...and moving forward
A N N U A L R E P O R T
2 0 0 7
To deliver top tier stock
price performance
to our investors
through growth
of Net Asset Value per share.
Proved Oil & Gas Reserves (BCFE)
Proved Oil & Gas Reserves Per Share (MCFE)
1200
1000
800
600
400
200
20
15
10
05
03
04
05
06
07
03
04
05
06
07
Oil & Gas Production (MMCFE per day)
Oil & Gas Production Per Share (MCFE)
300
250
200
150
100
50
2.00
1.50
1.00
0.50
03
04
05
06
07
03
04
05
06
07
Net Cash From Operating Activities ($ Millions)
Stockholders’ Equity ($ Millions)
800
600
400
200
1000
800
600
400
200
03
04
05
06
07
03
04
05
06
07
FinancialHighlights
2007
2006
2005
2004
2003
3
In thousands except production, proved reserves, price data, and per share amounts, as adjusted for 2 for 1 split on March 31, 2005
Income Statement Data
Oil and gas production revenues
$ 936,577
$ 758,913
$ 711,005
$ 413,318
$ 365,114
Gains on sales and other
Total operating revenues
Net income
53,517
28,788
28,585
19,781
28,594
$ 990,094
$ 787,701
$ 739,590
$ 433,099
$ 393,708
$ 189,712
$ 190,015
$ 151,936
$ 92,479
$ 95,575
Diluted earnings per share
$ 2.94
$
2.94
$
2.33
$ 1.44
$ 1.40
Cash dividends declared and paid per share $ 0.10
$ 0.10
$ 0.10
$ 0.05
$ 0.05
Diluted weighted average common
shares outstanding
64,850
65,962
66,894
66,894
71,069
Balance Sheet Data
Working capital
Total assets
Long-term debt
Stockholders’ equity
Average Net Daily Production
Gas (MMcf)
Oil (MBbl)
MMCFE (6:1)
Average Realized Sales Price
Gas (per Mcf)
Oil (per Bbl)
Proved Reserves
Gas (Bcf)
Oil (MMBbl)
BCFE (6:1)
$ (92,604)
$ 22,870
$
4,937
$ 12,035
$ 3,101
2,571,680
1,899,097
1,268,747
572,500
863,345
433,980
743,374
99,885
569,320
945,460
136,791
484,455
735,854
110,696
390,653
181.0
18.9
294.5
154.7
16.6
254.2
141.9
16.2
239.4
127.3
13.1
206.0
136.1
12.4
210.7
$ 7.63
$
7.37
$
7.90
$ 5.52
$ 4.89
$ 62.60
$ 56.60
$
50.93
$ 32.53
$ 26.96
613.5
78.8
1,086.5
482.5
74.2
927.6
417.1
62.9
794.5
319.2
56.6
658.6
307.0
47.8
593.7
LetterToStockholders
4
The theme to last year’s 2006 annual report was “Transitions.” In that report we described the
various transitions St. Mary has made over its 100 year history — from passive oil and gas royalty
owner to a fully functioning multi-billion dollar exploration and production company. In 2007, the
“Transitions” theme continued. I was named CEO early in the year when Mark Hellerstein retired
after leading the Company for 15 years. We continued the transition of our asset base toward
more concentrated asset groups comprised of low risk, repeatable resource plays. One way we did
this was with two acquisitions in South Texas targeting the Olmos shallow gas formation. Another
way was our initiation of a marketed divestiture package of non-core assets during the year. This
sale closed in January of 2008 for $131 million. Management also continued to transition during
2007 as we saw new leaders appointed to head four of our five regional offices.
This brings us to the theme of this year’s annual report: “Energized for 100 years… and moving
forward.” In early 2008, we celebrate our 100th anniversary. This is a tremendous accomplishment
for any business, particularly in an industry that sees as much consolidation as the exploration and
production industry. Our longevity is proof that St. Mary has been successful at delivering value
to its owners for a very long period of time. We plan to celebrate this anniversary with gatherings
at each of our offices early in the year, capped off with a special event at the New York Stock
Exchange where we will ring the closing bell. Our 100 years of success has been achieved with a
focus on creating value for our stockholders. We intend to continue this tradition.
2007 Performance and Highlights
5
The Company’s operational and financial highlights for 2007 include the following:
(cid:129) Proved reserves grew 17% year over year to 1,087 BCFE, which is a record for the Company
both in absolute terms and on a per share basis.
(cid:129) Record average daily production of 294.5 MMCFE per day, up 16% year over year. This was a
record on a per diluted share basis as well.
(cid:129) Record net cash provided by operating activities of $630.8 million, up 35% year over year.
(cid:129) Net income of $189.7 million and diluted earnings per share of $2.94 per share.
(cid:129) All-in reserve replacement percentage of 248%, an improvement from 244% in the prior year.
(cid:129) All-in finding costs of $3.48 per MCFE, down from $3.56 per MCFE in 2006.
These 2007 results were driven by an active acquisition and capital development plan whereby
St. Mary invested $926 million in acquisition, development, and leasing activities. The Company
deployed $741 million on exploration and development projects during the year, which was an
increase from the $523 million spent in 2006. Highlights of our 2007 regional programs include
the following:
6
MID-CONTINENT — In 2007, we invested $186 million in the Mid-Continent region on exploration,
development, and acquisition activities. Throughout 2007, we maintained a consistent level of
activity in the Arkoma Basin in order to advance our horizontal Woodford shale program where we
continued to refine our understanding of the play. Our results for this program were significantly
better in the second half of the year as we gained experience in the overall completion and design
methodology for these wells together with an increased understanding of the underlying geology,
all of which translated into enhanced performance. We decreased our activity in the Atoka/Granite
Wash development program while working to develop and implement a more cost efficient
completion design for these wells. Several exploration wells were also drilled by this regional
office in 2007. The most exciting of these tested deeper sections of the Anadarko Basin, which
we believe validated a geologic idea that we plan to test further in 2008.
ARKLATEX — The ArkLaTex region invested $150 million in 2007. This is 70% more than the $88
million spent in 2006. The primary drivers of this increase in capital investment were increased
activity levels in our James Lime and Cotton Valley programs. In the St. Mary operated horizontal
James Lime program, we operated one rig continuously throughout 2007. We continued to see solid
results in proven development areas and had two successful test wells during the year that
extended the play westward by a number of miles. We believe that we have identified a trend that
is roughly 75 miles in length that could be prospective for the James Lime. During 2007, we
increased our acreage position along that trend to approximately 50,000 net acres. Our team in
Shreveport has been successfully drilling and completing horizontal James Lime wells for a number
of years, and we believe we are one of the better operators in the play. The partner operated
Cotton Valley programs at Elm Grove and Terryville fields were areas of significant investment
in 2007. At Elm Grove Field, advancements such as 20-acre increased density drilling and
In 2007, the Company’s
proved reserves exceeded
1,000 BCFE, or 1 TCFE,
marking a major
milestone in our history.
TCFE
1,000,000,000,000
8
commingling of production from the Cotton Valley and Hosston formations have benefited us,
particularly as development has moved into areas where we have larger working interests. There
is an old adage in the exploration and production business that “good fields get better ”— this is
certainly the case with Elm Grove. At Terryville Field, despite more difficult operating conditions
resulting from the Cotton Valley formation being deeper and more highly pressured compared to
Elm Grove Field, operations there were highly successful in 2007 and allowed for sustained activity
during the year.
GULF COAST — Our capital expenditures in the Gulf Coast region grew significantly from $66
million in 2006 to $279 million in 2007, primarily driven by two significant acquisitions totaling
$179 million. These were the $149 million Rockford acquisition that closed in October 2007 and
the $30 million Catarina acquisition, which closed in April 2007. Both of these target the Olmos
shallow gas formation and are located in the greater Maverick Basin in South Texas. St. Mary had
been interested in the Olmos formation for some time, and we are pleased that we were able to
enter the play in a meaningful way in 2007. We are the operator of these recently acquired
assets and our emphasis in 2007 was the integration of these properties into our operations.
While the core focus of the region shifted toward onshore projects, we continued to be active off-
shore in 2007. The previously discovered Zloty intermediate deepwater project began production
late in the year, and other intermediate deepwater projects in which we are a partner continued to
advance. We were also active closer to shore with a program that included the successful Reno,
Clement, and Amber Jack wells. We have benefited from the meaningful production associated with
some of these longer lead time projects.
9
PERMIAN — St. Mary began 2007 with no regional office in the Permian Basin. That changed
in February when we opened a regional office in Midland, Texas to manage the Sweetie Peck
properties acquired in December 2006. Throughout 2007, we continued to build our Midland staff
and as of the date of this letter we are now fully staffed in this regional office. During 2007, this
region invested $135 million. The majority of this investment was deployed to develop projects that
target the Wolfcamp and Spraberry formations, commonly referred to as the “Wolfberry.” We
participated in two substantial Wolfberry programs during the year — the operated Sweetie Peck
program and the outside operated program at Halff East. We operated between two and five drilling
rigs at Sweetie Peck throughout 2007. Our efforts in the Sweetie Peck program have focused on
improving our operating efficiencies. Throughout 2007, we significantly improved our rig fleet and
transitioned the drilling operations in-house once the Midland office was fully staffed. We antici-
pate that these improvements will benefit our program here in the years to come. At Halff East,
our operating partner had two drilling rigs running continuously throughout the year. During the
year, we also invested capital in the Parkway and East Shugart Delaware waterflood projects.
ROCKY MOUNTAIN — In 2007, St. Mary invested $178 million in the Rocky Mountain region,
compared to $161 million in 2006. The 2007 amount included $36 million of capital invested in
the Hanging Woman Basin coalbed methane project. The 2007 conventional program focused on
a horizontal development in the Mississippian formations of the Williston Basin and the drilling of
Bakken formation infill locations in Montana.
2007 Proved Reserve Base by Region
1,087 BCFE (cid:129) 56% Gas (cid:129) 23% PUD
14%
11%
16%
19%
40%
■ Rocky Mountain ■ Mid-Continent ■ ArkLaTex ■ Gulf Coast ■ Permian
10
As a result of our active 2007 program, the Company reached a significant milestone in 2007 as
its proved reserves surpassed 1 TCFE. As of December 31, 2007, St. Mary had proved reserves of
1,087 BCFE, of which 77% were proved developed and 56% were natural gas. This is a significant
threshold for any independent E&P company since every day its assets are depleting as they are
produced. The ability to economically grow reserves is critical for the ongoing success of any
company in our industry. At St. Mary, our long-standing goal is to annually replace 200% of that
year’s production. In 2007, we met this goal by replacing 248% of our reserves produced in 2007
on an all sources basis. Our 3 year and 5 year average reserve replacement percentages were
249% and 235%, respectively. What is particularly important for stockholders is that St. Mary
has consistently grown proved reserves on a per share basis while incurring moderate levels of
debt. We replaced 88% of our 2007 produced reserves through acquisitions in 2007, which is
in-line with our historic average for acquisition reserve replacement. Acquisitions have historically
been a significant part of the St. Mary business plan, and we believe they will continue to play an
important role in our future strategy.
Our 2007 all-in finding cost for proved reserves was $3.48 per MCFE, down from $3.56 per MCFE
in 2006. We believe that it is important to look at longer time periods when analyzing this metric
due to the differences in timing as to when capital is invested and when proved reserves are
booked. Our 3 and 5 year averages for all-in finding costs on a per MCFE basis were $3.01 and
$2.61, respectively. Finding costs in the industry have generally increased in recent years as
costs to acquire or develop proved reserves have increased in correlation to commodity prices.
Although finding costs only tell part of the story with respect to the economics of a company’s
investments, we realize that finding costs are an important metric used to evaluate and compare
St. Mary has grown value for
its owners for 100 years,
and is focused on building value
as it enters its second century.
12
the costs at which companies are adding reserves. Accordingly, we are very focused on reducing
costs and making portfolio changes that will allow us to improve on this metric.
Production in 2007 set a new record for St. Mary, both in absolute terms and on a per share basis.
Total production for the year was 107.5 BCFE, or an average daily rate of 294.5 MMCFE per day.
For the full year, approximately 60% of the Company’s production was natural gas and roughly
40% was oil. This record production combined with strong commodity prices during the year,
particularly for oil, resulted in solid net income and cash flow from operating activities. Production
growth in 2007 was driven primarily by strong contributions from the Permian, ArkLaTex, and Mid-
Continent regions. The strong cash flows that we enjoyed during the year allowed us to maintain
the strong balance sheet for which St. Mary is known.
Plans for 2008
We are entering 2008 on solid footing both financially and operationally. We have a business plan
that we believe will deliver growth and value for our stockholders. Our debt-to-book capitalization
ratio as of the end of 2007 was 40%. When adjusted for the proceeds received from the divestiture
of non-core properties that closed on January 31, 2008, our pro forma debt-to-book capitalization
ratio stands at 34%. Currently, we are generating strong cash flows. We enjoy the benefits of
having oil as a significant portion of our production profile. Opportunistic natural gas hedges have
helped our realized natural gas revenues stay strong. Operationally, 2008 offers the strongest
inventory of projects that we have had since I joined St. Mary in 2006. We have a multi-year
drilling program in nearly every region that when taken together make clearly visible the
Company’s path for continued growth. The foundation of our property base was strengthened by
the divestiture of non-core assets referred to earlier — not only have we removed lower growth
properties from our portfolio, but now our employees can focus more of their efforts on the assets
13
that offer more upside potential for the Company.
Our initial 2008 exploration and development budget is $626 million. We believe that this budget
level will improve the capital efficiency of our investments and enhance the strength of our balance
sheet to maintain financial flexibility in the future. This budget level also provides solid organic
production growth for the Company. Programs that failed to meet our return criteria in 2007 were
either omitted or substantially reduced if they warranted further study. Accordingly, we anticipate
operating cash flows will exceed our drilling capital budget during the year. This will provide us the
financial flexibility to accelerate successful drilling programs, pursue potential acquisition oppor-
tunities, consider repurchases of outstanding shares of common stock, or repay bank borrowings
with excess cash flows. Highlights of the Company’s 2008 exploration and development plan
are as follows:
ARKLATEX — The largest regional capital program in 2008 will be in the ArkLaTex region, which
will focus on Cotton Valley and James Lime programs. Of the capital allocated for Cotton Valley
programs in 2008, a little over half will be invested at Elm Grove Field in northern Louisiana where
development continues to be highly successful. Further development of the field on 20-acre
spacing and highly economic uphole recompletions continue to drive activity in this play, which
becomes more meaningful to St. Mary as activity moves onto acreage where we have a larger
working interest. A successful horizontal Cotton Valley well completed at the end of 2007 has
raised the prospect that the field could be further developed with horizontal wells. Our operating
partner is currently drilling an offset to the initial horizontal test which, if successful, could
St. Mary has provided a compound return
of 20% to stockholders since its IPO in 1992.
15
substantiate a horizontal development plan at Elm Grove Field. The remaining Cotton Valley
allocation for 2008 will be split between the program at Terryville Field and the St. Mary operated
program in East Texas. Subsequent to year end, St. Mary acquired additional producing and non-
producing properties in Panola County, Texas, which are adjacent to existing St. Mary leasehold.
These assets target the Cotton Valley formation, a formation in which we are increasingly interested.
As operator, we plan to drill several horizontal and vertical wells in the area in 2008. We believe
that our experience in the region, particularly in drilling horizontal James Lime wells, will be an
advantage that we can exploit as we pursue a more active operated Cotton Valley program in the
future. In the operated horizontal James Lime program, we plan to have a more aggressive program
in 2008 with two operated rigs budgeted to run continuously throughout the year. We continue to
be active acquirers of leasehold in the play. We have been involved with this program for a number
of years and believe we are a leader in the play.
MID-CONTINENT — The largest component of our 2008 Mid-Continent plan is the horizontal
Woodford shale program in the Arkoma Basin. Our budget anticipates that we will drill ten hori-
zontal Woodford wells with two operated rigs in the first half of 2008, and continue to participate
with our partners in outside operated wells. As I mentioned earlier, we have seen results improve
recently in the horizontal Woodford program. With continued success in the play, we have the
ability to increase our capital investment in the program in the second half of 2008. We also plan
to continue with an exploration program in the Anadarko Basin that yielded encouraging results in
2007. This exploration program targets some of the deeper formations of the basin. In our Western
Oklahoma Washes program in the Anadarko Basin, previously referred to as the Mayfield devel-
opment area, we plan to invest capital in wells that target the Atoka and Granite Wash formations.
16
The area is a known hydrocarbon province. Our development efforts in 2008 will feature enhanced
geotechnical efforts and revised drilling and completion techniques, both of which should improve
the economic performance of this program.
GULF COAST — Our development and exploration budget in the Gulf Coast region for 2008 is
focused on the evaluation and exploitation of the two Olmos shallow gas projects that we acquired
in South Texas during 2007. Our technical team in Houston is in the process of reinterpreting
seismic data that covers a large portion of our acreage. Approximately half of the budgeted
capital will be deployed to drill new Olmos wells, with additional capital being invested in a
number of recompletion opportunities. We anticipate that the addition of this resource play will
provide focus and a visible inventory of projects for our Gulf Coast team. We will also invest capital
in production facilities for an intermediate deepwater discovery from 2005 that is expected to
be brought online in early 2009.
PERMIAN — The majority of capital investment made in the Permian in 2008 will be in properties
targeting the Wolfberry interval. At Sweetie Peck, we plan to operate three drilling rigs continuously
throughout the year. Included in the budget are investment dollars to test several 40-acre pilot
areas that could add meaningful proved reserves if successful. We expect to see increased
operating efficiency on the investments we made in 2007 related to high-grading our rig fleet
and bringing the drilling operations in-house. At the Halff East Wolfberry development area, we
will continue to invest with our operating partner. We will also be investing in several smaller
programs, including our Delaware waterfloods.
17
ROCKY MOUNTAIN — The 2008 plan for the Rockies is smaller than in years past. In the
conventional Rockies program, six vertical wells and two recompletions in the Red River are
planned for 2008. We also plan to drill a small number of horizontal Bakken wells in and around
our historic Bakken development areas in Montana. We expect to participate in a handful of wells
in the North Dakota Bakken play that has received so much attention in the past year. Our plan
also includes workover and recompletion operations in our Wind River Basin and Big Horn Basin
oil properties. At the outside operated Atlantic Rim coalbed methane play in the Green River
Basin, we expect to see activity ramp up since regulatory and environmental delays appear to
have been resolved. At Hanging Woman Basin, we plan to moderate our drilling activity in 2008
focusing on completing the in-fill program in the shallow coals, monitoring the intermediate depth
wells, and testing several horizontal completion techniques in the deeper coals. We plan to
continue concentrating our property base in the Rocky Mountain region, and are conducting a
thorough review of our Rockies acreage position. Divestitures of non-core assets are anticipated
in the region in the future.
Moving Forward
As mentioned earlier, the theme of this year’s annual report is “Energized for 100 years… and
moving forward.” As we move forward into our second century, we must embrace the challenge
of adapting to new competitive and market realities. One challenge that St. Mary has worked to
address over the past two years is the state of its drilling portfolio by actively working to increase
its inventory of repeatable, multi-year drilling projects. These types of programs are advantageous
because they allow for more predictable production and reserve growth, and have the potential
for improved economics as operational efficiencies develop. Transactions such as the Sweetie
St. Mary has a consistent record of building
value for stockholders by growing proved reserves
and production on a per share basis.
19
Peck acquisition in 2006 and the Olmos acquisitions in 2007 have added to our inventory. The
inventory has also grown through an increased emphasis on grassroots resource programs such
as the horizontal James Lime and Woodford shale. As with any exploration and production com-
pany, we need to continue adding to our project portfolio. To that end, we have been busy in 2007
and early 2008 adding business development professionals in our Denver headquarters and in our
regional offices. The goal is simple — build the team that will economically grow the project
inventory for the Company. As we capture more of these high quality projects in our inventory
pipeline, we will need more technical personnel to execute the development of those resources.
Accordingly, we have hired and are continuing to actively hire engineers and geologists in all of
our regional offices. As of this letter, our total number of employees is 438, an increase of roughly
80 employees from a year ago. This talented group will drive our long-term growth in value.
