(503)
(7,075)
Note 8 – Pension Benefits
New authoritative accounting guidance under FASB ASC Topic 715
(In thousands)
$
$
(29,672)
(4,368)
(34,040)
$
$
39,866
10,957
50,823
Effective January 1, 2009, new authoritative accounting guidance under FASB ASC Topic 715,
“Compensation – Retirement Benefits” (“ASC Topic 715”) amends the disclosure requirements of plan assets for
defined benefit pensions and other postretirement plans. The objective of ASC Topic 715 is to provide users of
financial statements with an understanding of how investment allocation decisions are made, the major categories
of plan assets held by the plans, the inputs and valuation techniques used to measure the fair value of plan assets,
significant concentration of risk within a company’s plan assets, fair value measurements determined using
significant unobservable inputs, and a reconciliation of changes between the beginning and ending balances for all
level 3 inputs.
Pension Plans
The Company has a non-contributory defined benefit pension plan covering substantially all employees
who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental
non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan”).
The Company recognizes the funded status (i.e., the difference between the fair value of plan assets and
the projected benefit obligation) of the Company’s pension plan in the consolidated balance sheets as either an
asset or a liability and recognizes a corresponding adjustment to accumulated other comprehensive income, net of
tax. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan
participants based on employee service and compensation including the effect of assumed future salary increases.
The accumulated benefit obligation uses the same factors as the projected benefit obligation but excludes the
F-33
effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is
December 31.
Obligations and Funded Status for Both Pension Plans
For the Years Ended December 31,
2009
2008
(In thousands)
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 at end of year
$
$
$
$
14,786
2,500
934
1,275
(945)
18,550
6,552
1,466
2,028
(945)
9,101
9,449
$ 14,744
2,229
889
(166)
(2,910)
$ 14,786
$
$
$
8,755
(1,782)
2,489
(2,910)
6,552
8,234
The Company’s underfunded status for the Pension Plans for the years ended December 31, 2009, and
2008, is $9.4 million and $8.2 million, respectively, and 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, 2009. 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
Projected benefit obligation
Accumulated benefit obligation
Less: Fair value of plan assets
Underfunded accumulated benefit obligation
As of December 31,
2009
2008
(In thousands)
$
$
$
18,550
13,278
9,101
4,177
$
$
$
14,786
9,922
6,552
3,370
Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of
benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets.
The expected long-term rate on plan assets is applied to a calculated value of plan assets that recognizes changes
in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension expense,
but it can have the effect of delaying recognition of differences between actual returns on assets and expected
returns based on long-term rate of return assumptions. Amortization of unrecognized net gain or loss resulting
from experience different from that assumed and from changes in assumptions (excluding asset gains and losses
not yet reflected in market-related value) is included as a component of net periodic benefit cost for a year. If, as
of the beginning of the year, that unrecognized net gain or loss exceeds 10 percent of the greater of the projected
F-34
benefit obligation and the market-related value of plan assets, the amortization is that excess divided by the
average remaining service period of participating employees expected to receive benefits under the plan.
Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated
other comprehensive income as of December 31, 2009, and 2008, consist of:
Unrecognized actuarial losses
Unrecognized prior service costs
Unrecognized transition obligation
Accumulated other comprehensive income
$
$
As of December 31,
2009
2008
(In thousands)
4,322
-
-
4,322
$
$
4,441
-
-
4,441
The estimated net loss that will be amortized from accumulated other comprehensive income into net
periodic benefit cost over the next fiscal year is $267,000.
Other pre-tax changes recognized in other comprehensive income during 2009, 2008, and 2007, were as
follows:
Net actuarial gain (loss)
Less: Amortization of:
Prior service cost
Actuarial gain (loss)
Total other comprehensive income
$
2009
As of December 31,
2008
(In thousands)
2007
$
(239)
$
(2,181)
$
(99)
-
(358)
119
-
(240)
(1,941)
$
-
(218)
119
$
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
$
2009
For the Year Ended December 31,
2008
(In thousands)
2007
$
2,500
934
$ 2,229
889
$
1,911
793
(430)
-
372
3,376
(565)
-
248
$ 2,801
(540)
-
218
2,382
$
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.
F-35
Pension Plan Assumptions
Weighted-average assumptions to measure the Company’s projected benefit obligation and net periodic
benefit cost are as follows:
Projected benefit obligation
Discount rate
Rate of compensation increase
Net periodic benefit cost
Discount rate
Expected return on plan assets
Rate of compensation increase
2009
6.1%
6.2%
6.6%
7.5%
6.2%
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 pension investment policy includes various guidelines and procedures designed to ensure
that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans.
The policy does not permit the direct investment of plan assets in the Company’s securities. The Company’s
investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term
perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The
key investment principles of diversification, assessment of risk, and targeting the optimal expected returns for
given levels of risk are applied.