With the changes outlined above, there are also certain standards that will remain unchanged.
Values such as integrity, reliability, and a sense of stewardship for our owners and our communities
will always be prominent characteristics of St. Mary. We remain committed to being a preferred
partner, employer, and customer in the industry. We believe that this foundation of values and the
commitment of our employees will result in value creation for our stockholders.
March 10, 2008
Anthony J. Best
President and Chief Executive Officer
DIRECTORS
OFFICERS
Barbara M. Baumann (1),(4)
Denver, Colorado
President
Cross Creek Energy Corporation
Anthony J. Best (1)
Denver, Colorado
President and Chief Executive Officer
St. Mary Land & Exploration Company
Larry W. Bickle (2),(4)
Houston, Texas
Private Investor
William J. Gardiner (1),(3)
Houston, Texas
Chief Financial Officer and Vice President
King Ranch Inc.
Mark A. Hellerstein (1)
Denver, Colorado
Chairman and
Former Chief Executive Officer
St. Mary Land & Exploration Company
Julio Quintana (3)
Houston, Texas
President and Chief Executive Officer
TESCO Corporation
John M. Seidl (2),(3)
Houston, Texas
Chairman
EnviroFuels, LLC
William D. Sullivan (2),(4)
The Woodlands, Texas
Former Executive Vice President,
Exploration and Production
Anadarko Petroleum Corporation
(1) Executive Committee
(2) Nominating and Corporate
Governance Committee
(3) Audit Committee
(4) Compensation Committee
Anthony J. Best
President and Chief Executive Officer
Javan D. Ottoson
Executive Vice President and
Chief Operating Officer
Mark D. Mueller
Senior Vice President and
Regional Manager
Stephen C. Pugh
Senior Vice President and
Regional Manager
Paul M. Veatch
Senior Vice President and
Regional Manager
Jerry Hertzler
Vice President – Business Development
Gregory T. Leyendecker
Vice President and Regional Manager
Lehman E. Newton, III
Vice President and Regional Manager
Milam Randolph Pharo
Vice President – Land and Legal
and Assistant Secretary
Garry A. Wilkening
Vice President – Human Resources
and Administration
Mark T. Solomon
Controller
Linda A. Ditsworth
Assistant Vice President –
Land and Assistant Secretary
Michael F. Roach
Assistant Vice President –
Director of Taxation
David J. Whitcomb
Assistant Vice President –
Director of Marketing
Matthew J. Purchase
Treasurer and Budget & Planning Director
INFORMATION ABOUT FORWARD
LOOKING STATEMENTS
This annual repor t contains for ward looking
statements within the meaning of securities laws,
including forecasts and projections for future
periods. The words “will,” “believe,” “anticipate,”
“budget,” “intend,” “estimate,” “forecast,” “plan,”
and “expect” and similar expressions are intended
to identify for ward looking statements. These
statements involve known and unknown risks,
which may cause St. Mary’s actual results to differ
materially from results expressed or implied by the
forward looking statements. These risks include
such factors as discussed in the “Risk Factors”
and “Cautionary Information about Forward Looking
Statements” sections of the accompanying 2007
Annual Report on Form 10-K/A. Although St. Mary
may from time to time voluntarily update its prior
for ward looking statements, it disclaims any
commitment to do so except as required by
securities laws.
GLOSSARY
Finding cost. Expressed in dollars per BOE or
MCFE. Finding costs are calculated by dividing the
amount of total capital expenditures for oil and
natural gas activities, including the effect of asset
retirement obligations, by the amount of estimated
net proved reserves added through discoveries,
extensions, infill drilling, acquisitions, and revisions
of previous estimates during the same period.
Reserve replacement percentage. The sum of
sales of reser ves, reser ve extensions and
discoveries, reser ve acquisitions, and reser ve
revisions of previous estimates for a specified
period of time divided by production for that same
period of time. This is believed to be a useful
non-GAAP measure that is widely utilized within the
exploration and production industry as well as by
investors. It is an easily calculable number and is
representative of the relative success a company
is having in replacing its production from its
declining asset base as well as its ability to grow
the overall company.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(cid:59)
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2007
or
(cid:134)
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission file number 001-31539
ST. MARY LAND & EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction
of incorporation or organization)
41-0518430
(I.R.S. Employer Identification No.)
1776 Lincoln Street, Suite 700, Denver, Colorado
(Address of principal executive offices)
80203
(Zip Code)
(303) 861-8140
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, $.01 par value
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:59) No (cid:134)
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 (cid:134) No (cid:59)
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 (cid:59) No (cid:134)
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. (cid:134)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer (cid:59)
Non-accelerated filer (cid:134) (Do not check if a smaller reporting company)
Accelerated filer (cid:134)
Smaller reporting company (cid:134)
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes (cid:134) No (cid:59)
The aggregate market value of 62,317,450 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the
common stock on June 29, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, of $36.62 per share as
reported on the New York Stock Exchange was $2,282,065,019. 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 15, 2008, the registrant had 63,020,524 shares of common stock outstanding, which is net of 1,009,712 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 2008 annual meeting of stockholders to be filed within 120 days after December 31, 2007.
DOCUMENTS INCORPORATED BY REFERENCE
EXPLANATORY NOTE:
This Amendment on Form 10-K/A to the Annual Report on Form 10-K for the fiscal year ended
December 31, 2007, by St. Mary Land & Exploration Company (the “Company”) is being filed to (i) include
typed conformed signatures of Deloitte & Touche LLP in the Report of Independent Registered Public
Accounting Firm appearing on page 72 and the Report of Independent Registered Public Accounting Firm
appearing on page F-1 (collectively, the “Reports”), the corresponding manual signatures for which were obtained
by the Company prior to the filing of the original Annual Report on Form 10-K (the “Original Form 10-K”) on
February 22, 2008, but the typed conformed signatures for which were inadvertently omitted from the electronic
versions of the Reports filed with the Original Form 10-K, (ii) file a consent of Deloitte & Touche LLP which
refers to the correct date of the Reports of February 21, 2008, and thereby corrects an inadvertent typographical
error in the consent of Deloitte & Touche LLP filed with the Original Form 10-K, which consent incorrectly
referred to the date of the Reports as February 20, 2008, and (iii) furnish a certification of the Company’s Chief
Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 which
refers to the correct title of the Company’s Chief Financial Officer as Senior Vice President - Chief Financial
Officer and Secretary and thereby corrects an inadvertent error in the corresponding certification furnished with
the Original Form 10-K, which certification incorrectly referred to the title of the Company’s Chief Financial
Officer as Senior Vice President - Chief Financial Officer and Treasurer.
Pursuant to the rules of the Securities and Exchange Commission, Item 15 of the Original Form 10-K has
been amended to contain currently dated certifications of the Company’s Chief Executive Officer and Chief
Financial Officer, as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002.
All other information contained in the Original Form 10-K remains unchanged, and the entire report with
all Items is included in this Form 10-K/A for the convenience of the reader. The Company has not updated the
disclosures contained herein to reflect events that occurred after the date of the Original Form 10-K.
ITEM
TABLE OF CONTENTS
PART I
PAGE
ITEMS 1 and 2. BUSINESS and PROPERTIES…………………………………………….
General………………………………………………………………
Strategy……………………………………………………………...
Significant Developments in 2007………………………………….
Assets………………………………………………………………..
Reserves……………………………………………………………..
Production…………………………………………………………...
Productive Wells…………………………………………………….
Drilling Activity…………………………………………………….
Acreage……………………………………………………………...
Major Customers……………………………………………………
Employees and Office Space………………………………………..
Title to Properties…………………………………………………...
Seasonality…………………………………………………………..
Competition…………………………………………………………
Government Regulations……………………………………………
Cautionary Information about Forward-Looking Statements………
Available Information………………………………………………
Glossary of Oil and Natural Gas Terms…………………………….
1
1
1
2
4
9
10
11
11
12
12
12
13
13
13
13
15
17
17
ITEM 1A.
RISK FACTORS………………………………………………………….
20
ITEM 1B.
UNRESOLVED STAFF COMMENTS…………………………………..
29
ITEM 3.
LEGAL PROCEEDINGS…………………………………………………
29
TABLE OF CONTENTS
(Continued)
ITEM
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS………………………………………………………………...
ITEM 4A.
EXECUTIVE OFFICERS OF THE REGISTRANT……………………..
PAGE
29
30
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
ITEM 10.
ITEM 11.
ITEM 12.
PART II
MARKET FOR REGISTRANT’S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES………………………………..
32
SELECTED FINANCIAL DATA…………………………………………
36
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS………..
Overview of the Company…………………………………………...
Overview of Liquidity and Capital Resources……………………….
Critical Accounting Policies and Estimates………………………….
Additional Comparative Data in Tabular Format……………………
Comparison of Financial Results and Trends between
38
38
48
59
62
2007 and 2006…………………………………………………….
64
Comparison of Financial Results and Trends between
2006 and 2005…………………………………………………….
Other Liquidity and Capital Resource Information………………….
Accounting Matters…………………………………………………..
Environmental………………………………………………………..
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK (included with the content of ITEM 7)…………………..
66
68
69
70
70
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA……….
70
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE……………........
70
CONTROLS AND PROCEDURES……………………………………….
70
OTHER INFORMATION………………………………………………….
73
PART III
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE...........................................................................................
73
EXECUTIVE COMPENSATION…………………………………………
73
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS……...……………………………………...
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,
AND DIRECTOR INDEPENDENCE……………………………………..
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES...............................
74
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES....................
74
PART IV
73
73
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. We were founded in 1908 and incorporated in Delaware in
1915. Our initial public offering of common stock took place in December of 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 objective is to build stockholder value through consistent economic growth in reserves and
production that increases net asset value per share. We seek to invest in oil and gas producing assets that result in
a superior return on equity while preserving underlying capital, resulting in a return on equity to stockholders that
reflects capital appreciation as well as the payment of cash dividends.
The majority of our current senior technical managers in each region possess between 20 and 30 years of
industry experience and lead fully-staffed regional technical offices that are supported by centralized administration
from our corporate office in Denver. We use our comprehensive base of geological, geophysical, land, engineering,
and production experience in each of our core operating areas to source prospects for our ongoing low-to-medium-
risk development and exploitation programs. We conduct detailed geologic studies and use an array of technologies
and tools including 2-D and 3-D seismic imaging, hydraulic fracturing and other reservoir stimulation techniques,
horizontal drilling, secondary recovery, and specialized logging tools to enhance the potential of our existing
properties. We believe that having fully-staffed technical teams based in each of our operating regions is an
advantage in that our regional offices are staffed with personnel that have a deep knowledge of the basins in which
they work, participate in the regional deal flow and prefer to live in regional areas, which minimizes personnel
attrition.
Acquisitions have been a key element of our business strategy. Historically, we have been most
successful in acquiring properties on a negotiated basis, as opposed to participating in widely marketed auctions
for properties. In the last two years we have made several large acquisitions. In 2007, we paid $178.9 million for
two acquisitions in South Texas for properties targeting the Olmos shallow gas formation. In 2006, we paid
$243.1 million to acquire assets that target the Wolfberry section in the Permian Basin.
We divest selected non-core assets when market conditions and prices are attractive. We will continue to
evaluate such opportunities in the future when we believe it to be appropriate. During 2007, we sold properties
with estimated proved reserves of 1.4 BCFE. We actively marketed and contracted to sell a package of non-core
assets in 2007. This sale closed on January 31, 2008, for a total adjusted sales price of $131.1 million before
commissions; this sale represented 40.4 BCFE of our year-end 2007 proved reserves. We utilized a 1031 reverse
exchange structure to defer the recognition of income tax on the gain from this sale.
Conservative use of financial leverage has long been a critical element of our strategy. We believe that
maintaining a strong balance sheet is a significant competitive advantage that enables us to pursue acquisitions and
1
other opportunities, particularly in weaker price environments. It also provides us with the financial resources to
weather periods of volatile commodity prices or escalating costs. Our debt to book capitalization ratio was
40 percent at the end of December 2007. The proceeds from the aforementioned property sale in January 2008 were
applied to reducing bank borrowings.
In summary, we believe that our dedication to making investment decisions based on net asset value per
share, our long-standing geologic and engineering experience in the regions in which we operate, our appropriate
application of technology, our established networks of local industry relationships, and our measured approach to
acquisitions and divestitures all provide us with competitive advantages that we can use to continue growing the
Company.
Significant Developments in 2007
•
Increase in 2007 Year-End Reserves. Proved reserves increased 17 percent to 1,086.5 BCFE at
December 31, 2007, from 927.6 BCFE at December 31, 2006. We added 132.1 BCFE from our drilling
program and 94.8 BCFE from acquisitions. We had a positive revision of 40.9 BCFE which consisted
of a 6.4 BCFE upward performance revision and an upward revision of 34.5 BCFE due primarily to
increased oil prices at the end of 2007. The 2007 acquisition volumes are lower than the initial
estimates previously disclosed as a result of the final year-end reservoir engineering estimation. We
sold properties with reserves of 1.4 BCFE in 2007.
• Drilling Results. Reserve additions from drilling activities of 132.1 BCFE were driven by results in the
Mid-Continent, Rocky Mountain, ArkLaTex, and Permian regions, with those regions contributing
37 percent, 21 percent, 20 percent, and 18 percent, respectively. Additions in the Mid-Continent were
driven principally by successful drilling by us and others in the horizontal Woodford shale formation in
the Arkoma Basin, as well as positive results in two programs in the Anadarko Basin. In the Rocky
Mountain region, the largest contribution came from the Hanging Woman Basin where we added
9.9 BCFE of proved reserves. The ArkLaTex region added 26.2 BCFE from successful drilling
operations in the James Lime carbonate program and Elm Grove Field. Successful results in the
Wolfberry program in 2007 were the principal driver of drilling additions in the Permian Basin.
• New Basin Entry in 2007. In 2007 we spent $182.9 million for acquisitions of proved and unproved oil
and gas properties. We entered the greater Maverick Basin with two acquisitions in South Texas
totaling $178.9 million that target the Olmos shallow gas formation. The first was the $30.0 million
Catarina acquisition that closed in June 2007. The more significant transaction was the $148.9 million
Rockford acquisition that closed in October 2007. These properties added a sizeable inventory of lower
risk drilling locations to our portfolio. Consistent with prior acquisitions, we hedged several years of
the risked production related to these acquisitions at the time of acquisition. The remaining acquisitions
in 2007 were small niche transactions throughout the year in the Mid-Continent, ArkLaTex, and Rocky
Mountain regions.
• Senior and Regional Management Changes. During 2007, the Company underwent or announced
personnel changes in the chief executive position and in several regional manager positions. On
February 23, 2007, Mark Hellerstein retired as Chief Executive Officer after serving in that role since
1995. Tony Best, President of the Company, was appointed as Chief Executive Officer on that date.
Mr. Hellerstein continues to serve as the Chairman of the Board. In June of 2007, Jerry Schuyler, the
Senior Vice President responsible for the Gulf Coast and Permian regions, left St. Mary to pursue
another professional opportunity. Greg Leyendecker, then Operations Manager for the Gulf Coast
region, assumed responsibility for the Gulf Coast and is now Vice President - Regional Manager of the
Gulf Coast region. We also made the Midland office a stand-alone regional office headed by
Lehman Newton III, Vice President - Regional Manager of our Permian region. Mr. Leyendecker and
Mr. Newton joined St. Mary in 2006 and each have over 25 years of management and operational
experience in the oil and gas industry. In July 2007, Stephen Pugh joined the Company as Senior Vice
President and Regional Manager of the ArkLaTex region. Mr. Pugh succeeded David Hart, who retired
from St. Mary after 15 years in various roles at the Company. Mr. Pugh came to St. Mary with over
2
25 years of engineering, operations, and business development experience in the oil and gas industry. In
August of this year, Robert Nance, Senior Vice President - Regional Manager of the Rocky Mountain
region, announced his decision to retire in the first quarter of 2008 after more than 40 years in the oil
and gas industry. Mark Mueller joined us as Senior Vice President in August and now leads our Rocky
Mountain region. Mr. Mueller has over 20 years of management and technical experience in the oil and
gas industry. Effective January 1, 2008 Mark Mueller was appointed Senior Vice President - Regional
Manager. Subsequent to year end, David Honeyfield, Senior Vice President - Chief Financial Officer,
announced that he will resign as an officer of St. Mary on March 21, 2008, in order to pursue an
opportunity in an unrelated industry. An external search for his successor is underway at the time of
this filing.
• 2007 Capital Markets Activity. In March of 2007 we called for redemption of the then outstanding
$100.0 million 5.75% Senior Convertible Notes. The notes had a conversion price of $13.00 per share.
One hundred percent of the holders of the notes elected to convert their notes into shares of common
stock. As a result of the conversion, 7.7 million shares of stock were issued to the note holders. This
resulted in a decrease to long-term debt of $100.0 million, and an increase to common stock associated
with the conversion together with the recognition of the excess tax benefit associated with the
contingent interest feature associated with the notes.
In April of 2007, we completed the sale of $287.5 million of 3.50% Senior Convertible Notes. The net
proceeds from the 3.50% Senior Convertible Notes were used to repay outstanding borrowings under
our revolving credit facility.
• Significant Volatility in Commodity Prices. During 2007, the exploration and production sector was
impacted by volatility in the prices for crude oil and natural gas. Our operations and financial
conditions were significantly impacted by these prices. Our crude oil is sold on contracts that pay us
the average of posted prices for the period in which the crude oil is sold. NYMEX crude oil began
2007 with an average January price of $54.67 per barrel and increased steadily throughout the year,
reaching an average monthly high for the year of $94.63 per barrel in November. The average
NYMEX price for the year was $72.34 per barrel. Geopolitical unrest in various producing regions
overseas and concerns domestically related to refinery utilization and petroleum product inventories
were the principal drivers of the increase in oil prices in 2007.
We sell the majority of our natural gas on contracts which are based on first of the month (also
frequently referred to as bid week) index pricing. The Inside FERC bid week price for Henry Hub, a
widely used industry measuring point, averaged $6.86 per MMBtu in 2007, which was five percent
lower than the average for 2006. High levels of natural gas in storage had an impact on pricing
during 2007 as inventory levels exceeded the five year average for all of 2007. Concerns about
supply overhang peaked for the year around September of 2007, leading to the lowest Henry Hub
price for the year of $5.43 per MMBtu. The impact was more acute in the Rocky Mountain region
where bid week prices were driven down to $2.13 per MMBtu and $1.11 per MMBtu for September
and October, respectively, on the Colorado Interstate Gas (CIG) index. A significant portion of our
production in the Rockies is oil and we had limited exposure to the CIG hub. Additionally, recent
acquisitions have added a richer gas stream to our overall production mix. The value received
associated with natural gas liquids (NGLs) from this rich gas stream align more closely with crude oil
prices. The increase in crude prices has had a similar impact on prices for NGLs, and as a result we
have enjoyed higher realized natural gas prices. We hedge a portion of our oil and gas production
using swaps and collars. A gain of $58.7 million was realized on our natural gas hedges for the year
and a loss of $34.3 million was realized on our oil hedges for the year.
• Repurchase of Common Stock. In 2007, we repurchased a total of 792,216 shares of our common
stock in the open market for a weighted-average price of $32.76 per share, including commissions,
under this program. At the time we repurchased our shares, we entered into hedges for a
commensurate amount of our production that was represented by the share repurchase in order to lock
in the discounted price at which our shares were trading. As of the date of this filing, we are
3
authorized by the Board to repurchase 5,207,784 additional shares under this program. The shares
may be repurchased from time to time in open market transactions or in privately negotiated
transactions, subject to market conditions and other factors, including certain provisions of our existing
credit facility agreement and compliance with securities laws. Stock repurchases may be funded with
existing cash balances, internal cash flow, and borrowings under the credit facility.
Assets
As of December 31, 2007, we had estimated proved reserves of 78.8 MMBbl of oil and 613.5 Bcf of
natural gas. Prices in effect on December 31, 2007, used to estimate proved reserves were $6.80 per MMBtu of
gas and $95.98 per barrel of oil. On an equivalent basis, our proved reserves were 1,086.5 BCFE as of
December 31, 2007, an increase of 17 percent from 927.6 BCFE at the end of the prior year. The increase in
proved reserves in 2007 was the result of development activities and acquisitions. On an equivalent basis,
77 percent of our proved reserves are classified as proved developed as of year-end. Total proved oil and gas
reserves have a before income tax PV-10 value of $3.9 billion and a standardized measure value, which includes
the effect of income taxes, of $2.7 billion (a reconciliation between these two amounts is shown under Reserves in
Part I, Items 1 and 2). During 2007, our average daily production was 181.0 MMcf of gas and 18.9 MBbl of oil,
for an average equivalent production rate of 294.5 MMCFE per day, which is a new annual record for us. We
sold certain non-core oil and gas properties subsequent to year end; all production and reserve information
presented is before the impact of this sale unless otherwise noted.
Our reserve replacement percentage – including sales for 2007 was 248 percent, which includes
1.4 BCFE of asset sales that occurred during the year. Our reserve replacement percentage – excluding sales was
249 percent. We acquired 94.8 BCFE of proved reserves through acquisitions in 2007, the majority of which
relate to the two Olmos shallow gas acquisitions in South Texas. We believe the use of the phrase “reserve
replacement percentage” is widely understood by those who make investment decisions related to the oil and gas
exploration business. We believe that this measure is useful in evaluating and comparing exploration and
production companies and provides a measure of the growth of a company. The Glossary includes a definition of
“reserve replacement percentage” and description of how it is calculated.
In 2007, we invested a total of $926.1 million on drilling activities and acquisitions. This was 15 percent
higher than the $805.5 million invested in 2006. Drilling investments, including leasing activity, in 2007 of
$740.9 million comprised 80 percent of our total capital investment budget for the year and compares to
$522.6 million in 2006. The increase in drilling activity was driven primarily by development of the Sweetie
Peck asset in the Permian Basin that was acquired in late 2006 as well as increases in activity in our ArkLaTex
region. We invested $185.2 million on acquisitions in 2007, the majority of which related to the two acquisitions
in South Texas targeting the Olmos shallow gas play.
We have $626 million budgeted for development and exploration investments in 2008, which is a decrease
of 16 percent from the $740.9 million invested in drilling activities in 2007. The decrease in investment year over
year is a reflection of our goal to improve our capital efficiency and to invest within our cash flow from operations in
order to maintain financial flexibility so that we can deploy additional capital where warranted in order to make
accretive acquisitions, repurchase stock, or repay debt.
4
Our operations are currently concentrated in five core operating areas in the United States. The following
table summarizes the production and proved reserves and PV-10 value of our core operating areas as of
December 31, 2007.
ArkLaTex
Mid-
Continent
Gulf
Coast
Permian
Rocky
Mountain
2007 Proved Reserves:
Oil (MMBbl)
Gas (Bcf)
Equivalents (BCFE)
Relative percentage
Proved Developed %
1.0
163.9
170.1
15%
52%
1.5
192.4
201.3
19%
88%
0.9
111.3
116.8
11%
48%
20.0
34.7
154.7
14%
69%
55.4
111.2
443.6
41%
92%
Total
78.8
613.5
1,086.5
100%
77%
PV-10 Value (in millions)
Relative percentage
$380.3
10%
$585.5
15%
$361.6
9%
$824.2
21%
$1,709.6
45%
$3,861.2
100%
2007 Production:
Oil (MMBbl)
Gas (Bcf)
Equivalent (BCFE)
Avg. Daily Equivalents
(MMCFE/d)
Relative percentage
0.1
13.0
13.8
37.8
13%
0.5
30.9
34.0
93.2
31%
0.2
9.0
1.4
2.4
10.3
10.7
28.2
10%
29.3
10%
4.7
10.8
38.7
106.0
36%
6.9
66.1
107.5
294.5
100%
Note: The table above includes production and proved reserves related to non-core assets that were divested on
January 31, 2008. The properties divested were primarily in the Mid-Continent and Rocky Mountain regions. These non-
core properties contributed 5.0 BCFE of production during 2007 and represented 40.4 BCFE of proved reserves at
December 31, 2007.
ArkLaTex Region. St. Mary’s operations in the ArkLaTex region are managed from our office in
Shreveport, Louisiana. The ArkLaTex region was the first operating office for the Company, originating from an
acquisition in 1992. For years the activities of this region focused on the tight sandstone Cotton Valley and Travis
Peak formations in the region. In recent years, we have utilized horizontal wells in the development of limestone
carbonates found in the region, particularly the James Lime formation.
The ArkLaTex region invested $149.8 million in 2007 on exploration, development, and acquisition
activities, which is 70 percent higher than the $88.0 million spent in 2006. The primary drivers of this increase in
capital were increased activity levels in our James Lime and Cotton Valley programs during the year. In the
St. Mary operated horizontal James Lime program, we operated one rig continuously throughout 2007. We
continued to see solid results in proven development areas and had two successful wells that extended the play
westward by approximately 75 miles. The Cotton Valley programs at Elm Grove and Terryville fields were areas of
significant investment in 2007, although these are operated by other companies. At Elm Grove Field, advancements
such as 20-acre increased density drilling, commingling of production of the Cotton Valley and Hosston formations,
and horizontal drilling have benefited us, particularly as development has moved into areas where we have larger
working interests. Even though operations at Terryville Field are more difficult due to the formation being deeper
and more highly pressured than the Cotton Valley formation at Elm Grove Field, operations in the field were highly
successful in 2007 and allowed for sustained activity during the year. The region’s 2007 production increased
31 percent to 13.8 BCFE. Our proved reserves at year-end 2007 were 170.1 BCFE, a seven percent increase over
2006 year-end proved reserves of 159.5 BCFE. On a forward looking basis, we expect that proved reserves in this
area will be booked on 20-acre spacing as the in-fill program at Elm Grove Field continues and additional locations
become permitted. We have not however booked these locations as proved reserves at year end due to the Securities
and Exchange Commission technical requirement of needing to have an “alternate unit” permitting process
completed prior to booking such items as proved reserves.
5
The Elm Grove Field is the highest value field in the ArkLaTex region at year-end 2007, with proved
reserves of 85.3 BCFE and a PV-10 value of $161.3 million. Elm Grove comprises roughly 42 percent of the
region’s PV-10 value and approximately four percent of our entire PV-10 value. We own interests in 382
producing wells in the field with many of those wells having uphole recompletion potential in the future. Our
working interest in the field is as high as 37 percent; higher working interests are located in the southern portion
of the acreage where recent activity has been occurring. Reserves in this field are primarily natural gas.
Our capital budget for the ArkLaTex region in 2008 is $161 million, 51 percent of which will be operated
by us. The largest portion of this year’s budget relates to Cotton Valley programs, where 50 percent of the region’s
capital will be deployed. Of the capital allocated for Cotton Valley programs, 60 percent will be invested at Elm
Grove Field where development continues to be highly successful. Development of the field on 20-acre spacing
continues to drive activity levels, and a successful horizontal well completed at the end of 2007 could set the stage
for horizontal development at Elm Grove Field. The remaining Cotton Valley allocation for 2008 will be split
roughly evenly between the program at Terryville Field and the St. Mary operated program at Carthage. Our
operated horizontal James Lime program will represent 34 percent of the region’s 2008 budget. We plan to operate
two drilling rigs throughout the year, with plans to drill more than 20 horizontal James Lime wells in 2008.
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 and our primary focus in the region is currently on the Atoka and Granite
Wash formations. 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, although the Wapanucka limestone and
Cromwell sandstone also appear to have commercial potential. The Mid-Continent region oversees our assets in
Constitution South Field in Jefferson County, Texas. Our long history of operations and proprietary geologic
knowledge in the region enables us to sustain economic development and exploration programs despite periods of
adverse industry conditions. We apply current technology through the use of hydraulic fracturing, innovative well
completion techniques, and horizontal drilling to accelerate production and associated cash flow from the region’s
tight gas reservoirs and developing plays.
In 2007, we invested $185.7 million in the Mid-Continent region on exploration, development, and
acquisition activity, which is 13 percent less than the $214.3 million deployed in 2006. Throughout 2007, we
maintained a consistent level of activity in the Arkoma Basin working on the Woodford shale program as we
continued to refine our understanding of the play. We decreased our activity in the Atoka/Granite Wash
development program as we developed more cost efficient completion designs for these wells. Mid-Continent
production in 2007 was 34.0 BCFE, an increase of 14 percent from the 29.8 BCFE produced in 2006. Proved
reserves at the end of 2007 were 201.3 BCFE, an increase of 18 percent from the 170.7 BCFE report for the prior
year.
The Constitution South Field is the highest value field in the Mid-Continent region with reserves of
15.2 BCFE and a PV-10 value of $115.1 million. This field also contributed 8.6 BCFE of production in 2007,
which represents approximately eight percent of our total production. Three wells, the Paggi Broussard #1, the
Paggi Broussard # 2, and the Loretta B. Casey #1, comprise the majority of reserves, PV-10 value, and production
in the Constitution South Field. These wells historically have performed better than anticipated and we have a
history, including at year-end 2007, of recognizing upward performance revisions in our proved reserves at this
field.
The 2008 capital expenditure budget for the Mid-Continent region is $135.0 million, 69 percent of which
we will operate. The largest component of the budget is our program targeting the Woodford shale using
horizontal wells in the Arkoma basin, where roughly 30 percent of the region’s budget will be invested. After
mixed results in the horizontal Woodford shale program in the first half of 2007, we had a series of successful
wells in the latter part of the year which we believe validates our understanding of the well and completion design
being used currently in this program. Our budget anticipates that we will drill ten horizontal Woodford wells with
two operated rigs in the first half of 2008, and continue to participate with our partners in outside operated wells.
With continued success in the play, we have the ability to increase activity and our capital investment in the
program in the latter part of 2008. In 2008, we plan to continue with an exploration program in the Anadarko
6
Basin that yielded encouraging results in 2007. This exploration program targets deeper formations of the basin.
We also plan to deploy approximately 27 percent of the region’s 2008 capital budget to drill six exploratory test
wells in this program. In the Western Oklahoma Washes program in the Anadarko Basin, which we have referred
to previously as the Mayfield development area, we plan to invest roughly 17 percent of the year’s budget in this
program that targets the Atoka and Granite Wash formations. The area is a known hydrocarbon province, and
efforts in 2008 will be directed toward improving the geotechnical effort applied to the program and revising
drilling and completion techniques.
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 lands yielded $3.7 million of gross oil and gas royalty revenue in 2007. Our Gulf Coast regional presence
expanded as a result of the acquisition of King Ranch Energy, Inc. in 1999. During 2007 we reached a significant
inflection point in this region as it shifted from an office centered on geotechnically driven exploration to one
focused on repeatable development and exploitation with our acquisition of two Olmos shallow gas assets in
South Texas. The Gulf Coast region is run from our office in Houston, Texas.
Our capital expenditures for exploration, development, and acquisition activity in the Gulf Coast region
grew significantly from $65.5 million in 2006 to $278.5 million in 2007, primarily driven by two significant
acquisitions. The majority of our 94.8 BCFE of acquisitions, classified as purchases of minerals in place, were in
the Gulf Coast region. These were the $150.3 million Rockford acquisition that closed in October 2007 and the
$30.4 million Catarina acquisition which closed in April 2007, both of which target the Olmos shallow gas
formation and are located in the greater Maverick Basin in Southwestern Texas. Final year-end reserve estimates
related to these acquisitions are lower than the initial estimates we previously disclosed, partly due to the fact that
our presentation of reserves at the time of the acquisition was on a dry gas basis whereas our annual report on
Form 10-K disclosures utilize a wet gas presentation. This accounted for approximately ten BCFE of the
difference in volumes, without any impact to value. The remaining difference was based on our final year-end
assessment of proved non-producing reserves and our proved undeveloped reserves, which were each lower than
the amounts estimated at the time of acquisition. Our emphasis in 2007 was on the successful integration of our
newly acquired properties. While the core focus of the region shifted toward onshore projects, we continued to be
active offshore in 2007. A previously discovered intermediate deepwater project, Zloty, began production late in
2007 and we continue to work to advance other intermediate deepwater projects in which we are a partner. We
were also active closer to shore with a mixed program that included the successful Reno, Clement, and Amber
Jack wells. Gulf Coast production in 2007 was 10.3 BCFE, an increase of six percent from the 9.7 BCFE
produced in 2006. Proved reserves at the end of 2007 were 116.8 BCFE, an increase of 263 percent from the
32.2 BCFE reported for the prior year. The disparity between the production growth and reserve growth for the
Gulf Coast region in 2007 is attributable to the acquisitions previously discussed.
The most significant asset in the Gulf Coast region is the Gold River project area that was acquired in
October of 2007 as part of the Rockford acquisition. The Gold River project area has 104 producing wells as of
year end. At December 31, 2007, this project area had a PV-10 value of $136.9 million with 53.6 BCFE of
proved reserves and accounts for approximately four percent of our entire PV-10 value. The acquisition of these
assets, together with the Catarina assets, represents the most recent resource play entry for the Company.
Our development and exploration budget in the Gulf Coast region for 2008 is $80 million and is focused
primarily on the development of the Olmos assets acquired in 2007. St. Mary will operate 75 percent of the
planned capital investment next year. Roughly $38 million, or 47 percent, of the budget will be dedicated to grass
roots Olmos wells and approximately $10 million, or 12 percent, of the budget will be spent on Olmos
recompletions.
Permian Basin Region. The Permian Basin area covers a significant portion of western Texas and eastern
New Mexico and is one of the major producing basins in the United States. Our holdings in the Permian Basin
began with a series of property acquisitions in 1996. In December 2006, we made a $240.6 million acquisition of
predominately oil properties in the Sweetie Peck project area. To manage the significant increase in operated
properties associated with the Sweetie Peck acquisition, we opened a regional office in Midland, Texas in early
February 2007.
7
In 2007, we spent $135.1 million in the region. The majority of this capital was deployed to develop
projects that target the Wolfberry tight oil play, which targets the stacked carbonate Wolfcamp and Spraberry
formations found in the basin. We participated in two substantial Wolfberry programs during 2007 – the operated
Sweetie Peck program and the outside operated program at Halff East. We operated between two and five drilling
rigs at Sweetie Peck throughout 2007. At Halff East, our operating partner had two drilling rigs running throughout
the year. We also invested capital in the Parkway and East Shugart Delaware waterflood projects. Production in the
region increased 234 percent over the prior year, from 3.2 BCFE in 2006 to 10.7 BCFE in 2007. Proved reserves as
of the end of 2007 were 154.7 BCFE, which is an increase of nine percent from 2006 year-end reserves of
142.2 BCFE.
As of the end of December 2007, the Sweetie Peck assets in the Permian Basin represented a PV-10 value
of $438.0 million with 77.7 BCFE of proved reserves. This accounts for approximately 11 percent of our entire
PV-10 value. The Sweetie Peck assets had 106 producing wells and 47 proved undeveloped reserve locations as
of the end of 2007.
The capital budget for 2008 in the region is $120 million, of which 74 percent will be operated by us. Of
this amount, roughly $103 million, or 86 percent, will be invested in Wolfberry projects. At Sweetie Peck, we plan
to spend approximately $77 million operating three drilling rigs continuously throughout the year. Included in this
amount are investment dollars to test several 40-acre pilot areas, which if successful could add meaningful proved
reserves. At Halff East, we will invest approximately $25 million with our operating partner. We will also invest a
small amount of capital in several smaller programs, including our Delaware waterfloods.
Rocky Mountain Region. St. Mary has conducted operations in the Williston Basin in eastern Montana
and western North Dakota since 1991. The region is managed by our office in Billings, Montana. In recent years,
we have expanded our operations into the Greater Green River, Powder River, Big Horn, and Wind River basins
of Wyoming through a series of acquisitions. The largest growth in the region came in late 2002 and early 2003
with significant property acquisitions from Choctaw, Burlington Resources, and Flying J. These transactions
brought with them a tremendous acreage position that has precipitated additional growth in this region.
Including the Hanging Woman Basin coalbed methane project, we invested $178.3 million in 2007 on
exploration, development, and acquisitions in the Rocky Mountain region, compared to $161.3 million in 2006.
The 2007 program was focused on a horizontal development in the Mississippian formations of the Williston
Basin, and the drilling of Bakken formation infill locations in Montana and Red River locations. Additionally,
2007 saw an acceleration of drilling at Hanging Woman Basin. Proved reserves for the Rocky Mountain region
were 443.6 BCFE at year-end, up five percent from 422.9 BCFE as of year end 2006. Production in the Rocky
Mountain region for 2007 was 38.7 BCFE. Total regional production was down two percent from 39.5 BCFE in
2006.
Included in the Rocky Mountain region is the coalbed methane project at Hanging Woman Basin. This
program is of particular interest because of the large resource potential on our leasehold. In 2007, we invested
$35.7 million at Hanging Woman Basin compared to $30.4 million in 2006. Proved reserves in this project grew
20 percent in 2007 to 40.2 BCFE, 75 percent of which were proved developed. Hanging Woman Basin had
33.4 BCFE in proved reserves at December 31, 2006, 91 percent of which were proved developed. Production
was 3.0 BCFE for the year ended 2007, up 49 percent from production in 2006.
The Elm Coulee Field is the highest value field in the region at year-end 2007, with 92 producing wells
and proved reserves of 42.4 BCFE and a PV-10 value of $236.5 million. The reserves in this field are
predominately oil and the Bakken is the formation of primary interest. This field comprises approximately
six percent of our entire PV-10 value.
Our capital budget for the Rocky Mountain region is $130 million for 2008, with roughly $24 million
budgeted for activities for Hanging Woman Basin coalbed methane. We will operate roughly 65 percent of our
planned regional investment in 2008. In the conventional Rockies program, several vertical wells and two
recompletions in the Red River are planned for the year. We also plan to drill a small number of horizontal
Bakken wells in and around our historic Bakken development areas in Montana. Workover and recompletion
8
operations are planned in our Wind River Basin and Big Horn Basin oil properties. At the outside operated
Atlantic Rim coalbed methane play in the Green River Basin, we expect to see activity ramp up since regulatory
and environmental delays appear to have been resolved. At Hanging Woman Basin, we plan to moderate our
drilling activity in 2008 and monitor and evaluate the results of the shallow and intermediate pods and deep
horizontal programs from previous year’s drilling efforts.
Reserves
The following table presents summary information with respect to the estimates of our proved oil and gas
reserves for each of the years in the three-year period ended December 31, 2007. For all years presented
Netherland, Sewell and Associates, Inc. (“NSAI”) prepared the reserve information for the Company’s coalbed
natural gas projects at Hanging Woman Basin in the northern Powder River Basin and St. Mary’s non-operated
coalbed methane interest in the Green River Basin. We engaged Ryder Scott Company, L.P. to review internal
engineering estimates for 80 percent of the PV-10 value of our proven conventional oil and gas reserves in 2007 and
2006. In 2005, Ryder Scott Company, L.P. prepared the reserve estimates for at least 80 percent of the PV-10 value
of our conventional oil and gas assets. St. Mary personnel prepared the reserve estimates for the remainder of all
properties. 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. 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. You should read
the following table 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 Securities and Exchange Commission, since the beginning of the last fiscal year.
Proved Reserves Data:
Oil (MMBbl)
Gas (Bcf)
BCFE
Standardized measure of discounted
future net cash flows (in thousands)
PV-10 value (in thousands)
Proved developed reserves
Reserve replacement – including sales
of reserves
2007
78.8
613.5
1,086.5
As of December 31,
2006
74.2
482.5
927.6
2005
62.9
417.1
794.5
$ 2,706,914
$ 3,861,187
77%
$ 1,576,437
$ 2,157,449
78%
$ 1,712,298
$ 2,494,169
82%
248%
244%
256%
Reserve replacement – 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
247%
10.0
249%
10.1
256%
9.1
preceding 12-month period.