The Company’s investment portfolio contains a diversified blend of common stocks and bonds, which
may reflect varying rates of return. The investments are further diversified within each asset classification. The
portfolio diversification provides protection against a single security or class of securities having a
disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and
rebalanced on a periodic basis to maintain the target allocations. The Company’s weighted-average asset
allocation for the Qualified Pension Plan is as follows:
Asset Category
Equity securities
Debt securities
Other
Total
Target
2010
60%
40%
-%
100.0%
2008
52.0%
As of December 31,
2009
61.3%
38.7%
-%
100.0%
48.0%
-%
100.0%
There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan.
An expected return on plan assets of 7.5 percent was used to calculate the Company’s obligation under the
Qualified Pension Plan for 2009 and 2008. 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-36
Fair Value Assumptions
The Company’s pension plan assets consist of funds that have quoted net asset values within active
markets. The individual funds are derived from quoted equity and debt securities within active markets with no
judgment involved. As such, the funds are deemed to be Level 1. The fair value of the Company’s pension plan
assets as of December 31, 2009, utilizing the fair value hierarchy discussed in Note 11- Fair Value Measurements
is as follows:
Assets:
Cash and Money Market Funds
Equity Securities
Foreign Large Blend (1)
U.S. Small Blend (2)
U.S Large Blend (3)
Fixed Income Securities
Intermediate Term Bond (4)
Level 1
$
4
Level 2
(In thousands)
-
$
$
Level 3
1,365
1,406
2,802
3,524
-
-
-
-
-
-
-
-
-
Total
(1) International equities are invested in companies that trade on active exchanges outside the U.S. and are well diversified among a dozen
9,101
$
$
$
-
-
or more developed markets. Active and passive strategies are employed.
(2) U.S. equities are invested in companies that are well diversified by industry sector and equity style, such as growth and value
strategies, that trade on active exchanges within the U.S. Active and passive management strategies are employed. At least 80% of
this fund is invested in equity securities of small companies.
(3) U.S. equities include companies that are well diversified by industry sector and equity style, such as growth and value strategies, that
trade on active exchanges within the U.S. Active and passive management strategies are employed. At least 80% of this fund is
invested in equity securities designed to replicate the holdings and weightings of the stocks listed in the S&P 500 index.
(4) Intermediate term bonds seek total return. At least 80% of this fund is invested in a diversified portfolio of bonds, which include all
types of securities. It invests primarily in bonds of corporate and governmental issues located in the U.S. and foreign countries,
including emerging markets all of which trade on active exchanges.
Contributions
The Company contributed $2.0 million, $2.5 million, and $2.2 million, to the Pension Plans in the years
ended December 31, 2009, 2008, and 2007, respectively. Under the Pension Protection Act of 2006, St. Mary is
not required to make a minimum contribution to the Pension Plans in 2010.
Benefit Payments
The Pension Plans made actual benefit payments of $945,000, $2.9 million, and $1.8 million in the years
ended December 31, 2009, 2008, and 2007, respectively. Expected benefit payments over the next ten years are
as follows (in thousands):
Years Ended December 31,
2010
2011
2012
2013
2014
2015 through 2019
$
610
1,286
1,305
2,381
2,840
$ 15,872
Note 9 – Asset Retirement Obligations
The Company recognizes an estimated liability for future costs associated with the abandonment of its oil
and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to
F-37
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.
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,
2009
2008
(In thousands)
$ 116,274
2,784
(28,958)
8,673
3,307
$ 102,080
$
$
108,284
11,684
(24,154)
7,486
12,974
116,274
Accounts payable and accrued expenses as of December 31, 2009, contain $23.7 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 and multiple Gulf of Mexico
platforms that are being relinquished or plugged. Accounts payable and accrued expenses contained $7.3 million
related to the Company’s asset retirement obligation as of December 31, 2008. 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 13 – Hurricanes for additional details.
Note 10 – Derivative Financial Instruments
New Authoritative Accounting Guidance under FASB ASC Topic 815
Effective January 1, 2009, new authoritative accounting guidance under FASB ASC Topic 815,
“Derivatives and Hedging” (“ASC Topic 815”) requires entities to provide greater transparency about how and
why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for,
and how derivative instruments and related hedged items affect an entity’s financial position, results of
operations, and cash flows.
Oil, Natural Gas and NGL Commodity Hedges
To mitigate a portion of the potential exposure to adverse market changes in oil and gas prices and the
associated impact on cash flows, the Company has entered into various derivative contracts. The Company’s
derivative contracts in place include swap and collar arrangements for oil, natural gas, and natural gas liquids
(“NGLs”). As of December 31, 2009, the Company has hedge contracts in place through the end of 2012 for a
total of approximately 6 million Bbls of anticipated crude oil production, 63 million MMBtu of anticipated natural
gas production, and 1 million Bbls of anticipated natural gas liquids production.