9
The following table reconciles the standardized measure of discounted future net cash flows to the PV-10
value. The difference has to do with the PV-10 value measure excluding the impact of income taxes. Please see
the definitions of standardized measure of discounted future net cash flows and PV-10 value in the Glossary.
Standardized measure of discounted
future net cash flows
$ 2,706,914
$ 1,576,437
$ 1,712,298
2007
As of December 31,
2006
(In thousands)
2005
Add: 10 percent annual discount, net of
income taxes
Add: Future income taxes
Undiscounted future net cash flows
Less: 10 percent annual discount without
tax effect
PV-10 value
Production
2,321,983
2,316,637
1,238,308
1,125,955
1,286,568
1,448,444
$ 7,345,534
$ 3,940,700
$ 4,447,310
(3,484,347)
(1,783,251)
(1,953,141)
$ 3,861,187
$ 2,157,449
$ 2,494,169
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,
2006
2005
2007
6.9
66.1
107.5
18.9
181.0
294.5
67.56
6.74
8.48
62.60
7.63
8.71
1.31
0.14
0.58
$
$
$
$
$
$
$
$
$
10
6.1
56.4
92.8
16.6
154.7
254.2
59.33
6.58
7.88
56.60
7.37
8.18
1.25
0.12
0.54
5.9
51.8
87.4
16.2
141.9
239.4
53.18
8.08
8.40
50.93
7.90
8.14
0.99
0.09
0.56
$
$
$
$
$
$
$
$
$
Productive Wells
As of December 31, 2007, St. Mary had working interests in 2,365 gross (1,125 net) productive oil wells
and 4,199 gross (1,405 net) productive gas wells. Productive wells are either producing wells or wells capable of
commercial production although currently shut-in. One or more completions in the same wellbore are counted as
one well. A well is categorized under state reporting regulations as an oil well or a gas well based upon the ratio of
gas to oil produced when it first commenced production, and such designation may not be indicative of current
production.
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:
2007
Years Ended December 31,
2006
2005
Gross
Net
Gross
Net
Gross
Net
Development:
Oil
Gas
Non-productive
Exploratory:
Oil
Gas
Non-productive
164
518
30
712
77.91
204.62
13.18
295.71
81
446
31
558
3
9
5
17
1.92
4.01
2.58
8.51
-
304.22
10
15
8
33
35.32
178.97
10.65
224.94
5.53
3.68
1.81
11.02
83
379
29
491
38.09
152.69
9.12
199.90
8
5
5
18
1.91
0.86
2.32
5.09
-
204.99
Farmout or non-consent
Total (1)
1
730
2
593
-
235.96
18
527
(1) Does not include three and nine gross wells completed on St. Mary's fee lands during 2006 and 2005,
respectively, in which we have only a royalty interest.
11
Acreage
The following table sets forth the gross and net acres of developed and undeveloped oil and gas leases,
fee properties, mineral servitudes, and lease options held by St. Mary as of December 31, 2007. Undeveloped
acreage includes leasehold interests that may already have been classified as containing proved undeveloped
reserves.
Arkansas
Colorado
Louisiana
Mississippi
Montana
New Mexico
North Dakota
Oklahoma
Texas
Utah (3)
Wyoming
Other (4)
Louisiana Fee Properties
Louisiana Mineral Servitudes
Total (5)
Developed Acres (1)
Net
Gross
Undeveloped Acres (2)
Total
Gross
Net
Gross
Net
2,917
3,098
136,606
6,646
70,462
5,440
150,968
302,820
215,056
480
152,209
2,201
1,048,903
10,818
10,173
20,991
1,069,894
408
2,496
45,913
727
45,523
2,608
97,691
91,523
78,310
115
97,129
873
463,316
10,818
5,740
16,558
479,874
207
20,269
52,349
59,907
426,161
1,480
198,104
107,018
163,849
3,574
395,083
3,836
1,431,837
14,096
4,411
18,507
1,450,344
68
12,530
15,081
21,435
286,841
1,187
110,786
56,735
97,019
831
226,410
1,090
830,013
14,096
4,048
18,144
848,157
3,124
23,367
188,955
66,553
496,623
6,920
349,072
409,838
378,905
4,054
547,292
6,037
2,480,740
24,914
14,584
39,498
2,520,238
476
15,026
60,994
22,162
332,364
3,795
208,477
148,258
175,329
946
323,539
1,963
1,293,329
24,914
9,788
34,702
1,328,031
(1) Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation.
Developed acreage in certain 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 proved reserves.
(3) St. Mary holds an overriding royalty interest in an additional 36,021 gross acres in Utah.
(4) Includes interests in Alabama, Kansas, Nebraska and South Dakota.
(5) Subsequent to December 31, 2007, St. Mary divested certain non-core properties, which included leases
covering approximately 155,400 and 53,900 developed gross and net acres, respectively, and 67,100 and
38,400 undeveloped gross and net acres, respectively. Additionally, St. Mary also divested its overriding
royalty interest in 36,000 gross acres in Utah.
Major Customers
During 2007 and 2006, no customer individually accounted for ten percent or more of the Company’s total
oil and gas production revenue. During 2005, sales to Tesoro Refining and Marketing individually accounted for
13 percent of the Company’s total oil and gas production revenue.
Employees and Office Space
As of February 15, 2008, we had 438 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. We lease
approximately 77,000 square feet of office space in Denver, Colorado for our executive and administrative
12
offices, of which approximately 10,000 square feet is subleased. We lease approximately 22,000 square feet of
office space in Tulsa, Oklahoma; approximately 21,000 square feet in Shreveport, Louisiana; approximately
20,000 square feet in Houston, Texas; approximately 12,000 square feet in Midland, Texas; approximately 36,000
square feet in Billings, Montana; 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, increased summertime
demand for electricity is beginning to place an increasing demand on storage volumes. Crude oil and the demand
for heating oil are also impacted by generally higher prices in the winter – although oil is much more driven by
global supply and demand. Seasonal anomalies such as mild winters sometimes lessen these fluctuations. The
impact of seasonality has somewhat been exacerbated by the overall supply and demand economics related to
crude oil because there is a narrow margin of production capacity in excess of existing worldwide demand.
Competition
The oil and gas industry is intensely competitive. This is particularly true in the competition for acquisitions
of prospective oil and natural gas properties and oil and gas reserves. We believe that our leasehold position
provides a sound foundation for a solid drilling program. Our competitive position also depends on our geological,
geophysical, and engineering expertise, and our financial resources. We believe that the location of our leasehold
acreage, our exploration, drilling, and production expertise, and the experience and knowledge of our management
and industry partners enable us to compete effectively in our core operating areas. Notwithstanding our talents and
assets, we still face stiff competition from a substantial number of major and independent oil and gas companies that
have larger technical staffs and greater financial and operational resources than we do. Many of these companies not
only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also
have refining operations, market refined products, own drilling rigs, and generate electricity. We also compete with
other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for the
drilling and completion of wells. Consequently, drilling equipment may be in short supply from time to time.
Currently, access to incremental drilling equipment in certain regions is difficult but is not, at this time, anticipated
to have any material negative impact on our ability to deploy our drilling capital budget for 2008. We are seeing
signs of loosening rig availability, although it is quite specific by region. Finally, we also compete for people.
Throughout the industry, the need for talented people has grown at a time when the number of people available is
constrained. We are not insulated from this resource constraint and we have to be willing to compete in this market
in order to be successful.
Government Regulations
Our business is subject to various federal, state, and local laws and governmental regulations that may be
changed from time to time in response to economic or political conditions. Matters subject to regulation include the
issuance of drilling permits, discharge permits for drilling operations, drilling bonds, reports concerning operations,
the spacing of wells, unitization and pooling of properties, taxation, and environmental protection. From time to
13
time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of
oil and gas wells below actual production capacity in order to conserve supplies of oil and gas.
Energy Regulations. Our sale of natural gas is affected by the availability, terms, and cost of transportation.
The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. While
the rules and regulations of the Federal Energy Regulatory Commission (FERC) have in the past greatly affected the
production and sale of natural gas, the direct impact on the upstream exploration and production segment of the
energy industry has changed to allow market forces to set the price paid for natural gas. FERC regulations continue
to affect the midstream and transportation segments of the industry and thus can have an indirect impact of the sales
price we receive for natural gas production. There is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue. We do not believe that we will be more materially
affected by any action taken by the FERC or Congress than other natural gas producers and marketers with whom
we compete.
Certain operations we conduct involve federal minerals administered by the Minerals Management
Service (MMS). The MMS issues leases covering such lands through competitive bidding. These leases contain
relatively standardized terms and require compliance with federal laws and detailed MMS regulations. For
offshore operations, lessees must obtain MMS approval for exploration plans and development and production
plans prior to the commencement of such operations. In addition to permits required from other agencies such as
the Coast Guard, the Army Corps of Engineers, and the Environmental Protection Agency, lessees must obtain a
permit from the MMS prior to the commencement of drilling. Lessees must also comply with detailed MMS
regulations governing, among other things:
• Engineering and construction specifications for offshore production facilities
• Safety procedures
• Flaring of production
• Plugging and abandonment of Outer Continental Shelf (OCS) wells
• Calculation of royalty payments and the valuation of production for this purpose
• Removal of facilities.
To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post
substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or
other surety can be substantial, and we may not be able to continue to obtain bonds or other surety in all cases.
Under certain circumstances the MMS may require our operations on federal leases to be suspended or
terminated.
Many of the states in which we conduct our oil and gas drilling and production activities regulate such
activities by requiring, among other things, drilling permits and bonds and reports concerning operations. The
laws of these states also govern a number of environmental and conservation matters, including the handling and
disposing of waste material, plugging and abandonment of wells, restoration requirements, unitization, pooling of
interests in natural gas and oil properties, and establishment of maximum rates of production from natural gas and
oil wells. States generally have the ability to prorate production to the market demand for oil and natural gas;
however, this is not currently occurring.
Environmental Regulations. Our operations are subject to numerous existing federal, state, and local laws
and regulations governing environmental quality and pollution control. These laws and regulations may require that
permits be obtained before drilling commences, restrict the types, quantities, and concentration of various substances
that can be released into the environment in connection with drilling and production activities, 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
14
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 such laws and regulations.
Our coalbed methane gas production is similar to our traditional natural gas production as to the physical
producing facilities and the product produced. However, the subsurface mechanisms that allow the gas to move
to the wellbore and the producing characteristics of coalbed methane wells are very different from traditional
natural gas production. Unlike conventional gas wells, which require a porous and permeable reservoir,
hydrocarbon migration, and a natural structural and/or stratigraphic trap, coalbed methane gas is trapped in the
molecular structure of the coal itself until released by pressure changes resulting from the removal of in situ
water. Frequently, coalbeds are partly or completely saturated with water. As the water is removed, internal
pressures on the coal are decreased, allowing the gas to desorb from the coal and flow to the wellbore. Unlike
traditional gas wells, new coalbed methane wells often produce water for several months and then, as the water
production decreases, natural gas production increases.
Coalbed methane gas production requires state permits for the use of well-site pits and evaporation ponds
for the disposal of produced water. Groundwater produced from the coal seams can generally be discharged into
arroyos, surface waters, well-site pits, and evaporation ponds without a permit if it does not exceed surface
discharge permit levels, and meets state and federal primary drinking water standards. All of these disposal
options require an extensive third-party water sampling and laboratory analysis program to ensure compliance
with state permit standards. Where water of lesser quality is involved or the wells produce water in excess of the
applicable volumetric permit limits, additional disposal wells may have to be drilled to re-inject the produced
water back into underground rock formations.
A portion of our acreage at the Hanging Woman Basin coalbed methane project is on federal lands in
Montana. We are subject to delays in permitting associated with the completion of a supplemental Environmental
Impact Statement covering the contemplation of phased development on federal leases in Montana. We are also
affected by considerations for sage grouse that are native to the area. Each of these issues has the potential to
impact the timing of our permitting and drilling operations associated with development of Hanging Woman
Basin.
To date we have not experienced any material adverse effect on our operations from obligations under
environmental laws and regulations. We believe that we are in substantial compliance with currently applicable
environmental laws and regulations and that continued compliance with existing requirements would not have a
material 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 capital resources to fund
capital expenditures
• The drilling of wells and other exploration and development activities, as well as possible future
acquisitions
• Reserve estimates and the estimates of both future net revenues and the present value of future net
revenues that are implied by those reserve estimates
15
• Future oil and natural gas production estimates
• Our outlook on future oil and natural gas prices
• 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 and our outlook on 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” 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” in Item 1A of this Form 10-K, and include such factors as:
• The volatility and level of realized oil and natural gas prices
• Our ability to replace reserves and sustain production
• Unexpected drilling conditions and results
• Unsuccessful exploration and development drilling
• The availability of economically attractive exploration, development, and property acquisition
opportunities and any necessary financing
• The risks of hedging strategies
• Lower prices realized on oil and natural gas sales resulting from our commodity price risk management
activities
• The uncertain nature of the expected benefits from acquisitions and divestitures of oil and natural gas
properties, including uncertainties in evaluating oil and natural gas reserves of acquired properties and
associated potential liabilities
• The imprecise nature of oil and natural gas reserve estimates
• Uncertainties inherent in projecting future rates of production from drilling activities and acquisitions
• Drilling and operating service availability
• Uncertainties in cash flow
• The financial strength of hedge contract counterparties
• The negative impact that lower oil and natural gas prices could have on our ability to borrow
• The potential effects of increased levels of debt financing
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• Our ability to compete effectively against other independent and major oil and natural gas companies
• Litigation, environmental matters, the potential impact of government regulations, and the use of
management estimates.
We caution you that forward-looking statements are not guarantees of future performance and that actual
results or developments 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. Within our website’s financial information section
we make available free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable
securities laws. These materials are made available as soon as reasonably practical after we electronically file
such materials with or furnish such materials to the SEC.
We also make available through our website’s corporate governance section our Corporate Governance
Guidelines, Code of Business Conduct and Ethics, and the Charters for our Board of Directors’ Audit Committee,
Compensation Committee, Executive Committee, and Nominating and Corporate Governance Committee. These
documents are also available in print to any stockholder who requests them. Requests for these documents may
be submitted to:
St. Mary Land & Exploration Company
Investor Relations
1776 Lincoln Street, Suite 700
Denver, Colorado 80203
Telephone: (303) 863-4322
http://www.stmaryland.com
Information on our website is not incorporated by reference into this Form 10-K and should not be
considered part of this document.
Glossary of Oil and Natural Gas Terms
The oil and natural gas terms defined in this section are used throughout this Form 10-K.
2-D seismic or 2-D data. Seismic data that is acquired and processed to yield a two-dimensional cross-section of the
subsurface.
3-D seismic or 3-D data. Seismic data that is acquired and processed to yield a three-dimensional picture of the
subsurface.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet, used in reference to natural gas.
BCFE. Billion cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six
Mcf of natural gas (including natural gas liquids) to one Bbl of oil.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas (including
natural gas liquids) to one Bbl of oil.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a
stratigraphic horizon known to be productive.
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Dry hole. A well found to be incapable of producing either oil or natural gas in sufficient commercial quantities.
Exploratory well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in
a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir
beyond its known horizon.
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 or stratigraphic condition.
Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated by dividing the amount of total
capital expenditures for oil and natural gas activities, including the effect of asset retirement obligations, by the
amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and
revisions of previous estimates during the same period. The information for this calculation is included in Note 13
of Part IV, Item 15 of this Form 10-K.
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.
Hydraulic fracturing. A procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand)
into the formation under high pressure. This increases the permeability and porosity of the targeted formation.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural
gas (including natural gas liquids) to one Bbl of oil.
MMBOE. One million barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural
gas (including natural gas liquids) to one Bbl of oil.
Mcf. One thousand cubic feet, used in reference to natural gas.
MCFE. One thousand cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of
six Mcf of natural gas (including natural gas liquids) to one Bbl of oil.
MMcf. One million cubic feet, used in reference to natural gas.
MMCFE. One million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of
six Mcf of natural gas (including natural gas liquids) to one Bbl of oil.
MMBtu. One million British Thermal Units. A British Thermal Unit is the amount of heat required to raise the
temperature of a one-pound mass of water by one degree Fahrenheit.
Net acres or net wells. The sum of our fractional working interests owned in gross acres or gross wells.
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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.
OCS. Outer Continental Shelf in the Gulf of Mexico.
PV-10 value. The present value of estimated future gross revenue to be generated from the production of estimated
net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of
the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without
giving effect to non-property related expenses such as general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion, and amortization, discounted using an annual discount rate of
ten percent. While this measure does not include the effect of income taxes as it would in the use of the standardized
measure calculation, it does provide an indicative representation of the relative value of the Company on a
comparative basis to other companies and from period to period.
Productive well. A well that is producing oil or natural gas or that is capable of commercial production.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved reserves. The estimated quantities of oil, natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or
from existing wells where a relatively major expenditure is required for recompletion.
Recompletion. The completion in an existing wellbore in a formation other than that in which the well has
previously been completed.
Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual
production for the preceding 12-month period.
Reserve replacement percentage – excluding sales of reserves. The sum of reserve extensions and discoveries,
reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production
for that same period of time. This is believed to be a useful non-GAAP measure that is widely utilized within the
exploration and production industry as well as by investors. It is an easily calculable number and is representative of
the relative success a company is having in replacing its production from its declining asset base as well as its ability
to grow the overall company.
Reserve replacement percentage – including sales of reserves. The sum of sales of reserves, reserve extensions and
discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided
by production for that same period of time. This is believed to be a useful non-GAAP measure that is widely
utilized within the exploration and production industry as well as by investors. It is an easily calculable number and
is representative of the relative success a company is having in replacing its production from its declining asset base
as well as its ability to grow the overall company.
Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage of gross income from oil
and natural gas produced and sold unencumbered by expenses relating to the drilling, completing, and operating of
the affected well.
Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of oil and natural gas
production free of costs of exploration, development, and production operations.
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Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved
reserves based on year-end prices, costs, and statutory tax rates, and a ten percent annual discount rate. The
information for this calculation is included in the note regarding disclosures about oil and gas producing activities
contained in the Notes to Consolidated Financial Statements included in this Form 10-K.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains
estimated net proved reserves.
Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating
activities on the property and to share in the production, sales, and costs.
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 a decline in prices could hurt 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 and borrowing capacity, as well as the amount and value of our oil and natural
gas reserves.
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:
• Worldwide and domestic supplies of oil and natural gas
• The ability of the members of the Organization of Petroleum Exporting Countries to agree to and
maintain oil price and production controls
• Pipeline, transportation, or refining capacity constraints in a regional or localized area may impact the
realized price for oil or natural gas
• Political instability or armed conflict in oil or natural gas producing regions
• The price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural
gas
• Worldwide and domestic economic conditions
• The level of consumer demand for hydrocarbons
• Productive capacity of the industry as a whole
• The availability of transportation facilities
• Weather conditions
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• The price and availability of alternative fuels
• Governmental regulations and taxes.
These factors and the volatility of oil and natural gas markets make it very 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 material adverse effect on us.
If we are not able to replace reserves, we will not be able to sustain production.
Our future operations depend on our ability to find, develop, and acquire oil and natural gas reserves that
are economically recoverable. Our properties produce oil and natural gas at a declining rate over time. In order to
maintain current production rates we must locate and develop or acquire new oil and natural gas reserves to
replace those being depleted by production. In addition, competition for the acquisition of producing oil and
natural gas properties is intense and many of our competitors have financial and other resources needed to
evaluate and integrate acquisitions that are substantially greater than those available to us. Therefore, we may not
be able to acquire oil and natural gas properties that contain economically recoverable reserves, or we may not be
able to acquire such properties at prices acceptable to us. Without successful drilling or acquisition activities, our
reserves, production, and revenues will decline over time.
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 are actively seeking oil and
natural gas properties 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 and technical 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 or 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 people. The need for talented people across all disciplines in the industry has grown at
a time when the number of people available is 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. Reserve 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 reserves is
complex. This process requires significant decisions and assumptions in the evaluation of available geological,
geophysical, engineering, and economic data for each reservoir. These estimates are dependent on many variables
and therefore changes often occur as these variables evolve. Therefore, these estimates are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, production taxes, development
expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will most likely vary
from those estimated. Any significant variance could materially affect the estimated quantities of and present
values related to proved reserves disclosed by us, and the actual quantities and present values may be less than we
have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history,
results of exploration and development activity, prevailing oil and natural gas prices, costs to develop and operate
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properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to
hydrocarbon drainage from production by operators on adjacent properties.
As of December 31, 2007, approximately 23 percent, or 250.2 BCFE, of our estimated proved reserves
were proved undeveloped and approximately 11 percent or 116.0 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
recover our proved undeveloped reserves, an estimated $234 million of capital expenditures will be spent during
2008. Production revenues from proved developed non-producing reserves will not be realized until some time in
the future. In order to bring production on-line for our proved developed non-producing reserves, we estimate
capital expenditures of $12 million for 2008. 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 capital expenditure
budget for 2008 is directed towards projects that are not yet classified within the construct of proved reserves as
defined by Regulation S-X of the Securities and Exchange Commission.
You should not assume that the PV-10 value and standardized measure of discounted future net cash
flows included in this Form 10-K represent the current market value of our estimated proved oil and natural gas
reserves. Management has based the estimated discounted future net cash flows from proved reserves on prices
and costs as of the date of the estimate, in accordance with SEC requirements, whereas actual future prices and
costs may be materially higher or lower. For example, values of our reserves as of December 31, 2007, were
estimated using a calculated sales price of $6.80 per MMBtu of natural gas (NYMEX Henry Hub spot price) and
$95.98 per Bbl of oil (NYMEX West Texas Intermediate spot price). We then adjust this base price to ensure we
consider the appropriate basis and location differentials as of that date in estimating our proved reserves. During
2007, our monthly average realized natural gas prices, excluding the effect of hedging, were as high as $7.83 per
Mcf and as low as $5.42 per Mcf. For the same period our monthly average realized oil prices before hedging
were as high as $91.53 per Bbl and as low as $48.88 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 governmental 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 and risks to which our business and
the oil and natural gas industry in general are subject.
Our producing 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
22
entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally,
we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and
warranties.
In addition, significant acquisitions can change the nature of our operations and business if the acquired
properties have substantially different operating and geological characteristics or are in different geographic
locations than our existing properties. To the extent acquired properties are substantially different than our
existing properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be
limited.
Integrating acquired properties and businesses involves a number of other special risks, including the risk
that management may be distracted from normal business concerns by the need to integrate operations and
systems as well as retain and assimilate additional employees. Therefore, we may not be able to realize all of the
anticipated benefits of our acquisitions.
Exploration and development drilling may not result in commercially productive reserves.
Oil and natural gas drilling and production activities are subject to numerous risks, including the risk that
no commercially productive oil or natural gas will be found. The cost of drilling and completing wells is often
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 and 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. 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.
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
23
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.
Our future drilling activities may not be successful. Our overall drilling success rate or our drilling
success rate for activity 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 transactions may limit the prices that we receive for oil and natural gas sales and involve other risks.
To manage our exposure to price risks in the sale of our oil and natural gas, 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. 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. In addition, these transactions may
expose us to the risk of financial loss in certain circumstances, including instances in which:
• Our production is less than expected
• There is a widening of price differentials between delivery points for our production and the delivery
point assumed in the hedge arrangement
• The counterparties to our hedge contracts fail to perform under the contracts.
Some of our hedging agreements may also require us to furnish cash collateral, letters of credit, or other
forms of performance assurance in the event that mark-to-market calculations result in settlement obligations by
us to the counterparties, which could impact our liquidity and capital resources. In addition, some of our hedging
transactions use derivative instruments that may involve basis risk. Basis risk in a hedging contract occurs when
the index upon which the contract is based is more or less variable than the index upon which the hedged asset is
based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes
of production may have more or less variability than the regional price index used for the sale of that production.
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 future net revenues, we must write
down the costs of each such field to our estimate of its fair market value. Unproved properties are evaluated at the
lower of cost or fair market value. Accordingly, a significant decline in oil or natural gas prices or unsuccessful
exploration efforts could cause a future write-down of capitalized costs.
We review the carrying value of our properties quarterly based on prices in effect as of the end of each
quarter or as of the time of reporting our results. 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.
Substantial capital is required to replace our reserves.
We need to 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, our success in locating and acquiring new reserves, and prices paid for oil
24
and natural gas. If oil or natural gas prices decrease or we encounter operating difficulties that result in our cash
flows from operations being less than expected, we may have to 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. The proceeds offered to us for
potential divestitures may not always be of acceptable value to us.
If our revenues were to decrease due to lower oil or natural gas prices, decreased production, or other
reasons, and if we could not obtain capital through our revolving credit facility, other acceptable debt or equity
financing arrangements, or sale of non-core assets, our ability to execute our development plans, replace our
reserves, or maintain production levels could be greatly limited.
The markets for raising public debt are quite constrained at the current time, given the overall liquidity
concerns arising from the widely reported difficulties in the sub-prime and leveraged loan markets. While we
continue to believe that our secured revolving credit facility will be sufficient for the foreseeable future, we must
continually monitor the overall condition of the markets as a whole and remain cognizant that an overall pressure
on the credit markets has the risk of increasing the cost of borrowings or decreasing the availability of new capital
or the capacity of existing debt instruments.
A decrease in oil or natural gas prices could limit our ability to borrow under our revolving credit facility.
Our revolving credit facility currently has a maximum commitment amount of $500 million, subject to a
borrowing base of $1.25 billion that the lenders periodically redetermine based on the bank groups’ assessment of
the value of our oil and natural gas properties, which in turn is based in part on oil and natural gas prices. Lower
oil or natural gas prices in the future could limit our borrowing base and reduce our ability to borrow under the
credit facility.
Our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse
economic conditions, and make it more difficult for us to make payments on our debt.
As of December 31, 2007, we had $287.5 million of total long-term senior unsecured debt outstanding
under our 3.50 % Senior Convertible Notes due 2027 and $285.0 million of secured debt outstanding under our
revolving credit facility. As of February 15, 2008, we had an outstanding balance of $180.0 million drawn against
our revolving credit facility resulting in $320.0 million of available debt capacity under our revolving credit facility,
assuming the borrowing conditions of this facility were met. Our long-term debt represented 40 percent of our total
book capitalization as of December 31, 2007. The decrease in the borrowings subsequent to year end is a result of
using the net proceeds from the sale of non-core properties on January 31, 2008. Our revolving credit facility has a
maximum loan amount of $500 million, a current borrowing base of $1.25 billion, and we have elected a current
commitment amount of $500 million.
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 associated with our debt rather than to productive investments.
• Limiting our operating flexibility due to financial and other restrictive covenants, including
restrictions on incurring additional debt, creating liens on our properties, making acquisitions, and
paying dividends
25
• 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 to 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, 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.
Our debt instruments, including our revolving credit 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.
In addition, our revolving credit facility is subject to periodic borrowing base redeterminations. We could
be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing
base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient
funds and are otherwise unable to negotiate renewals of our borrowing base or arrange new financing, we may be
forced to sell significant assets.
We are subject to operating and environmental risks and hazards that could result in substantial losses.
Oil and natural gas operations are subject to many risks, including well blowouts, craterings, explosions,
uncontrollable flows of oil, natural gas or well fluids, fires, adverse weather such as hurricanes in the Gulf Coast
region, freezing conditions, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of
toxic gas, and other environmental risks and hazards. If any of these types of events occurs, we could sustain
substantial losses.
Under certain limited circumstances we may be liable for environmental damage caused by previous owners
or operators of properties that we own, lease, or operate. As a result, we may incur substantial liabilities to third
parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or
acquisitions or cause us to incur losses.
We maintain insurance against some, but not all, of these potential risks and losses. We have significant
but limited coverage for sudden environmental damages. We do not believe that insurance coverage for the full
potential liability that could be caused by sudden environmental damages or insurance coverage for environmental
damage that occurs over time is available at a reasonable cost. In addition, pollution and environmental risks
generally are not fully insurable. Further, we may elect not to obtain other insurance coverage under
circumstances where we believe that the cost of available insurance is excessive relative to the risks presented.
Accordingly, we may be subject to liability or may lose substantial portions of certain properties in the event of
environmental or other damages. If a significant accident or other event occurs and is not fully covered by
insurance, we could suffer a material loss.
Following the severe Atlantic hurricanes in 2004 and 2005, the insurance markets suffered significant
losses. As a result, the availability of coverage and the cost at which such coverage will be available in the future is
uncertain, and such coverage has become substantially more expensive.
26
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. To cover the various obligations of leaseholders
in federal waters, federal authorities generally require that leaseholders have substantial net worth or post bonds or
other acceptable assurances that such obligations will be met. The cost of these bonds or other assurances can be
substantial, and we may not be able to obtain bonds or other assurances in all cases. Under limited circumstances,
federal authorities may require any of our ongoing or planned operations on federal leases to be delayed, suspended
or terminated. Any such delay, suspension or termination could have a material adverse effect on our operations.
Our coalbed methane development at Hanging Woman Basin is particularly affected, as a portion of our acreage is
on federal lands in Montana which have been subject to delays in permitting.
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.
In addition, recent studies have suggested that emissions of certain gases, commonly referred to as
“greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component
of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are
examples of greenhouse gases. In response to these studies, the U.S. Congress is considering legislation to reduce
emissions of greenhouse gases. In addition, at least nine states in the Northeast and five states in the West have
separately taken legal measures to reduce emissions of greenhouse gases, primarily through the planned
development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs.
Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts et al. v. Environmental
Protection Agency et al., the U.S. Environmental Protection Agency must reconsider whether it is required to
regulate greenhouse gas emissions from motor vehicles even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse
gases fall under the Federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of
greenhouse gas emissions from stationary sources under certain Clean Air Act programs. Passage of climate
change legislation or other regulatory initiatives by Congress or various states or the adoption of regulations by
the EPA or analogous state agencies that restrict emissions of greenhouse gases, including methane or carbon
dioxide, in areas in which we conduct business could adversely affect our operations and the demand for our
products.
We depend on transportation facilities owned by others.
The marketability of our oil and natural gas production depends in part on the availability, proximity, and
capacity of pipeline transportation systems owned by third parties. The lack of available transportation capacity on
these systems and facilities could result in the shutting-in of producing wells, the delay or discontinuance of
27
development plans for properties, or lower price realizations. Although we have some contractual control over the
transportation of our production, material changes in these business relationships could materially affect our
operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies,
changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, and general economic
conditions could adversely affect our ability to produce, gather, and transport oil and natural gas.
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, 2007 to February 15, 2008, the closing daily sales price of our common stock as reported
by the New York Stock Exchange ranged from a low of $31.80 per share to a high of $44.07 per share. We expect
our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our
control. These factors include:
• Changes in oil or natural gas prices
• Variations in quarterly drilling, recompletions, acquisitions, and operating results
• Changes in financial estimates by securities analysts
• Changes in market valuations of comparable companies
• Additions or departures of key personnel
• Future sales of our common stock
• Changes in the national and global economic outlook.
We may fail to meet expectations of our stockholders and/or of securities analysts at some time in the
future, and our stock price could decline as a result.
Our certificate of incorporation and bylaws have provisions that discourage corporate takeovers and could prevent
stockholders from receiving a takeover premium on their investment.
Our certificate of incorporation and bylaws 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 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.
28
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
material adverse effect on our stock price. As of February 15, 2008, 62,915,531 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 2,367,914 shares of our common stock were outstanding, of
which 2,360,414 were exercisable. These options are exercisable at prices ranging from $4.63 to $20.87 per
share. In addition, restricted stock units providing for the issuance of up to a total of 682,446 shares of our
common stock were outstanding. As of February 15, 2008, there were 63,020,524 shares of common stock
outstanding, which is net of 1,009,712 treasury shares.
We may not always pay dividends on our common stock.
The payment of future dividends remains in the discretion of the Board of Directors and will continue to
depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of
dividends is subject to covenants in our credit facility, including a covenant regarding the level of our current ratio
of current assets to current liabilities and a limit on the annual dividend rate that we may pay to no more than
$0.25 per share. The Board of Directors may determine in the future to reduce the current semi-annual dividend
rate of $0.05 per share or discontinue the payment of dividends altogether.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
St. Mary has no unresolved comments from the SEC staff regarding its periodic or current reports under
the Securities Exchange Act of 1934.
ITEM 3.
LEGAL PROCEEDINGS
From time to time, we may be involved in litigation relating to claims arising out of our operations in the
normal course of business. As of the date of this report, no legal proceedings are pending against us that we believe
individually or collectively could have a materially adverse effect upon our financial condition, results of operations
or cash flows.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of our security holders during the fourth quarter of 2007.
29
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 15, 2008.
Name
Age Position
Chief Executive Officer and President
Executive Vice President and Chief Operating Officer
Senior Vice President - Chief Financial Officer and Secretary
Senior Vice President and Regional Manager
Senior Vice President and Regional Manager
Senior Vice President and Regional Manager
58
49
41
43
49
41
50 Vice President - Business Development
Anthony J. Best
Javan D. Ottoson
David W. Honeyfield*
Mark D. Mueller
Stephen C. Pugh
Paul M. Veatch
Jerold M. Hertzler
Gregory T. Leyendecker 50 Vice President - Regional Manager
52 Vice President - Regional Manager
Lehman E. Newton, III
55 Vice President - Land and Legal and Assistant Secretary
Milam Randolph Pharo
57 Vice President - Human Resources and Administration
Garry A. Wilkening
39
Mark T. Solomon
Controller
*Mr. Honeyfield has announced that he will resign from his position of Senior Vice President - Chief Financial Officer and
Secretary effective March 21, 2008, in order to pursue an opportunity in an unrelated industry.
Each executive officer has held his respective position during the past five years, except as follows:
Anthony J. Best joined St. Mary in June 2006 as President and Chief Operating Officer. In
December 2006, Mr. Best relinquished his position as Chief Operating Officer when Javan D. Ottoson was
elected to that office. Mr. Best was elected Chief Executive Officer of St. Mary in February 2007. From
November 2005 to June 2006, Mr. Best was developing a business plan and attempting to raise capital for a start-
up exploration and production entity. From 2003 to October 2005, Mr. Best was President and Chief Executive
Officer of Pure Resources, Inc., a subsidiary of Unocal Corporation, 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 public, private, and
small startup exploration and production 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 20 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. Mr. Ottoson managed the Permian Basin assets for Pure Resources, Inc., a subsidiary of Unocal
Corporation, and its successor owner, Chevron, from July 2003 to April 2006. From April 2000 to July 2003, Mr.
Ottoson owned and operated a homebuilding company in Colorado and ran his family farm. Prior to 2000, Mr.
Ottoson worked for ARCO in management and operational roles. These roles included President - ARCO China,
Commercial Director of ARCO British, and Vice President of Operations and Development - ARCO Permian.
David W. Honeyfield was appointed as Chief Financial Officer in May 2005 and Senior Vice President in
March 2007. Mr. Honeyfield joined St. Mary in May 2003 as Vice President - Finance, Treasurer and Secretary.
Prior to joining St. Mary, Mr. Honeyfield was Controller and Chief Accounting Officer of Cimarex Energy from
September 2002 to May 2003 and Controller and Chief Accounting Officer of Key Production Company, Inc.,
which was acquired by Cimarex in September 2002. Prior to joining Key Production Company in April 2002,
Mr. Honeyfield was a senior audit manager with Arthur Andersen LLP in Denver. Mr. Honeyfield had been with
Arthur Andersen since January 1991.
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
30
been in the energy industry for 21 years and was Vice President and General Manager at Samson Exploration Ltd.
in Calgary, Canada from September 2006 to September 2007. Mr. Mueller was Vice President and General
Manager for Samson Canada Ltd. from April 2005 until its sale in August 2006. 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 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.
Stephen C. Pugh joined St. Mary as Senior Vice President and Regional Manager of the ArkLaTex region
in July 2007. Stephen Pugh has over 26 years of experience in the oil and gas industry. He was a Managing
Director for Scotia Waterous in the Houston office from July 2006 to July 2007. Prior to joining Scotia Waterous,
Mr. Pugh had over 17 years of experience in acquisition and divestiture, operations and engineering with
Burlington Resources (subsequently ConocoPhillips). His most recent title there 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.
Paul M. Veatch was appointed Senior Vice President and Regional Manager of the Mid-Continent region
in March 2006. Mr. Veatch joined St. Mary in April 2001 as Regional Acquisition and Divestiture Engineer of
the ArkLaTex region. He was Manager of Engineering from April 2003 to August 2004 and Vice President –
General Manager, ArkLaTex from August 2004 to March 2006. Prior to joining St. Mary, Mr. Veatch worked in
various engineering and supervisory roles at Burlington Resources from November 1994 to April 2001. Prior to
joining Burlington Resources, Mr. Veatch held various engineering and operations positions for Arco Oil & Gas
Company (subsequently Vastar Resources) in Louisiana and Texas from July 1989 until November 1994.
Jerold M. Hertzler was appointed Vice President - Business Development in March 2007. Mr. Hertzler
joined St. Mary in October 1998 as Manager of Reservoir Engineering. He assumed the role of Acquisitions
Manager in July 2003 and was promoted to Director and Business Development in March 2005. Mr. Hertzler
entered the petroleum industry in December of 1979 and has served in various operations and reservoir
engineering roles since then, including nine years with Tenneco Oil Company and seven years with Meridian Oil
Company.
Gregory T. Leyendecker was appointed Vice President - Regional Manager of the Gulf Coast region in
July 2007. Mr. Leyendecker joined St. Mary in December 2006 as Operations Manager for the Gulf Coast region
in Houston. Mr. Leyendecker has worked for 27 years in the energy industry and held various positions with the
Unocal Corporation from 1980 until its acquisition in 2005. During this time he was the Asset Manager for
Unocal Gulf Region USA from 2003 to June 2004 and Production and Reservoir Engineering Technology
Manager for Unocal from June 2004 to August 2005. He was appointed Drilling and Workover Manager for
Chevron’s San Joaquin Valley business unit in Bakersfield, California in August 2005 and held this position until
January 2006. Immediately prior to joining St. Mary, Mr. Leyendecker was Vice President of Drilling
Management Services for Enventure Global Technology, a position he held from February 2006 to
November 2006.
Lehman E. Newton III joined St. Mary in December 2006 as General Manager for the Midland office and
was appointed Vice President - Regional Manager of the Permian region in June 2007. Mr. Newton has over
27 years of exploration and production experience in engineering, operations and business development. From
November 2005 to November 2006 Mr. Newton served as Project Manager for one of Chevron’s largest projects
in the continental United States. 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 exploration and production company in the Permian Basin, 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.
31
Garry A. Wilkening was appointed Vice President - Human Resources and Administration in
November 2007 and served as Vice President of Administration from January 2007 to November 2007.
Mr. Wilkening relinquished his position as Controller in January 2007 when Mark T. Solomon was elected to that
office. Mr. Wilkening was Vice President - Administration and Controller from 1999 to 2007.
Mark T. Solomon was appointed Controller in January 2007. Mr. Solomon joined St. Mary in 1996. He
served as Financial Reporting Manager from February 1999 to September 2002, Assistant Vice President of
Financial Reporting from September 2002 to May 2006 and Assistant Vice President and Assistant Controller
from May 2006 to January 2007. Prior to joining St. Mary, Mr. Solomon was an auditor with Ernst & Young.
Executive officers generally are elected at the regular meeting of the Board immediately following the
annual stockholders meeting, to serve for the ensuing year or until their successors are duly qualified and elected.
The executive officers of St. Mary do not have fixed terms and serve at the discretion of the Board of Directors.
Any officer elected by the Board may be removed by the Board with or without cause, subject to any contractual
rights of the person so removed.
Mr. Best has an employment agreement with St. Mary. Upon any termination of the employment of
Mr. Best by St. Mary for any reason other than death, disability, or misconduct by Mr. Best, St. Mary is generally
obligated to continue to pay his base salary and insurance benefits for a period of two years after termination. In
addition, upon commencement of employment, Mr. Best received a cash bonus and a special restricted stock
award of 20,000 shares that are vested immediately and not subject to forfeiture. Over the next two years
Mr. Best is also eligible to earn additional restricted shares in varying amounts, a portion of which are based on the
Company’s net asset value growth.