F-38
The Company attempts to qualify its oil, gas and NGL derivative instruments as cash flow hedges for
accounting purposes under ASC Topic 815. 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 derivatives that are designated as
cash flow hedges to the specific forecasted sale of oil, gas or NGL 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 for that derivative
prospectively. If hedge accounting is discontinued and the derivative remains outstanding, the Company will
recognize all subsequent changes in its fair value in the Company’s consolidated statements of operations for the
period in which the change occurs. As of December 31, 2009, all oil, natural gas, and NGL 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, gas and NGL hedges are measured at fair value and are included in the
accompanying consolidated balance sheets as derivative assets and liabilities. The Company derives internal
valuation estimates taking into consideration the counterparties’ credit worthiness, the Company’s credit
worthiness, and the time value of money. Those internal valuations are then compared to the counterparties’
mark-to-market statements. The consideration of the factors results in an estimated exit-price for each derivative
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, gas and NGL derivative markets are highly active. The fair value of oil, gas and NGL derivative
contracts designated and qualifying as cash flow hedges under ASC Topic 815 was a net liability of $80.9 million
and a net asset of $105.3 million at December 31, 2009, and 2008, respectively.
The following table details the fair value of derivatives recorded in the consolidated balance sheets, by
category:
Derivative assets designated as cash
flow hedges:
Oil, natural gas, and NGL commodity
Oil, natural gas, and NGL commodity
Total derivative assets designated as
cash flow hedges under ASC
Topic 815
Derivative liabilities designated as
cash flow hedges:
Oil, natural gas, and NGL commodity
Oil, natural gas, and NGL commodity
Total derivative liabilities designated
as cash flow hedges under ASC
Topic 815
Location on
Consolidated Balance
Sheets
Fair Value at
December 31, 2009
Fair Value at
December 31, 2008
(In thousands)
Current assets
Other noncurrent assets
$
30,295
8,251
$
111,649
21,541
$
38,546
$
133,190
Current liabilities
Noncurrent liabilities
$
(53,929)
(65,499)
$
(501)
(27,419)
$
(119,428)
$
(27,920)
Realized gains or losses from the settlement of oil, gas and NGL derivative contracts are reported in the
total operating revenues section of the accompanying consolidated statements of operations. The Company
realized a net gain of $140.6 million, a net loss of $101.1 million, and a net gain of $24.5 million from its oil, gas,
NGL and interest rate derivative contracts for the years ended December 31, 2009, 2008, and 2007, respectively.
F-39
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 accumulated other
comprehensive income in the accompanying consolidated balance sheets until the hedged item is realized in
earnings upon the sale of the associated hedged production. As of December 31, 2009, the amount of unrealized
loss net of deferred income taxes to be reclassified from accumulated other comprehensive income to realized oil
and gas hedge gain (loss) in the Company’s accompanying consolidated statements of operations in the next
twelve months is $6.5 million.
The Company seeks to minimize ineffectiveness by entering into oil derivative contracts indexed to the
New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”) index 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 sales contracts, this
results in derivative contracts that are highly correlated with the underlying hedged item.
The following table details the effect of derivative instruments on other comprehensive income (loss) and
the consolidated balance sheets (net of tax):
Derivatives
Qualifying
as Cash
Flow
Hedges
Commodity
hedges
Commodity
hedges
2009
For the Years
Ended December 31,
2008
(In thousands)
2007
$ 35,977
$(177,005)
$154,497
$ (67,344)
$ 46,463
$ (15,470)
Amount of (Gain) Loss on
Derivatives Recognized in
OCI During the Period
(Effective Portion)
Amount of (Gain) Loss
Reclassified from AOCI to
Realized Oil and Gas Hedge
Gain (Loss) (Effective
Portion)
Any change in fair value resulting from hedge ineffectiveness is recognized in unrealized derivative
(gain) loss in the accompanying consolidated statements of operations. The following table details the effect of
derivative instruments on the consolidated statements of operations:
Derivatives Qualifying
as Cash Flow Hedges
Classification of (Gain)
Loss Recognized in
Earnings
(Gain) Loss Recognized in Earnings
(Ineffective Portion)
For the Years
Ended December 31,
2008
(In thousands)
2007
2009
Commodity Hedges
Unrealized derivative
(gain) loss
$ 20,469
$ (11,209)
$
4,123
F-40
Derivatives Not
Qualifying as Cash Flow
Hedges
Classification of (Gain)
Loss Recognized in
Earnings
(Gain) Loss Recognized in Earnings
(Ineffective Portion)
For the Years
Ended December 31,
2008
(In thousands)
2007
2009
Commodity Hedges
Unrealized derivative
(gain) loss
$
-
$
-
$
1,335
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. A mark-to-market valuation 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. This derivative qualified for cash
flow hedge treatment under ASC Topic 815. 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
The contingent interest provision of the 3.50% Senior Convertible Notes is a derivative instrument. As of
December 31, 2009 and 2008, the value of this derivative was determined to be immaterial.
Note 11 – Fair Value Measurements
On January 1, 2008, the Company applied new authoritative accounting guidance under FASB ASC
Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”) for all financial assets and liabilities
measured at fair value on a recurring basis. The topic established a framework for measuring fair value and
required enhanced disclosures about fair value measurements. ASC Topic 820 defined fair value as the price that
would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between
market participants at the measurement date. The topic established market or observable inputs as the preferred
sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs.
The topic established 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
On January 1, 2009, the Company applied ASC Topic 820 to all non-financial assets and liabilities
measured at fair value on a nonrecurring basis, including long-lived assets and assets held for sale measured at
fair value under ASC Topic 360 and asset retirement obligations initially measured at fair value under FASB ASC
Topic 410, “Asset Retirement and Environmental Obligations” (“ASC Topic 410”). The adoption of ASC Topic
820 for non-financial assets and liabilities did not have a material impact on the Company’s financial statements.
F-41
The following is a listing of the Company’s assets and liabilities that are measured at fair value and where
they are classified within the hierarchy as of December 31, 2009:
Level 1
Level 2
(In thousands)
Level 3
Assets:
Derivatives(a)
Proved oil and gas
properties(b)
Materials inventory(b)
Liabilities:
Derivatives(a)
Net Profits Plan(a)
$
$
$
$
$
-
-
-
-
-
$
38,546
$
-
$
$
$
$
-
13,882
$
$
11,740
-
119,428
-
$
-
$ 170,291
(a) This represents a financial asset or liability that is measured at fair value on a recurring basis.
(b) This represents a nonfinancial asset or liability that is measured at fair value on a nonrecurring basis effective January 1, 2009.
The following is a listing of the Company’s financial assets and liabilities that are measured at fair value
on a recurring basis and where they are classified within the hierarchy as of December 31, 2008:
Assets:
Derivatives
Liabilities:
Derivatives
Net Profits Plan
Level 1
Level 2
(In thousands)
Level 3
$
$
$
-
-
-
$ 133,190
$
-
$
$
27,920
-
-
$
$ 177,366
Both financial and non-financial assets and liabilities are categorized within the hierarchy based on the
lowest level of input that is significant to the fair value measurement. The following is a description of the
valuation methodologies used by the Company as well as the general classification of such instruments pursuant
to the hierarchy.
Derivatives
The Company uses Level 2 inputs to measure the fair value of oil and gas hedges. Fair values are based
upon interpolated data. The Company derives internal valuation estimates taking into consideration the
counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are
then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an
estimated exit-price that management believes provides a reasonable and consistent methodology for valuing
derivative instruments.
Generally, market quotes assume that all counterparties have near zero, or low, default rates and have
equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific
counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its
counterparties and may ask counterparties to post collateral if their ratings deteriorate. In some instances the
Company will attempt to novate the trade to a more stable counterparty.
Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value
of any 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 facility margins, and any
F-42
change in such margins since the last measurement date. The majority of the Company’s derivative
counterparties are members of St. Mary’s credit facility bank syndicate.
The methods described above may result in a fair value estimate that may not be indicative of net
realizable value or may not be reflective of future fair values and cash flows. While the Company believes that
the valuation methods utilized are appropriate and consistent with the requirements of ASC Topic 820 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.
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 expected future cash flow
amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations
of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to
calculate the fair value. There is a direct correlation between realized oil and gas commodity prices driving net
cash flows and the Net Profits Plan liability. If commodity prices fall, the liability is reduced or eliminated.
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 Company continually evaluates the assumptions used in this
calculation in order to consider the current market environment for oil and gas prices, costs, discount rates, and
overall market conditions. For 2008 and prior the commodity price assumptions were formulated by applying a
price that was derived from a rolling average of actual prices realized in the 24 months prior to the reporting date
together with adjusted NYMEX strip prices for the ensuing 12 months. This average price was adjusted to
include the effect of hedge prices for the percentage of forecasted production hedged in the relevant periods. Due
to significant fluctuations in commodity prices over the past two years the Company no longer believes this
method for computing commodity price assumptions produces the best estimate of future prices. The
December 31, 2009, Net Profits Plan liability was determined using price assumptions that were computed using
five one-year strip prices with the fifth year’s pricing being carried out indefinitely. The Company’s management
believes the change in accounting estimate is appropriate and provides a better estimation of the liability. The
average price is still adjusted to include the effects of hedging. The non-cash expense associated with this
significant management estimate is highly volatile from period to period due to fluctuations that occur in the
crude oil and natural gas commodity markets.
If the commodity prices used in the calculation changed by five percent, the liability recorded at
December 31, 2009, 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, realized commodity
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.