There are no family relationships between any executive officer and any other executive officer or
director. There are no arrangements or understandings between any officer and any other person pursuant to
which that officer was elected.
PART II
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information. St. Mary's common stock is currently traded on the New York Stock Exchange under
the symbol SM. The range of high and low sales prices for the quarterly periods in 2007 and 2006, as reported by
the New York Stock Exchange.
Quarter Ended
December 31, 2007
September 30, 2007
June 30, 2007
March 31, 2007
December 31, 2006
September 30, 2006
June 30, 2006
March 31, 2006
High
Low
$
$
44.50
37.15
40.19
38.20
40.85
43.92
45.59
44.69
$
$
35.40
31.20
34.91
33.55
33.43
34.77
34.38
34.70
32
PERFORMANCE GRAPH
The following performance graph compares the cumulative total stockholder return on St. Mary’s common
stock for the period December 31, 2002, to December 31, 2007, with the cumulative total return of the Dow Jones
U.S. Exploration and Production Broad Index, and the Standard & Poor’s 500 Stock Index.
COMPARE 5-YEAR CUMULATIVE TOTAL RETURN
AMONG ST. MARY LAND & EXPLORATION COMPANY
s
r
a
l
l
o
D
500.0
450.0
400.0
350.0
300.0
250.0
200.0
150.0
100.0
50.0
-
2002
2003
2004
2005
2006
2007
SM 2007
DJUSOS 2007
S&P 2007
The preceding information under the caption “Performance Graph” shall be deemed to be “furnished” but
not “filed” with the Securities and Exchange Commission.
Holders. As of February 15, 2008, the number of record holders of St. Mary's common stock was 116.
Based on inquiry, management believes that the number of beneficial owners of our common stock is approximately
21,700.
Dividends. St. Mary has paid cash dividends to stockholders every year since 1940. Semi-annual dividends
of $0.025 per share were paid in each of the years 1998 through 2004. Semi-annual dividends of $0.05 per share
were paid in 2005, 2006 and 2007. We expect that our practice of paying dividends on our common stock will
continue, although the payment of future dividends will continue to depend on our earnings, capital requirements,
financial condition, and other factors. In addition, the payment of dividends is subject to covenants in our credit
facility, including the requirement that we maintain certain levels of stockholders’ equity and the limitation of our
annual dividend rate to no more than $0.25 per share per year. Dividends are currently paid on a semi-annual basis.
Dividends paid totaled $6.3 million in 2007.
Restricted Shares. Aside from Rule 144 restrictions on shares for insiders, shares subject to transfer
restrictions under the provisions of the Employee Stock Purchase Plan, restricted shares issued to directors under the
Non-Employee Director Stock Compensation Plan, and restricted shares issued to directors under the 2006 Equity
Incentive Compensation Plan (the “2006 Equity Plan”), St. Mary has no restricted shares outstanding as of
December 31, 2007.
33
Equity Compensation Plans. St. Mary has the 2006 Equity Plan under which options and shares of
St. Mary common stock are authorized for grant or issuance as compensation to eligible employees, consultants,
and members of the Board of Directors. Our stockholders have approved this plan. See Note 7 - Compensation
Plans in the Notes to Consolidated Financial Statements included in Part IV, Item 15 of this report for further
information about the material terms of these plans. The following table is a summary of the shares of common
stock authorized for issuance under our equity compensation plans as of December 31, 2007:
( a )
( b )
Number of
securities to be
issued upon exercise
of outstanding
options, warrants,
and rights
Plan Category
2006 Equity Incentive Compensation Plan
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))
Stock Options and
Incentive Stock
Options
Restricted Stock Plan
Employee Stock Purchase Plan
Equity compensation plans not
approved by security
holders
Total
______________
2,385,500
684,264
-
$
12.62
N/A
-
-
2,560,224
1,599,811
(1)
(1)
(2)
-
-
3,069,764
$
12.62
-
4,160,035
(1) In May 2006 the stockholders approved the 2006 Equity Plan to authorize the issuance of restricted stock, restricted
stock units, non-qualified stock options, incentive stock options, stock appreciation rights, and stock-based awards
to key employees, consultants, and members of the Board of Directors of St. Mary or any affiliate of St. Mary. The
2006 Equity Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the
St. Mary Land & Exploration Company Incentive Stock Option Plan, the St. Mary Land & Exploration Company
Restricted Stock Plan, and the St. Mary Land & Exploration Company Non-Employee Director Stock
Compensation Plan (collectively, the “Predecessor Plans”). All grants of equity are now made out of the 2006
Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a
Predecessor Plan immediately prior to the effective date of the 2006 Equity Plan continues to be governed solely by
the terms and conditions of the instruments evidencing such grants or issuances. Awards granted in 2007, 2006,
and 2005 under the 2006 Equity Plan and the Predecessor Plans were 135,138, 527,678, and 209,238, respectively.
(2) Under the St. Mary Land & Exploration Company Employee Stock Purchase Plan, eligible employees may purchase
shares of the Company’s common stock through payroll deductions of up to 15 percent of their eligible
compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the
first or last day of the purchase period, and shares issued under the Employee Stock Purchase Plan are restricted for
a period of 18 months from the date issued. The Employee Stock Purchase Plan is intended to qualify under Section
423 of the Internal Revenue Code. There have been 29,534, 26,046, and 28,447 shares issued under this plan in
2007, 2006, and 2005, respectively.
34
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, 2007, 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
Average Price Paid
per Share
Total Number of
Shares Purchased as
Part of Publicly
Announced Program
Maximum Number
of Shares that May
Yet be Purchased
Under the
Program(2)
January 1, 2007 –
March 31, 2007
April 1, 2007 -
June 30, 2007
July 1, 2007 -
September 30, 2007
October 1, 2007 -
October 31, 2007
November 1, 2007 -
November 30, 2007
December 1, 2007 -
December 31, 2007
Total October 1, 2007 -
December 31, 2007
Total
-
-
791,816 (1)
-
-
1,400
1,400
793,216
$
$
$
$
$
$
$
$
-
-
-
-
32.76
790,816
-
-
37.52
37.52
32.76
-
-
1,400
1,400
792,216
6,000,000
6,000,000
5,209,184
5,209,184
5,209,184
5,207,784
5,207,784
5,207,784
(1) Includes a total of 1,000shares purchased by Anthony J. Best, St. Mary’s President and Chief Executive Officer, in
open market transactions that were not made pursuant to our stock repurchase program. The table does not include
the 678 shares purchased by Mr. Best under the Company’s employee stock purchase plan.
(2) In July 2006 the Company’s 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, the Company has Board authorization to repurchase 5,207,784 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 stock repurchases are subject to covenants in our bank credit facility, including the requirement that
we maintain certain levels of stockholders’ equity.
35
ITEM 6.
SELECTED FINANCIAL DATA
The following table sets forth supplemental selected financial and operating data for St. Mary as of the dates
and for the periods indicated. The financial data for each of the five years presented were derived from the
consolidated financial statements of St. Mary. The following data should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of Operations," which includes a
discussion of factors materially affecting the comparability of the information presented, and in conjunction with
St. Mary's consolidated financial statements included in this report. In March 2005 the Company’s Board of
Directors approved a two-for-one stock split in the form of a stock dividend whereby one additional share of
common stock was distributed for each common share outstanding. The stock dividend was distributed on
March 31, 2005, to shareholders of record as of the close of business on March 21, 2005. All share and per share
amounts for all prior periods presented herein have been reclassified to reflect this stock split.
Years Ended December 31,
2007
2006
(In thousands, except per share data)
2005
2004
2003
Total operating revenues
$ 990,094
$ 787,701
$ 739,590
$ 433,099
$ 393,708
Income before cumulative effect of
change in accounting principle
Net income per share:
Basic
Diluted
$ 189,712
$ 190,015
$ 151,936
$
92,479
$
90,140
$
$
3.07
2.94
$
$
3.38
2.94
$
$
2.67
2.33
$
$
1.60
1.44
$
$
1.53
1.40
Total assets at year end
$ 2,571,680
$ 1,899,097
$ 1,268,747
$ 945,460
$ 735,854
Long-term obligations:
Line of credit
Senior convertible notes
$ 285,000
$ 287,500
$ 334,000
99,980
$
Cash dividends declared and paid
per common share
$
0.10
$
0.10
$
$
$
-
99,885
0.10
$
$
$
37,000
99,791
$
$
11,000
99,696
0.05
$
0.05
36
Supplemental Selected Financial and Operational Data:
2007
Years Ended December 31,
2004
2005
(In thousands, except per share data)
2006
2003
Balance Sheet Data:
Total working capital (deficit) $
Total stockholders’ equity
(92,604)
$ 863,345
22,870
$
$ 743,374
4,937
$
$ 569,320
$ 12,035
$ 484,455
3,101
$
$ 390,653
Weighted-average
shares outstanding:
Basic
Diluted
Reserves:
Oil (MMBbl)
Gas (Mcf)
MCFE
Production and Operational:
Oil and gas production
61,852
64,850
78.8
613.5
1,086.5
56,291
65,962
74.2
482.5
927.6
56,907
66,894
62.9
417.1
794.5
57,702
66,894
56.6
319.2
658.6
62,467
71,069
47.8
307.0
593.7
revenues, including hedging $ 936,577
$ 758,913
$ 711,005
$ 413,318
$ 365,114
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:
$ 218,208
$ 227,596
60,149
$
$ 176,590
$ 154,522
38,873
$
$ 142,873
$ 132,758
32,756
$
$ 95,518
$ 92,223
$ 22,004
$ 88,509
$ 81,960
$ 21,197
6.9
66.1
107.5
6.1
56.4
92.8
5.9
51.8
87.4
4.8
46.6
75.4
4.5
49.7
76.9
67.56
6.74
$
$
59.33
6.58
$
$
53.18
8.08
$
$
39.77
5.85
$
$
29.40
5.12
62.60
7.63
$
$
56.60
7.37
$
$
50.93
7.90
$
$
32.53
5.52
$
$
26.96
4.89
1.31
0.14
0.58
2.12
0.56
$
$
$
$
$
1.25
0.12
0.54
1.67
0.42
$
$
$
$
$
0.99
0.09
0.56
1.52
0.37
$
$
$
$
$
0.81
0.10
0.36
1.22
0.29
$
$
$
$
$
0.77
0.09
0.29
1.07
0.28
$
$
$
$
$
$
$
$
$
$ 237,162
$ 204,319
$ (247,006) $ (196,939)
(3,707)
$
1,435
$
From operations
Used in investing
From (used in) financing
$ 630,792
$ (803,872)
$ 215,126
$ 467,700
$ (724,719)
$ 243,558
$ 409,379
$ (339,779)
(61,093)
$
37
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 the United States. We earn 95 percent of our revenues
and generate our cash flows from operations primarily from the sale of produced natural gas and crude oil. Our
oil and gas reserves and operations are concentrated primarily in various Rocky Mountain basins, including the
Williston, Big Horn, Wind River, Powder River and Greater Green River basins; the Mid-Continent Anadarko
and Arkoma basins; the Permian Basin; the tight sandstone reservoirs of East Texas and North Louisiana; South
Texas assets targeting the Olmos shallow gas formation; 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.
In 2007, we achieved the following financial and operational results:
• Average daily gas production of 181.0 MMcf per day, up 17 percent from 2006. Average daily
oil production of 18.9 MBbl per day, up 14 percent from 2006. Average total equivalent daily
production was 294.5 MMCFE which was an annual record for the Company.
• Estimated proved reserves of 78.8 MMBbls of oil and 613.5 Bcf of natural gas, or 1,086.5 BCFE,
as of December 31, 2007. This was an increase of 17 percent from year-end 2006 proved
reserves of 927.6 BCFE.
• Diluted earnings per share for 2007 were $2.94 on net income of $189.7 million. This reflects a
slight decrease in net income when compared to 2006. The earnings per share benefited from the
0.8 million shares acquired by the Company during 2007.
• Cash flow from operating activities of $630.8 million, an increase of 35 percent from 2006.
• Debt to capitalization ratio is 40 percent. The 2007 amount does not consider proceeds from our
divestiture of non-core assets that closed on January 31, 2008, described in Note 3 of Part IV,
Item 15 of this report, which were used to pay down outstanding bank borrowings.
Our business objective is to economically grow our production and proved reserves through development,
exploitation, and exploration activities, as well as through acquisitions of developed and undeveloped properties.
Our operations are generally funded first through cash flows from operating activities, and then borrowings under
our existing credit facility. Acquisitions may be funded with proceeds from sales of public or private debt and
equity, borrowings under our existing credit facility, and cash flow from operating activities. In 2007, we
deployed $740.9 million for development and exploration and invested $185.2 million for acquisitions of oil and
gas properties.
A major determinant of the value of our Company is the value of our proved reserves. At year-end 2007,
we had proved reserves of 1,086.5 BCFE of which 56 percent were natural gas and 77 percent were characterized
as proved developed. Based on our year-end oil and gas reserve estimation process, we determined that we added
94.8 BCFE of proved reserves through acquisitions in 2007, 96 percent of which was natural gas and 42 percent
of which was proved developed. Upward price revisions resulted in an increase of 34.5 BCFE which were driven
primarily by higher oil prices at December 31, 2007, compared to the prior year. We experienced positive
38
performance revisions of 6.4 BCFE and divested 1.4 BCFE of proved reserves. The before income tax PV-10
value of our proved reserves was $3.9 billion as of December 31, 2007. The after tax value of $2.7 billion as
represented by the standardized measure calculation is presented in Note 13 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. This
value is based on adjusted year-end pricing of $7.56 per Mcf and $88.71 per Bbl, which are up 36 percent and
65 percent, respectively, from the prior year.
Chief Executive Officer, Chief Financial Officer and Senior and Regional Management Transitions
During 2007, the Company underwent or announced personnel changes in the chief executive position and
several regional manager positions. On February 23, 2007, Mark Hellerstein, retired as Chief Executive Officer
after serving in that role since 1995. Tony Best, President of the Company, was appointed as Chief Executive
Officer on that date. Mr. Hellerstein continues to serve as the Chairman of the Board. In June 2007, Jerry Schuyler,
the Senior Vice President responsible for the Gulf Coast and Permian regions, left St. Mary to pursue other
professional opportunities. Greg Leyendecker, then Operations Manager for the Gulf Coast region, assumed
responsibility for the Gulf Coast and is now Vice President - Regional Manager of the Gulf Coast region. We also
made the Midland office a stand-alone regional office which is headed by Lehman Newton III, as Vce President -
Regional Manager of the Permian region. Mr. Leyendecker and Mr. Newton both joined St. Mary in 2006 and each
have over 25 years of management and operational experience in the oil and gas industry. In July 2007,
Stephen Pugh joined the Company as Senior Vice President - Regional Manager of the ArkLaTex region. Mr. Pugh
succeeded David Hart, who retired from St. Mary after 15 years in various roles at the Company. Mr. Pugh came to
St. Mary with over 25 years of engineering, operations, and business development experience in the oil and gas
industry. In August of this year, Robert Nance, Senior Vice President - Regional Manager of the Rocky Mountain
region announced his decision to retire in the first quarter of 2008 after more than 40 years in the oil and gas
industry. Mark Mueller joined the Company as Senior Vice President in September and is now responsible for the
Rocky Mountain region. Mr. Mueller has 20 years of management and technical experience in the oil and gas
industry. Effective January 1, 2008, Mark Mueller became the Senior Vice President and Regional Manager.
Subsequent to year end, David Honeyfield, Senior Vice President - Chief Financial Officer, announced he will
resign effective March 21, 2008, to accept an executive position in an unrelated industry.
2007 Acquisition of South Texas Oil and Natural Gas Assets
We entered the greater Maverick Basin with two acquisitions in South Texas that target the Olmos shallow
gas formation. These two acquisitions comprised the majority of the 94.8 BCFE of reserves classified as purchases
of minerals in place. These properties added a sizable inventory of lower risk drilling locations to our portfolio. The
first was the $30.0 million Catarina acquisition that closed in June 2007, in which we acquired 14.0 BCFE of proved
reserves that were 99 percent gas and 65 percent proved developed. The average working interest in these assets is
30 percent; however we are the operator of the project area. The more significant transaction was the $148.9 million
Rockford acquisition that closed in October 2007, where we have a nearly 100 percent working interest and are the
operator. As mentioned elsewhere in this report, the final year-end reserve estimates we recorded were lower than
the initial estimates we previously disclosed at the time of acquisition. We initially estimated reserves on a dry
gas basis in our previous disclosure at the time of the acquisition whereas our annual report on Form 10-K
disclosures utilize a wet gas presentation convention. This accounted for approximately ten BCFE of the
difference in volumes, without any impact on value. The remaining difference was a result of our final year end
assessment of proved non-producing reserves and our proved undeveloped reserves which were each lower than
the amounts preliminarily estimated at the time of acquisition. The Rockford properties are adjacent to the
Catarina assets. Consistent with prior acquisitions, we hedged several years of risked production related to these
assets at the time of acquisition. These assets will be managed by our Gulf Coast region based in Houston, Texas.
2007 Capital Markets Activity
In March of 2007 we called for redemption of the then outstanding $100.0 million 5.75% Senior
Convertible Notes. The notes had a conversion price of $13.00 per share. One hundred percent of the holders of the
notes elected to convert their notes into shares of common stock. As a result of the conversion, 7.7 million shares of
stock were issued to the note holders. This resulted in a decrease to long-term debt of $100.0 million, and an
39
increase to common stock associated with the conversion together with the recognition of the excess tax benefit
associated with the contingent interest feature associated with the notes. In April of 2007, we completed the private
placement of $287.5 million of 3.50% Senior Convertible Notes. The net proceeds from the 3.50% Senior
Convertible Notes were used to repay outstanding borrowings under our revolving credit facility.
Reserve Replacement, Finding Costs and Growth
Like all oil and gas exploration and production companies, we face the challenge of natural production
declines of oil and natural gas resources. An oil and gas exploration and production company depletes part of its
asset base with each unit of oil and gas it produces. Historically, we have been able to grow our production
despite this natural decline by adding more reserves through acquisitions and drilling activities than we produce.
Future growth will depend on our ability to economically continue adding reserves in excess of production.
We believe growth in net asset value per share drives appreciation in our stock price over the long term.
Our challenge is to grow net asset value per share. To accomplish this, our goal is to economically replace at least
200 percent of annual production with new reserves and to grow production by ten to 15 percent per year. In
2007, we replaced 248 percent of our production at a finding cost of $3.48 per MCFE. The reserve replacement
percentages and finding cost terms are defined in the glossary at the end of Part I, Items 1 and 2 of this report.
Excluding acquisitions, we replaced 161 percent of our production at a cost of $4.42 per MCFE. Through
acquisition activities we replaced 88 percent of production at an acquisition cost of $1.71 per MCFE. We sold
reserves representing 1.4 BCFE of our proved reserves during 2007. 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 evaluating these items over an extended
period of time is a better indication of performance. We note that aberrations, causing both relatively good and
bad results, will occur over short intervals of time. Our three-year average reserve replacement ratio – including
sales is 249 percent and our three-year average all-in finding cost is $3.01 per MCFE. Our finding cost numbers,
particularly those related to drilling activities, have been notably higher in recent years. Part of this is explained
by increases in completed well costs that have occurred in recent years which have affected all exploration and
production companies. A significant part has related to the performance of our capital investments being less than
anticipated. We will need to see an improvement in the types of projects we are pursuing and/or see an
improvement in our operating abilities to meaningfully bring our finding cost numbers down. We believe that we
have taken steps through recent acquisitions and portfolio screenings to improve the projects in which we are
investing. Our operating teams are also performing technological reviews to see where we can improve our
operations.
Sustainability in our business is dependent on the ability to create new ideas and new value year-after-
year. The challenges we face are increasingly more difficult each year as North American oil and gas production
continues to decline and other exploration and production companies compete for available reserves. We believe
we have a formula for meeting these challenges. We have placed talented geoscientists, engineers, and landmen
in each of our regional offices where their experience and knowledge of the local area can be fully utilized. We
provide a compensation package that aligns their goals with those of the Company and in turn with those of our
stockholders. We support our personnel with a strong balance sheet and fiscal and operating discipline. Even so,
we are subject to similar constraints as other companies in the exploration and production industry. Limitations to
future growth will be based on overall availability of additional qualified personnel and the generation of new
ideas and the utilization of appropriate technology to improve the economics of our operations. We believe that
we have sufficient capital resources for the foreseeable future, that we have the ability to grow our workforce, and
that we have the necessary access to drilling rigs and services to execute our drilling budget for 2008 in a
successful and profitable manner.
Oil and Gas Prices
Results of our operations and financial condition are significantly affected by oil and natural gas
commodity prices, which fluctuate dramatically. In 2007, we saw a net increase in oil prices throughout the year.
Geopolitical unrest in various producing regions overseas and concerns domestically related to refinery utilization
40
and petroleum product inventories were the principal drivers of the increase in oil prices in 2007. Natural gas
prices were moderated throughout 2007 by high levels of natural gas in storage and a lack of significant disruptive
hurricane activity during year.
Repurchase of Common Stock
We evaluate the market price of our common stock relative to our internal assessment of net asset value
per share. To the extent that the market price per share is below what we believe to be the net asset value per
share and when the trading window for the Company and executive management is open, we may repurchase
shares under the program. In 2007, we repurchased 792,216 shares of our common stock in the open market for a
weighted-average price of $32.76 per share, including commissions. These shares were purchased under a share
repurchase program approved by the Board. At the time we repurchased our shares, we entered into hedges for a
commensurate amount of our production that was represented by the share repurchase in order to lock in the
discounted price at which our shares were trading. As of the date of this filing, we are authorized to repurchase an
additional 5,207,784 million shares under this program.
Hedging Activities
We have an active hedging program in which we hedge the first two to five years of an acquisition’s
risked production. We will also on occasion enter into derivative transactions to hedge a portion of our existing
forecasted production. In October 2005, we hedged a significant portion of anticipated future production from
our current producing properties using zero-cost collars. We also hedged a portion of specific forecasted natural
gas production for 2006, 2007, and 2008 using swap contracts. Taking into account all oil and gas production
hedge contracts in place through February 15, 2008, we have hedged anticipated future production of
approximately 11 million Bbls of oil, 70 million MMBtu of natural gas, and 1 million Bbls of natural gas liquids
through the year 2011. We believe we have established an economic base for our future operations, and the
spread between the price floors and ceilings on our collars allows us to continue to participate in a higher oil and
gas price environment. Please see Note 10 of Part IV, Item 15 of this report for additional information regarding
our oil and gas hedges, and see the caption, Summary of Oil and Gas Production Hedges in Place, later in this
section.
Net Profits Plan
Payments made for distributions from the Net Profits Plan have been expensed as compensation costs in
the amounts of $31.9 million, $26.1 million, and $20.8 million for the years ended December 31, 2007, 2006, and
2005, respectively. Although increasing each year, these payments for 2007 were lower than originally budgeted
due to the effects of increased oil and gas production expense and additional capital expenditures, both of which
decreased the current impact of and delayed the timing of payout for the 2004 pool. The actual cash payments we
make are dependent on actual production, realized prices, and operating and capital costs associated with the
properties in each individual pool. Actual cash payments will be inherently different from the estimated liability
amounts. More detailed discussion is included in the analysis in the Comparison of Financial Results and Trends
sections below. An increasing percentage of the costs associated with the payments for the Net Profits Plan are
attributable to general and administrative expense as compared to exploration expense. This is a function of the
normal departure of employees who previously contributed to our past exploration efforts. We have determined that
because of the change in circumstances, a greater percentage of the payments should be recorded as general and
administrative expense beginning in 2007.
With respect to the accounting estimate of the liability associated with future estimated payments from
our Net Profits Plan, we have recorded $50.8 million of net expense for the year ended December 31, 2007,
thereby increasing the long-term liability associated with this item. This increase is related to an increase in the
estimated future prices used to calculate the liability driven by overall commodity price increases, the accretion of
the discount used for the calculation, and the addition of the 2007 pool. Additionally, we adjusted our discount
rate used to calculate the present value of future payments during the fourth quarter of 2007 from a base rate of
15 percent to 12 percent. The single largest item was the impact from the change in discount rate, which drove an
increase in the liability of $29 million as of December 31, 2007. As a result of these factors the liability increased
41
to $211.4 million at December 31, 2007. While we have forecast that this liability will again increase in 2008, it
is not possible to predict this with certainty due to the impact of commodity prices and reserve estimates on the
valuation of this estimated liability. The Company will not be adding new Net Profits Plan pools prospectively as
this benefit has been replaced with a different program, which is described in Footnote 7 of Part IV, Item 15 of
this Form 10-K. The Company will continue to make payments from the established Net Profits Plan pools, as
well as make prospective adjustments to the long-term liability, as necessary for current conditions. We expect
general and administrative expense to increase due to changes in our incentive compensation program. Beginning
in 2008, grants from the restricted stock units program and the Net Profits Plan are being replaced with grants of
market-based performance shares under our 2006 Equity Plan. Although the total value of the compensation
package to employees is essentially unchanged, we do expect general and administrative expense to increase as
the cost of the grants of performance shares under the 2006 Equity Plan will be amortized over a much shorter
time than the functional expense recorded under the Net Profits Plan.
The calculation of the estimated liability associated with the Net Profits Plan requires management to
prepare an estimate of future amounts payable from the Net Profits Plan. On a monthly basis, we calculate
estimates of the payments to be made for each individual pool. The underlying principal factors for our estimates
are forecasted oil and gas production from the properties that comprise each individual pool, price assumptions,
cost assumptions, and discount rate. In most cases, the cash flow streams used in these calculations will span
more than 20 years. The decrease in the discount rate to 12 percent was a result of the ever increasing competitive
environment for proven oil and gas properties and our assessment of the overall market for proved oil and gas
reserves. Commodity prices impact the calculated cash flows during periods after payout and can dramatically
affect the timing of the estimated date of payout of the individual pools. Our commodity price assumptions are
currently determined from an average of actual prices realized over the prior 24 months together with adjusted
NYMEX strip prices for the ensuing 12 months for a total of 36 months of data. This average is supplemented by
including the effect of realized and anticipated hedge prices for the percentage of forecasted hedged production in
the relevant period.
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, 2007, would differ by approximately
$19 million. A one percentage point decrease in the discount rate would result in an increase to the liability of
approximately $12 million, while a one percentage point increase in the discount rate would result in a decrease to
the liability of approximately $10 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.
42
The table below provides information regarding selected production and financial information for the
quarter ended December 31, 2007, and the immediately preceding three quarters. Additional details of per MCFE
costs are contained later in this section.
December 31,
2007
For the Three Months Ended
June 30,
September 30,
2007
2007
March 31,
2007
(In millions, except production sales data)
Production (BCFE)
28.5
27.5
26.0
25.5
Oil and gas production revenue,
excluding the effects of hedging
Lease operating expense
Transportation costs
Production taxes
DD&A
Exploration*
General and administrative expense*
Net income
Percentage change from previous quarter:
Production (BCFE)
Oil and gas production revenues,
excluding the effects of hedging
Lease operating expense
Transportation costs
Production taxes
DD&A
Exploration*
General and administrative expense*
Net income
$ 273.7
$ 37.8
$
3.8
$ 19.1
$ 64.8
$ 16.0
$ 15.1
$ 32.8
4%
20%
2%
19%
28%
10%
27%
(4)%
(43)%
$ 228.5
$ 36.9
$
3.2
$ 14.9
$ 59.1
$ 12.6
$ 15.8
$ 57.7
6%
6%
17%
(24)%
3%
8%
14%
(3)%
(3)%
$ 216.2
$ 31.6
$
4.2
$ 14.5
$ 54.7
$ 11.1
$ 16.3
$ 59.2
$ 193.7
$ 34.1
$
4.4
$ 13.7
$ 49.0
$ 19.0
$ 12.9
$ 40.0
2%
12%
(7)%
(5)%
6%
12%
(42)%
26%
48%
2%
7%
9%
47%
6%
10%
19%
63%
(8)%
*As a result of a change in circumstances in 2007, we have begun classifying payments made under the Net Profits Plan to
exploration overhead only for those individuals who are currently employed by us and who continue to be involved in our
exploration efforts. Therefore, the quarterly financial information presented in the above table reflects that Net Profits Plan
payments associated with the distributions under the Net Profits Plan for ex-employees were recorded to general and
administrative expense since there is no longer any functional link to exploration expense as there is by definition no periodic
costs associated with geologic and geophysical, exploration related work by those ex-employees. The impact to any prior
comparative quarter was not material.
2007 Financial Highlights
In 2007, we experienced record production and strong earnings. Our record production is the realization
of operational and investment decisions made in prior years as well as the current period. Our solid earnings
reflect our balanced production profile and high oil prices throughout the year. Our hedging program contributed
to our earnings as we received meaningful cash flows from the realization of in-the-money natural gas hedges.
Our operating margins remained strong in 2007 despite increasing operating costs. Our 2007 operating margin
was $6.68 per MCFE compared to $6.27 per MCFE in 2006.
Net income for 2007 was $189.7 million or $2.94 per diluted share compared to $190.0 million or
$2.94 per diluted share for the prior year. Net cash provided by operating activities was $630.8 million, up
35 percent from 2006. Average daily production for the year increased 16 percent to a record 294.5 MMCFE.
Our average net realized price increased $0.53 to $8.71 per MCFE. Unit costs increased for the period as lease
operating expenses increased $0.06 to $1.31 per MCFE. While general industry costs associated with drilling and
completing wells are flat or declining year over year, costs related to the ongoing operation of oil and gas
43
properties continue to experience upward pressure. This increase over last year’s comparable period is driven by
continued pressure on costs related to the servicing of wells, such as disposal and trucking, as well as workover
and labor costs. As a company with a significant oil component to our production mix, our property base
inherently requires more labor than operations that are dominated by natural gas production. Labor costs continue
to be a significant driver of our lease operating expense. In addition to the higher costs we are incurring on our
base activity, we also have been actively incurring workover expense to restore or increase production in the Gulf
Coast and Rocky Mountain regions. Per MCFE transportation costs increased $0.02 per MCFE, or 17 percent, to
$0.14 per MCFE as compared to a year ago. The increase is due to newly drilled wells with higher transportation
costs. Production taxes increased $0.04 per MCFE to $0.58 per MCFE and are a reflection of higher commodity
prices.
Depletion, depreciation, and amortization, including asset retirement obligation accretion expense, per
MCFE increased $0.45 to $2.12 per MCFE. The depletion, depreciation, and amortization increase is reflective of
higher costs on a per MCFE basis for new reserve additions relative to the base per MCFE cost of oil and gas
properties. General and administrative expense increased $0.14 per MCFE to $0.56 per MCFE. The increase in
general and administrative expenses is driven by our growing employee base and higher payments from the Net
Profits Plan. Exploration expense for 2007 was $58.7 million, which was $6.8 million higher than the
$51.9 million incurred during 2006 due to an increase in exploratory dry hole expense as well as the overall
increase in the level of exploration activity during 2007. We discuss these financial results and trends in more
detail below.
Outlook for 2008
Our anticipated exploration and development drilling budget is $626 million for 2008, which is
16 percent smaller than the $740.9 million we spent on development and exploration in 2007. The decrease in our
development and exploration budget reflects our desire to improve the capital efficiency of our investments and to
manage the balance sheet to improve financial flexibility in the future. Planned expenditures for programs that
failed to meet our expectations in 2007 were either omitted or substantially reduced in 2008. The reduced budget
for 2008 is also expected to allow for cash flow in excess of our capital investments for the year. We believe that
this will provide us the financial flexibility to accelerate successful drilling programs, pursue potential acquisition
opportunities, repurchase outstanding shares of common stock, or repay bank borrowings when the opportunity
arises. We have not budgeted any capital for acquisitions in 2008, however we believe our solid financial
condition provides us the ability to execute significant transactions we believe will be accretive to the Company.
We anticipate production for the first half of 2008 to be slightly lower than the last quarter of 2007 due to the
divestiture of non-core properties that closed subsequent to year-end. We project production will ramp up in the
second half of 2008 as many of our exploration and development projects are scheduled to come on-line in the
second half of the year.
Our 2008 capital budget was built using a NYMEX price deck of $7.00 per Mcf and $60.00 per barrel.
Current strip prices for oil and natural gas support our plans for the year. However, we are keenly aware of how
volatile oil and natural gas prices are and how quickly they can move. The cost environment related to drilling
and completing wells appears to have leveled out in the past year after several years of significant cost escalation.
Day rates for land-based drilling rigs have held flat or declined throughout the year, and the increasing number of
drilling rigs entering the market bodes well for this trend. Prices for completion services continue to be firm, but
we note new capacity is being added by incumbent providers as well as new entrants to the service sector.
Availability of drilling and completion services is not the potentially limiting condition that existed the last two
years. Prices for these services are highly dynamic, vary greatly region to region, and are influenced greatly by
commodity prices. We will continue to evaluate the economics of each well prior to the onset of drilling using the
most current commodity price and cost information available to ensure it meets our economic and operational
thresholds.
44
The information below provides some detail of our capital investment plans for 2008:
• We believe that we have the necessary capital, personnel, and service availability to execute this
program. The $626 million budgeted for drilling activities in 2008 is allocated among our core areas
as described below. Included in the discussion are highlights of the program in each region this year.
ArkLaTex - $161 million – Half of our budgeted capital investment for this region in 2008 is for
projects targeting the Cotton Valley sandstone formation. The largest component relates to activity
planned at Elm Grove Field, where 20-acre increased density drilling and Hosston and Cotton Valley
formation commingling are improving results and enhancing reserve recovery. Importantly, there has
been a successful horizontal test well at Elm Grove Field that could lead to additional upside. Also in
the Cotton Valley program, we plan to participate in twice the number of wells in Terryville Field in
2008 compared to 2007. Lastly, we will operate a small Cotton Valley program in 2008 where we
have plans to drill two vertical and three horizontal wells. The other major program in the ArkLaTex
region is our operated horizontal James Lime program. We plan to operate two drilling rigs
continuously and drill more than 20 wells throughout 2008.
Mid-Continent - $135 million – The largest part of our 2008 program in the Mid-Continent relates to
the horizontal Woodford program in the Arkoma Basin. After mixed results in the horizontal
Woodford program in the first half of 2007, we had a series of successful wells in the latter part of the
year which we believe validates our understanding of the well and completion design. We currently
plan to drill ten horizontal Woodford wells using two operated rigs in the first half of 2008, as well as
continuing to participate with our partners in outside operated wells. With continued success in the
play, we anticipate increasing our activity and our capital investment in the program in the latter part
of 2008. In the Western Oklahoma Washes program in the Anadarko Basin, which we have referred
to previously as the Mayfield development area, we plan to invest in projects in the Atoka and
Granite Wash formations. The area is a known hydrocarbon province, and efforts in 2008 will center
around refining our assessments of geotechnical aspects of the program and revising drilling and
completion techniques with an intent to lower the completion costs. We also plan to deploy
approximately one quarter of the region’s 2008 capital budget to drill six exploratory test wells which
focus on a geologic concept that was developed in 2007 which targets deeper formations in the
Anadarko Basin.
Rocky Mountain - $130 million – In the conventional Rockies program, six vertical wells and two
recompletions in the Red River are planned for 2008. We also plan to drill a small number of
horizontal Bakken wells in and around our historic Bakken development areas in Montana. We have
planned workover and recompletion operations in our Wind River Basin and Big Horn Basin oil
properties. At the outside operated Atlantic Rim coalbed methane play in the Green River Basin, we
expect to see activity ramp up since regulatory and environmental delays appear to have been
resolved. At Hanging Woman Basin, we plan to moderate our drilling activity in 2008 focusing on
completing the in-fill program in the shallow coals, monitoring the intermediate depth wells and
testing several horizontal completion techniques in the deeper coal horizontal programs.
Permian - $120 million – The vast majority of capital investment made in the Permian in 2008 will be
in properties targeting the Wolfberry section. At Sweetie Peck, we plan to operate three drilling rigs
continuously throughout the year. Included in the budget are investment dollars to test several 40-acre
pilot areas which, if successful, could add meaningful proved reserves. At the Halff East Wolfberry
development area, we will invest approximately $25 million with our operating partner. We will also be
investing a small amount of capital in several smaller programs, including the Delaware waterfloods.
Gulf Coast - $80 million – Our development and exploration budget in the Gulf Coast region for 2008
is focused on the integration and development of the two Olmos shallow gas projects that we acquired
in South Texas in 2007. Approximately half of the budgeted capital will be deployed to drill new
45
Olmos wells, with additional capital being invested in a number of recompletion opportunities. We
anticipate that the addition of this resource play will provide focus and a visible inventory of projects
for our Gulf Coast team. We will also invest capital in production facilities for an intermediate
deepwater discovery from 2005 that is expected to be brought online in early 2009.
46
A year-to-year overview of selected reserve, production and financial information, including trends:
$ 432,375
504,202
$ 936,577
$ 342,810
416,103
$ 758,913
$ 301,860
409,145
$ 711,005
23%
7%
As of and for the Years Ended
2006
2007
2005
Selected Operations Data (In Thousands, Except Price, Volume, and Per MCFE Amounts):
Total proved reserves
Oil (MMBbl)
Natural gas (Bcf)
BCFE
78.8
613.5
1,086.5
74.2
482.5
927.6
62.9
417.1
794.5
Net production volumes
Oil (MMBbl)
Natural gas (Bcf)
BCFE
Average daily production
Oil (MBbl)
Natural gas (MMcf)
MMCFE
Oil & gas production revenues
Oil production, including hedging
Gas production, including hedging
Total
Oil & gas production costs
Lease operating expenses
Transportation costs
Production taxes
Total
Average net realized sales price (1)
Oil (per Bbl)
Natural gas (per Mcf)
Per MCFE data
Average net realized price (1)
Lease operating expense
Transportation costs
Production taxes
General and administrative
Operating profit
Depletion, depreciation and amortization
6.9
66.1
107.5
18.9
181.0
294.5
6.1
56.4
92.8
16.6
154.7
254.2
5.9
51.8
87.4
16.2
141.9
239.4
$ 140,389
15,529
62,290
$ 218,208
$ 115,896
10,999
49,695
$ 176,590
$ 86,130
8,010
48,733
$ 142,873
$
$
$
$
$
62.60
7.63
$
$
56.60
7.37
$
$
50.93
7.90
8.71
(1.31)
(0.14)
(0.58)
(0.56)
6.12
$
$
8.18
(1.25)
(0.12)
(0.54)
(0.42)
5.85
$
$
8.14
(0.99)
(0.09)
(0.56)
(0.37)
6.13
2.12
$
1.67
$
1.52
Financial Information (In Thousands, Except Per Share Amounts):
Working capital (deficit)
Long-term debt
Stockholders’ equity
Net income
$ (92,604)
$ 572,500
$ 863,345
$ 189,712
$ 22,870
$ 433,980
$ 743,374
$ 190,015
$
4,937
$ 99,885
$ 569,320
$ 151,936
Basic net income per common share
Diluted net income per common share
$
$
3.07
2.94
$
$
3.38
2.94
$
$
2.67
2.33
Basic weighted-average shares outstanding
Diluted weighted-average shares outstanding
61,852
64,850
56,291
65,962
56,907
66,894
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing
$ 630,792
$ (803,872)
$ 467,700
$ (724,719)
$ 409,379
$ (339,779)
Percent Change Between
2006/2005
2007/2006
17%
17%
16%
6%
16%
6%
24%
24%
11%
4%
6%
5%
17%
7%
33%
5%
27%
(505)%
32%
16%
-%
(9)%
-%
10%
(2)%
35%
11%
11%
(7)%
-%
26%
33%
(4)%
14%
(5)%
10%
363%
334%
31%
25%
27%
26%
(1)%
(1)%
14%
113%
Activities
$ 215,126
$ 243,558
$ (61,093)
(12)%
(499)%
_____________________
(1) Includes the effects of our hedging activities.