F-43
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 management estimates that are
described within this footnote. While some inputs to the Company’s calculation of fair value on 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 (c)
Net settlements (c) (d)
Transfers in (out) of Level 3
2009
2007
For the Years Ended December 31,
2008
(In thousands)
$ 211,406
17,421
(51,461)
-
$ 177,366
$ 160,583
82,734
(31,911)
-
$ 211,406
$ 177,366
13,511
(20,586)
-
$ 170,291
Ending balance
(c) 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.
(d) Settlements represent cash payments made or accrued for under the Net Profits Plan.
3.50% Senior Convertible Notes Due 2027
Based on the market price of the 3.50% Senior Convertible Notes, the estimated fair value of the notes
was approximately $290.0 million and $204.0 million as of December 31, 2009 and 2008, respectively. The fair
value of the embedded contingent interest derivative as of December 31, 2009, and 2008, was zero.
Proved Oil and Gas Properties
Proved oil and gas property costs are evaluated for impairment and reduced to fair value if the sum of the
expected undiscounted future cash flows is less than net book value pursuant to ASC Topic 360. The Company
uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value
amount, to measure the fair value of proved properties through an application of discount rates and price forecasts
selected by the Company’s management. The calculation of the discount rate is a significant management
estimate based on the best information available and computed to be 12 percent for the year ended
December 31, 2009. Management believes that the discount rate is representative of current market conditions
and includes the following factors: estimate of future cash payments, expectations of possible variations in the
amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on
NYMEX strip pricing, adjusted for basis differentials, for the first five years. Future operating costs are also
adjusted as deemed appropriate for these estimates.
In accordance with ASC Topic 820, of the $2.1 billion worth of long-lived assets, excluding materials
inventory, $11.7 million were measured at fair value at December 31, 2009.
Materials Inventory
Materials inventory is valued at the lower of cost or market. The Company uses Level 2 inputs to
measure the fair value of materials inventory, which is primarily comprised of tubular goods. The Company uses
third party market quotes and compares the quotes to the book value of the materials inventory. If the book value
exceeds the quoted market price, the Company reduces the book value to the market price. The considered factors
result in an estimated exit-price that management believes provides a reasonable and consistent methodology for
valuing materials inventory.
In accordance with ASC Topic 820, of the $24.5 million of materials inventory, $13.9 million was
measured at fair value at December 31, 2009.
F-44
Asset Retirement Obligations
The Company estimates asset retirement obligations pursuant to the provisions of ASC Topic 410. The
income valuation technique is utilized by the Company to determine the fair value of the liability at the point of
inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time
value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given
the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed
to use Level 3 inputs. There were no asset retirement obligations measured at fair value within the accompanying
consolidated balance sheets at December 31, 2009.
Please refer to Note 10 – Derivative Financial Instruments and Note 9 – Asset Retirement Obligations for
more information regarding the Company’s hedging instruments and asset retirement obligations, as well as Note
8 - Pension Benefits for additional fair value discussion.
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 authorized to be repurchased under the plan of 6,000,000.
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 laws. Stock repurchases may be funded with
existing cash balances, internal cash flows, and borrowings under the credit facility. The details for shares
repurchased and retired are summarized as follows:
For the Years Ended December 31,
2008
2009
2007
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
$
Number of shares retired
Remaining shares authorized to be repurchased
-
3,072,184
2,945,212
3,072,184
-
5,207,784
Note 13 – Hurricanes
In 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 made use of its insurance coverage with regards to the lost platform and damage to several other
properties. Due to the severe damage caused by the hurricanes, the total storm related costs exceeded the
maximum insurance policy limit. As a result, the Company recorded losses of $8.3 million and $7.0 million in
other expense in the accompanying consolidated statements of operations for the years ended December 31, 2009
and 2008, respectively. To date, the Company has received $16.8 million in insurance proceeds. Any variation
between actual and estimated storm related costs will impact the final determination of the loss.
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. The Company recorded a loss of $2.3 million and a gain of $5.2 million in other revenue in the
accompanying consolidated statements of operations for the years ended December 31, 2008, and 2007,
F-45
respectively, resulting in a total net gain of $2.9 million. The Company’s retirement efforts were 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. At that time, certain
SemGroup entities purchased 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.
On October 27, 2009, the Company executed a Purchase and Sale Agreement whereby the Company sold
a portion of its SemGroup administrative claim under Section 503(b)(9) of the Bankruptcy Code. The Company
recorded a recovery of bad debt expense within the accompanying consolidated statements of operations for the
year ended December 31, 2009. The Company deemed the remaining accounts receivable balance relating to
SemGroup to be uncollectible. As a result of this determination, the Company wrote off the allowance for
doubtful accounts and the accounts receivable balance as of December 31, 2009. This matter is complete as of
December 31, 2009, and did not have a material adverse effect on the Company’s liquidity or overall financial
position.
Note 15 – 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:
Development costs
Exploration costs
Acquisitions
For the Years Ended December 31,
2009
2008
2007
$ 223,108
154,122
(In thousands)
$ 587,548
92,199
$ 592,275
111,470
Proved properties
Unproved properties – acquisitions of
proved properties (1)
Unproved properties - other
Total, including asset retirement obligation(2)(3)
76
51,567
161,665
-
41,677
$ 418,983
43,274
83,078
$ 857,666
23,495
38,436
$ 927,341
(1) Represents 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 for additional information.
(2) Includes capitalized interest of $1.9 million, $4.7 million, and $6.7 million for the years ended December 31, 2009, 2008, and 2007,
respectively.
(3) Includes amounts relating to estimated asset retirement obligations of $(805,000), $15.4 million, and $27.6 million for the years ended
December 31, 2009, 2008, and 2007, respectively.
F-46
Suspended Well Costs
The following table reflects the net changes in capitalized exploratory well costs during 2009, 2008, and
2007. The table does not include amounts that were capitalized and either subsequently expensed or reclassified
to producing well costs in the same period:
2009
For the Years Ended December 31,
2008
(In thousands)
2007
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,
$ 9,437
$ 42,930
$ 22,799
34,384
9,437
29,551
(7,569)
(1,868)
$ 34,384
(36,842)
(6,088)
9,437
$
(9,237)
(183)
$ 42,930
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
2009
For the Years Ended December 31,
2008
(In thousands)
$ 9,437
-
$ 9,437
$ 29,368
13,562
$ 42,930
2007
$ 34,384
-
$ 34,384
-
-
3
Note 16 – Disclosures about Oil and Gas Producing Activities (Unaudited)
Recent SEC and FASB Guidance
In December 2008 the SEC published the final rules and interpretations updating its oil and gas reporting
requirements. The Company adopted the rules effective December 31, 2009, and the rule changes, including
those related to pricing and technology, are included in the Company’s reserve estimates.
In January 2010 the FASB aligned ASC Topic 932, with the aforementioned SEC requirements. Please
refer to the section entitled Recently Issued Accounting Standards under Note 1 – Summary of Significant
Accounting Policies for additional discussion regarding both adoptions.
Application of the new rules resulted in the use of lower prices at December 31, 2009, for both oil and gas
than would have resulted under the SEC’s previous methodology. Using 12-month average commodity prices the
Company’s estimated proved reserves were 772.2 BCFE at December 31, 2009, compared to estimated proved
reserves of 865.5 at December 31, 2008. Using year-end commodity prices, as required under the SEC’s previous
methodology, would have resulted in estimated proved reserves of 897.2 BCFE at December 31, 2009.
Therefore, the total impact of the new SEC price methodology was a negative 125 BCFE.
F-47
Third-party Reserves Audit
The Company engaged Ryder Scott Company, L.P. to review internal engineering estimates for at least 80
percent of the PV-10 value of our proven conventional oil and gas reserves in 2009, 2008, and 2007. For 2008
and 2007, Netherland, Sewell and Associates, Inc. prepared the reserve information for the Company’s coalbed
methane 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. The Company divested of all Hanging Woman Basin
properties in the fourth quarter of 2009. Please refer to the section entitled Third-party Reserves Audit under the
heading Reserves included in Part I, Items 1. and 2. Business and Properties.
Oil and Gas Reserve Quantities
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids,
which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be
economically producible – from a given date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations – prior to the time at which contracts providing the
right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices
and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the
average price during the 12-month period prior to the ending date of the period covered by the report, determined
as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless
prices are defined by contractual arrangements, excluding escalations based upon future conditions. With respect
to reserves as of dates prior to December 31, 2009, the applicable SEC definition of proved reserves was 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, meaning prices and costs as of the date the estimate is made. All of the
Company’s proved reserves are located in the continental United States.
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.
F-48
Presented below is a summary of the changes in estimated proved reserves of the Company:
2009
For the Years Ended December 31,
2008
Oil or
Condensate
(MBbl)
Gas
(MMcf)
Oil or
Condensate
(MBbl)
Gas
(MMcf)
2007
Oil or
Condensate
(MBbl)
Gas
(MMcf)
Total Proved Reserves
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 (b)
Production
End of year (c)
Proved developed reserves
Beginning of year
End of year
Proved undeveloped reserves
Beginning of year
End of year
51,363
557,366
78,847
613,450
74,195
482,475
4,520
3,389
(76,767)
51,964
(22,667)
677
(108,163)
41,077
5,238
1,166
9,489
28,483
1,241
29,855
5,424
92,389
4,592
69,090
-
(401)
(6,328)
53,784
-
(41,767)
(71,106)
449,545
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
47,106
48,045
433,210
342,044
68,277
47,106
426,627
433,210
61,519
68,277
358,477
426,627
4,257
5,739
124,156
107,501
10,570
4,257
186,823
124,156
12,676
10,570
123,998
186,823
(a) For the year ended December 31, 2009, of the 49.6 BCFE downward revision of previous estimate, 12.0 BCFE and (61.6) BCFE
relate to price and performance revisions, respectively. The largest portion of the performance revision related to producing
properties in the Company’s Wolfberry tight oil program in the Permian Basin in West Texas. Well performance data collected
during 2009 at the Sweetie Peck and Halff East programs that target the Wolfberry interval indicate that these assets are
underperforming for year-end 2008 decline forecasts. Accordingly, the Company removed 37 BCFE from proved reserves in the
Permian region, primarily related to the Wolfberry tight oil program. The Company believes that a significant portion of these
reserves, while not meeting the criteria to be booked as proved reserves at year-end, are likely to eventually be produced. The
Company also saw a downward performance revision of 12 BCFE related to certain Cotton Valley assets in our ArkLaTex region.
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.
(b) The Company divested of certain non-core assets during 2009, 2008, and 2007. Please refer to Note 3 - Acquisitions, Divestitures,
and Assets Held for Sale for additional information.
(c) For the years ended December 31, 2009, 2008, and 2007, amounts included approximately 370, 659, and, 316 MMcf respectively,
representing the Company’s net underproduced gas balancing position.
Standardized Measure of Discounted Future Net Cash Flows
The Company follows the guidelines prescribed in ASC Topic 932 for computing a standardized measure
of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows and future
production and development costs are determined by applying prices and costs, including transportation, quality,
and basis differentials, 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.
F-49
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
SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived
from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process,
as discussed previously, are equally applicable to the standardized measure computations since these reserve
quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation,
quality, and basis differentials were used in the calculation of the standardized measure:
2009
2008
2007
Gas (per Mcf)
Oil (per Bbl)
$ 3.82
$ 53.94
$ 4.88
$ 33.91
$ 7.56
$ 88.71
F-50
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 ASC Topic 932:
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
2009
$ 4,620,735
(1,968,096)
(387,722)
(515,953)
1,748,964
(732,997)
As of December 31,
2008
(In thousands)
$ 4,463,894
(1,866,821)
(393,620)
(419,544)
1,783,909
(724,840)
2007
$11,629,679
(3,672,857)
(611,288)
(2,316,637)
5,028,897
(2,321,983)
$ 1,015,967
$ 1,059,069
$ 2,706,914
The principle sources of change in the standardized measure of discounted future net cash flows are:
2009
For the Years Ended December 31,
2008
(In thousands)
2007
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
$ 1,059,069
$2,706,914
$ 1,576,436
(409,153)
154,008
(988,045)
(2,033,674)
(693,885)
1,320,994
166,666
-
33,742
75,134
(96,354)
126,538
(44,823)
(61,801)
12,941
$ 1,015,967
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
F-51
Note 17 – Quarterly Financial Information (Unaudited)
The Company’s quarterly financial information for fiscal 2009 and 2008 is as follows (in thousands,
except per share amounts):
Year Ended December 31, 2009
Total operating revenues
Total operating expenses
Income (loss) from operations
Income (loss) before income taxes
Net income (loss)
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$ 199,220
334,685
$ (135,465)
$ 205,198
211,059
(5,861)
$
$ 185,787
185,330
457
$
$ 241,996
231,962
10,034
$
$ (141,539)
$ (87,623)
$ (13,419)
(8,322)
$
$
$
$
$
$
(7,018)
(4,415)
(0.07)
(0.07)
0.05
$
$
$
$
$
2,512
990
0.02
0.02
-
Basic net income (loss) per common share
Diluted net income (loss) per common share
Dividends declared per common share
$
$
$
(1.41)
(1.41)
0.05
$
$
$
(0.13)
(0.13)
-
Year Ended December 31, 2008 (1)
Total operating revenues
Total operating expenses
Income (loss) from operations
Income (loss) before income taxes
Net income (loss)
$ 362,102
204,762
$ 157,340
$ 356,942
298,691
58,251
$
$ 324,088
179,762
$ 144,326
$ 258,169
446,885
$ (188,716)
$ 150,844
$ 94,974
$
$
51,067
32,469
$ 137,539
86,997
$
$ (194,714)
$ (127,092)
0.53
Basic net income (loss) per common share
0.52
Diluted net income (loss) per common share
-
Dividends declared per common share
(1) The 2008 amounts have been adjusted for the application of guidance under ASC Topic 470.
$
$
$
1.51
1.48
0.05
$
$
$
$
$
$
1.40
1.38
0.05
$
$
$
(2.04)
(2.04)
-
F-52
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, 2010
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, 2009, 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, 2010
/s/ A. WADE PURSELL
A. Wade Pursell
/s/ MARK T. SOLOMON
Mark T. Solomon
Executive Vice President and Chief
Financial Officer
February 23, 2010
Controller
February 23, 2010
Signature
Title
Date
/s/ WILLIAM D. SULLIVAN
William D. Sullivan
/s/ BARBARA M. BAUMANN
Barbara M. Baumann
/s/ LARRY W. BICKLE
Larry W. Bickle
/s/ WILLIAM J. GARDINER
William J. Gardiner
/s/ JULIO M. QUINTANA
Julio M. Quintana
/s/ JOHN M. SEIDL
John. M. Seidl
Chairman of the Board of Directors
February 23, 2010
Director
February 23, 2010
Director
February 23, 2010
Director
February 23, 2010
Director
February 23, 2010
Director
February 23, 2010
DIRECTORS
OFFICERS
William D. Sullivan
The Woodlands, Texas
Chairman of the Board
St. Mary Land & Exploration Company
Barbara M. Baumann
Denver, Colorado
President
Cross Creek Energy Corporation
Anthony J. Best
Denver, Colorado
President and Chief Executive Officer
Anthony J. Best
President and Chief Executive Officer
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
St. Mary Land & Exploration Company
Regional Manager — Rockies
Larry W. Bickle
Houston, Texas
Private Equity Investor
William J. Gardiner
Houston, Texas
Milam Randolph Pharo
Senior Vice President and
General Counsel
Stephen C. Pugh
Senior Vice President and
Vice President and Chief Financial Officer
Regional Manager — ArkLaTex
INFORMATION ABOUT FORWARD
LOOKING STATEMENTS
This annual report contains forward looking
statements within the meaning of securities laws,
including forecasts and projections. The words “will,”
“believe,” “budget,” “plan,” “intend,” “estimate,”
“forecast,” and “expect” and similar expressions are
intended to identify forward looking statements.
These statements involve known and unknown risks,
which may cause 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 2009
Annual Report on Form 10-K. Although St. Mary
may from time to time voluntarily update its
prior forward looking statements, it disclaims any
commitment to do so except as required by
securities laws.
King Ranch, Inc.
Julio M. Quintana
Houston, Texas
President and Chief Executive Officer
TESCO Corporation
John M. Seidl
Houston, Texas
Chairman of the Board
and Chief Executive Officer
EnviroFuels, LLC
12
Paul M. Veatch
Senior Vice President and
Regional Manager — Mid-Continent
T. Hutch Jobe
Vice President
Geoscience & Exploration
Kenneth J. Knott
Vice President
Business Development & Land
Gregory T. Leyendecker
Vice President and
Regional Manager — South Texas
and Gulf Coast
John R. Monark
Vice President
Human Resources
Lehman E. Newton, III
Vice President and
Regional Manager — Permian
David J. Whitcomb
Vice President — Marketing
Dennis A. Zubieta
Vice President
Engineering & Evaluation
Mark T. Solomon
Controller
Stockholder Information
OFFICES
INVESTOR RELATIONS CONTACT
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.
Email: 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.
Email:
information@stmaryland.com
Please visit the Investor Relations section of our website at stmaryland.com
Stock Transfer Agent
Any stockholder 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 16, 2010, the registrant had
62,777,688 shares of common stock outstanding, which is net of 126,893
treasury shares held by the Company.
March 31
June 30
September 30
December 31
2009 — Quarter Ended
2008 — Quarter Ended
High
Low
High
Low
$24.60
$11.21
$39.95
$31.70
23.48
33.62
38.05
12.05
17.13
29.80
65.00
65.58
35.81
37.73
32.53
14.76
Denver, CO – Corporate Headquarters
Our Denver office has moved its location.
Our new address is:
1775 Sherman Street
Suite 1200
Denver, CO 80203
Main telephone: (303) 861-8140
Fax: (303) 861-0934
Billings, MT
550 N. 31st Street
Suite 500
Billings, MT 59101
Main telephone: (406) 245-6248
Houston, TX
777 N. Eldridge Pkwy
Suite 1000
Houston, TX 77079
Main telephone: (281) 677-2800
Midland, TX
3300 N. A Street
Building 7
Suite 200
Midland, TX 79705
Main telephone: (432) 688-1700
Shreveport, LA
330 Marshall Street
Suite 1200
Shreveport, LA 71101
Main telephone: (318) 424-0804
Tulsa, OK
7060 S. Yale
Suite 800
Tulsa, OK 74136
Main telephone: (918) 488-7600
DESIGN BY: MARK MULVANY GRAPHIC DESIGN (DENVER, COLORADO)
PHOTOGRAPHY BY: JIM BLECHA (AURORA, COLORADO)
St. Mary Land & Exploration Company • stmaryland.com