We present this table as a summary of information relating to key indicators of financial condition and
operating performance that we believe are important.
47
The increase in our proved reserves reflects our drilling results and acquisition activity. Please see Note 13
of Part IV, Item 15 for additional details. Over time, our ability to economically replace at least 200 percent of the
total 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. We anticipate that we must continue our successful
drilling program and average one or more relatively significant acquisitions per year in the current price environment
to achieve this level of ongoing growth. The measure of our success will vary year-to-year due to changes in these
factors.
Rapid changes in production volumes, oil and gas sales revenues, and costs reflect the cyclical and highly
volatile prices our industry receives for production, as well as the impact of the timing of acquisitions. The
comparison of changes in production from 2006 to 2007 reflects the positive results from our drilling programs in
2007 and the full year impact of a significant acquisition made in the fourth quarter of 2006. Production volumes in
2007 were also affected by production from oil and gas properties acquired in 2007 and from production from new
drilling activity.
We present per MCFE information because we use this information to evaluate our performance relative to
our peers and to identify and measure trends that we believe require analysis. Our year-to-year comparison of
financial results presented later provides additional details for the analysis of changes between years in selected line
items. Oil and gas production expenses increased in 2007 as a result of a higher percentage of oil production and
ongoing upward pressure for oil and gas sector services related to the ongoing operation of our oil and gas
properties. Depreciation, depletion, and amortization will continue to significantly increase due to higher costs
associated with finding and acquiring crude oil and natural gas reserves. General and administrative expense
increased as a result of $41 million in expense associated with payments under our Net Profits Plan, costs associated
with office space and overall upward pressure on compensation in the exploration and production industry.
We have in-the-money stock options, unvested restricted stock units, and Senior Convertible Notes that are
considered potentially dilutive securities. At times these dilutive securities can affect our earnings per share.
Consequently, both basic and diluted earnings per share are presented in the table above. A detailed explanation is
presented in Note 1 of Part IV, Item 15 of this report. Basic and diluted weighted-average common shares
outstanding used in our 2007, 2006 and 2005 earnings per share calculations reflect our stock repurchases, offset by
an increase in outstanding shares related to stock option exercises. Basic and diluted weighted-average shares
outstanding in 2007 were affected by similar factors as 2006 and 2005, as well as an increase in shares that is related
to the issuance of common stock upon settlement of RSU’s following the expiration of the restriction period. We
issued 733,650 shares of common stock in 2007, 1,489,636 shares in 2006, and 936,403 shares in 2005 as a result of
stock option exercises. These share issuances were offset by the repurchase of 792,216 shares of common stock in
2007, 3,319,300 shares in 2006, and 1,175,282 shares in 2005 through our stock repurchase plan.
The remaining information in the table relates to information we have provided in our operations update
press releases and is intended to supplement the discussion above.
Overview of Liquidity and Capital Resources
We own depleting assets. In order to maintain our current size or to meet our projected growth targets, we
will have to effectively invest capital into new projects and acquisitions. The following analysis and discussion
includes our assessments of market risk and possible effects of inflation and changing prices.
Sources of cash
Based on our current forecast, we project that our 2008 cash flows from operations will exceed our
planned capital investment budget for exploration and development resulting in free cash flow that will be
available for additional drilling opportunities, acquisitions, share repurchases, or repayment of debt. Accordingly,
we do not expect to access the capital markets in 2008. On January 31, 2008, we closed on the sale of our
previously announced divestiture of non-core oil and gas properties. Net proceeds from this transaction, before
commission costs, was $131.6 million. These proceeds were used to repay debt under our revolving credit
facility. We do anticipate that we will continue to evaluate our property base for the divestiture of properties that
48
we consider non-core and we will likely utilize such proceeds to fund our capital programs. Although our
working capital is a negative amount, it is important to note that a significant portion of this relates to hedge
contracts that are in a liability position. We classify those expected settlements that are anticipated to be settled
over the year of 2008 as a current item in our balance sheet.
Our primary sources of liquidity are the cash provided by operating activities, debt financing, sales of
non-core properties, and access to capital markets. All of these sources can be impacted by the general condition
of our industry and by significant fluctuations in oil and gas prices, operating costs, and volumes produced. We
have no control over the market prices for oil and natural gas, although we are able to influence the amount of our
net realized revenues related to oil and gas sales through the use of derivative contracts. A decrease in market
prices would reduce expected cash flow from operating activities and could reduce the borrowing base of our
credit facility as well as the value of non-strategic properties we might consider selling. Historically, decreases in
market prices have limited our industry’s access to the capital markets. The public debt markets for energy
companies continue to be available to us, although they are significantly less favorable than this time a year
earlier. Credit spreads have increased materially and the volume of transactions being placed in the market is
down dramatically. The overall credit markets have seen a significant contraction as a result of credit tightening
caused by widely reported sub-prime and leveraged loan market issues. Equity and convertible debt financings
are still an available alternative and are somewhat favorable to energy companies that operate in the exploration
and production industry. This is a result of strong commodity prices and the general strength reflected in the
balance sheets of the companies in this industry as well as the historically low credit defaults of energy
companies. We do not, however, anticipate any need to raise either public debt or equity related capital in the
foreseeable future. We intend to rely on our current credit facility for borrowings. However, a significant
transaction could necessitate the need to raise additional public debt or equity financing.
Our current credit facility. We have a five-year, $500 million credit facility agreement with Wachovia
Bank, Wells Fargo Bank and nine other participating banks. This credit facility has a borrowing base of
$1.25 billion. We have elected a commitment amount of $500 million. We believe this commitment level is
adequate for our near-term liquidity requirements. The credit agreement has a maturity date of April 7, 2010. We
must comply with certain financial and non-financial covenants under our existing credit facility. The Company is
in compliance with all covenants associated with the credit facility. As of February 15, 2008, we had $320.0 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. This reduces the amount available under
the commitment amount on a dollar-for-dollar basis. Borrowings under the new 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.
Commitment fees are accrued on the unused portion of the aggregate commitment amount and are
included in interest expense in the consolidated statements of operations. We had an outstanding loan balance of
$285.0 million as of December 31, 2007. As of December 31, 2007, we had a cash and short-term investment
balance of $44.7 million.
We decreased our net borrowings from the previous year by $49.0 million when comparing the ending
balance sheet amounts. A substantial increase in the average outstanding credit facility balance throughout
2007, offset by a decrease in interest rates and an increase in the amount of capitalized interest of $1.9 million,
resulted in a higher interest expense of $19.9 million in 2007 compared with $8.5 million in 2006. Our
weighted-average interest rate paid in 2007 was 5.4 percent and included fees paid on the unused portion of the
credit facility aggregate commitment amount, amortization of deferred financing costs, amortization of the
contingent interest embedded derivative associated with the 5.75% Senior Convertible Notes, and the effects of
interest rate swaps.
49
Uses of cash
We use cash for the acquisition, exploration, and development of oil and gas properties, and for the
payment of debt obligations, trade payables, income taxes, common stock repurchases, and stockholder dividends.
During 2007 we spent $637.7 million of cash on capital development and $182.9 million of cash for property
acquisitions. These amounts differ from the cost incurred amounts based on the timing of cash payments
associated with these activities as compared to the accrual based activity upon which the costs incurred amounts
are presented. These cash flows were funded using cash inflows from operations and available borrowing
capacity under our revolving credit facility.
Expenditures for exploration and development of oil and gas properties and acquisitions are the primary use
of our capital resources. We anticipate spending approximately $626 million for capital and exploration
expenditures in 2008. The capital expenditures budget was described in more detail earlier in the Outlook for
2008 section. The amount and allocation of future capital expenditures will depend upon a number of factors
including the number and size of available economic acquisitions and drilling opportunities, our cash flows from
operating and financing activities, and our ability to assimilate acquisitions. Also, the impact of oil and gas prices
on investment opportunities, the availability of capital and borrowing facilities, and the success of our
development and exploratory activities could lead to changes in funding requirements for future development.
We regularly review our capital expenditure budget to assess changes in current and projected cash flows,
acquisition opportunities, debt requirements, and other factors.
The current portion of our income tax expense was 16 percent of our total income tax expense for 2007.
We make estimated payments during the calendar year and as of December 31, 2007, we anticipate that we have
an income tax refund with accrued interest due the Company of $1.0 million.
During 2007 we purchased 792,216 shares of our common stock in the open market at a weighted-
average price of $32.76, including commissions, for a total of $26.0 million. As of this filing date we have Board
authorization to repurchase up to an additional 5,207,784 million shares of our common stock under our stock
repurchase program. Shares may be repurchased from time to time in open market transactions or privately
negotiated transactions subject to market conditions and other factors including certain provisions of our existing
bank credit facility agreement, compliance with securities laws, and the terms and provisions of our stock
repurchase program.
In 2007, we paid $6.3 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.
Amount of Change Between
2006/2005
2007/2006
Percent of Change
Between
2007/2006
2006/2005
Net Cash Provided By Operating Activities
$ 163,092
$ 58,321
Net Cash Used In Investing Activities
$ (79,153)
$ (384,940)
35%
11%
Net Cash Provided By (Used In) Financing Activities $ (28,432)
$ 304,651
(12)%
14%
113%
499%
Analysis of cash flow changes between 2007 and 2006
Operating activities. Cash received from oil and gas production revenues, net of the realized effects of
hedging, increased $123.0 million to $925.1 million for the year ended December 31, 2007. Included in the oil and
gas production revenue amount is $24.5 million of net realized hedging gains. The increase was the result of a
16 percent increase in production and a six percent increase in our net realized price after hedging, resulting in a
50
23 percent increase in production revenue. Net cash payments made for income taxes decreased $26.7 million
relative to the prior year as the Company was able to deduct for tax purposes a larger amount of intangible drilling
costs due to the expanded 2007 capital program.
Investing activities. Net cash proceeds from an insurance settlement related to Hurricane Rita totaled
$5.9 million for the period ended December 31, 2007. Total cash outflow for 2007 capital expenditures for
leasehold and drilling activities increased $182.7 million or 40 percent to $637.7 million. Total cash outflow for
2007 related to the acquisition of oil and gas properties decreased $87.8 million or 32 percent to $182.9 million.
Cash received from short-term investments increased $1.4 million and deposits to short-term investments increased
$1.2 million for the period ended December 31, 2007, as compared to the same period in 2006. Cash received from
other for the period ended December 31, 2007 included a deposit of $10 million related to the divestiture of non-core
oil and gas assets that was completed on January 31, 2008.
Financing activities. Net repayments to our credit facility increased $383 million and payments to our
short-term note payable increased $4.5 million for the period ended December 31, 2007, compared to 2006. In
March 2007, we received $280.7 million, net of $6.8 million of deferred financing costs, from the issuance of the
3.50% Senior Convertible Notes. Our income tax benefit attributable to the exercise of stock options decreased
$6.2 million to $9.9 million for the year ended December 31, 2007. We received $7.7 million less from the sale of
common stock related to stock option exercises and issuance under the employee stock purchase plan in 2007,
compared to 2006. Additionally, we invested $97.2 million less to repurchase shares of our common stock during
2007, compared to the same period in 2006.
We had $43.5 million in cash and cash equivalents and had a working deficit of $92.6 million as of
December 31, 2007, compared to $1.5 million in cash and cash equivalents and working capital of $22.9 million as
of December 31, 2006. The large increase in the cash balance as of the end of 2007 compared to prior periods was a
reflection of timing of maturities of the LIBOR denominated tranches on our credit facility.
Analysis of cash flow changes between 2006 and 2005
Operating activities. Cash received from oil and gas production revenue, net of the realized effects of
hedging, increased $152.5 million to $802.1 million for the year ended December 31, 2006. Included in the oil and
gas production revenue amount is $28.2 million of realized hedging gains. This increase was the result of a
six percent increase in production offset by lower realized prices. Net cash payments made for income taxes
decreased $40.2 million as the Company was able to deduct a larger amount of intangible drilling costs due to the
expanded capital program.
Investing activities. Total cash outflow for 2006 capital expenditures, as adjusted for accruals and including
acquisitions of oil and gas properties, increased $380.9 million, or 110 percent, to $725.7 million. This increase
reflects increased drilling expenditures and net cash paid for oil and gas properties acquired in the Sweetie Peck
project area in the Permian Basin during 2006.
Financing activities. Net borrowings against our credit facility were $334.0 million for the year ended
December 31, 2006, versus net payments of $37.0 million in 2005. We paid $123.1 million to acquire shares of our
common stock under our stock repurchase program in 2006, compared to $28.9 million paid in 2005. We also
received $6.5 million more from the exercise of stock options in 2006 compared to 2005, and we had a $16.1 million
increase in income tax benefit resulting from the exercise of stock options in 2006 compared to 2005.
We had $1.5 million in cash and cash equivalents and had working capital of $22.9 million as of
December 31, 2006, compared to $14.9 million in cash and cash equivalents and working capital of $4.9 million as
of December 31, 2005.
51
Capital Expenditures
The following table sets forth certain historical information regarding the costs incurred by us in our oil
and gas activities. The below amounts for 2007, 2006, and 2005 include capitalized costs associated with asset
retirement obligations of $27.6 million, $7.8 million, and $22.8 million, respectively.
Development costs
Exploration costs
Acquisitions:
Proved
Unproved
Leasing activity
Total
2007
Years Ended December 31,
2006
(In thousands)
2005
$ 591,013
111,470
$ 367,546
126,220
$ 249,518
69,817
161,665
23,495
38,436
238,400
44,472
28,816
84,981
2,853
14,330
$ 926,079
$ 805,454
$ 421,499
The costs we incurred for capital and exploration activities in 2007 increased $120.6 million or 15 percent
compared to 2006. This increase was a result of planned increases in drilling activity offset by an $88.1 million
decrease in acquisitions relative to the prior year. Increased activity in our drilling program was the primary
driver of this increase, particularly since cost inflation moderated in 2007.
Commodity Price Risk and Interest Rate Risk
We are exposed to market risk, including the effects of changes in oil and gas commodity prices and
changes in interest rates as discussed below under the caption “Summary of Interest Rate Hedges in Place.”
Changes in interest rates can affect the amount of interest we earn on our cash, cash equivalents, and short-term
investments and the amount of interest we pay on borrowings under our revolving credit facility. Changes in
interest rates do not affect the amount of interest we pay on our fixed-rate 3.50% Senior Convertible Notes, but do
affect their fair market value.
Since we produce and sell natural gas and crude oil, our financial results are affected when prices for
these commodities fluctuate. The following table reflects our estimate of the effect on net cash flows from
operations of a ten percent change in our average realized sales price, inclusive of the impact of hedging, for natural
gas, for oil, and in combination for the years presented. These amounts have been reduced by the effective income
tax rate applicable to each period since a reduction in revenue would reduce cash requirements to pay income taxes.
General and administrative expenses have not been adjusted. To fund the capital expenditures we incurred in those
years we would have been required to utilize different amounts under our credit facility as a source of funds. In each
of these years we would have had sufficient borrowing base available under our credit facility to meet this
contingency without reducing or eliminating expenditures or altering our growth strategy.
Pro forma effect on net cash flow from
operations of a ten percent change in
average realized sales price:
2007
For the Years Ended December 31,
2006
(In thousands)
2005
Oil
Natural Gas
Total
$ 25,248
29,998
$ 55,246
$ 20,496
25,117
$ 45,613
$ 18,098
24,502
$ 42,600
52
We enter into hedging transactions in order to reduce the impact of fluctuations in commodity prices.
Note 10 of Part IV, Item 15 of this report contains important information about our oil and gas derivative
contracts, and additional information is below under the caption Summary of Oil and Gas Production Hedges in
Place. We do not anticipate significant changes in existing hedge contracts or derivative contract transactions.
Summary of Oil and Gas Production Hedges in Place
Our oil and natural gas derivative contracts include swap and costless collar arrangements. All contracts
are entered into for other-than-trading purposes. Please refer to Note 10 – Derivative Financial Instruments in
Part IV, Item 15 of this report for additional information regarding accounting for our derivative transactions.
Our net realized oil and gas prices are impacted by hedges we have placed on future forecasted
production. We have historically entered into hedges of existing production around the time we make
acquisitions of producing oil and gas properties. Our intent has been to lock in a significant portion of an
equivalent amount of existing production to the prices we used to evaluate the risked economics of our
acquisitions. We also hedge a portion of our forecasted production on a discretionary basis. As of year end our
hedged positions of anticipated production through 2011 totaled approximately 11 million Bbls of oil, 70 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.
53
The following tables describe the volumes, average contract prices, and fair value of contracts we have in
place as of December 31, 2007. We seek to minimize basis risk and index the majority of our oil contracts to
NYMEX prices and our gas contracts to various regional index prices associated with pipelines in proximity to
our areas of gas production.
Oil Contracts
Oil Swaps
Contract Period
Volumes
(Bbl)
Weighted-
Average
Contract
Price
(per Bbl)
Fair Value at
December 31, 2007
Asset/(Liability)
(in thousands)
First quarter 2008 -
NYMEX WTI
WCS
Second quarter 2008 -
493,000
45,000
$
$
69.52
51.63
$
(12,707)
(464)
NYMEX WTI
WCS
459,000
45,000
$
$
69.10
53.69
Third quarter 2008 -
NYMEX WTI
WCS
Fourth quarter 2008 -
NYMEX WTI
WCS
2009 -
438,000
45,000
$
$
69.22
54.03
405,000
15,000
$
$
68.79
50.42
NYMEX WTI
1,363,000
$
67.74
2010 -
NYMEX WTI
1,239,000
$
66.47
2011 -
NYMEX WTI
1,032,000
$
65.36
(11,157)
(296)
(9,814)
(206)
(8,645)
(107)
(26,439)
(22,068)
(18,312)
$
(110,215)
All oil swap contracts
Oil Collars
Contract Period
First quarter 2008
Second quarter 2008
Third quarter 2008
Fourth quarter 2008
2009
2010
2011
All oil collars
NYMEX WTI
Volumes
(Bbl)
415,000
415,000
419,000
419,000
1,526,000
1,367,500
1,236,000
Weighted-
Average
Ceiling
Price
(per Bbl)
$ 69.83
$ 69.83
$ 69.82
$ 69.82
$ 67.31
$ 64.91
$ 63.70
Weighted-
Average
Floor
Price
(per Bbl)
$ 50.00
$ 50.00
$ 50.00
$ 50.00
$ 50.00
$ 50.00
$ 50.00
54
Fair Value at
December 31, 2007
Asset/(Liability)
(in thousands)
$
(10,580)
(9,876)
(9,385)
(9,012)
(32,858)
(29,056)
(26,176)
$
(126,943)
Gas Contracts
Gas Swaps
Contract Period
First quarter 2008 -
IF CIG
IF PEPL
IF NGPL
IF ANR OK
IF EL PASO
IF HSC
Second quarter 2008 -
IF CIG
IF PEPL
IF NGPL
IF ANR OK
IF EL PASO
IF HSC
Third quarter 2008 -
IF CIG
IF PEPL
IF NGPL
IF ANR OK
IF EL PASO
IF HSC
Fourth quarter 2008 -
IF CIG
IF PEPL
IF NGPL
IF ANR OK
IF EL PASO
IF HSC
2009 -
IF CIG
IF PEPL
IF NGPL
IF ANR OK
IF EL PASO
IF HSC
Volumes
(MMBtu)
780,000
1,410,000
330,000
330,000
220,000
1,120,000
780,000
1,420,000
240,000
240,000
260,000
1,180,000
780,000
1,460,000
190,000
190,000
280,000
1,200,000
780,000
1,490,000
160,000
160,000
300,000
1,400,000
1,710,000
3,360,000
440,000
440,000
1,200,000
6,320,000
Weighted-
Average
Contract
Price
(per MMBtu)
Fair Value at
December 31, 2007
Asset/(Liability)
(in thousands)
2,104
3,990
366
408
284
1,726
561
1,077
(18)
(17)
1
276
148
1,046
(26)
31
2
241
400
1,849
2
19
(29)
562
998
2,189
(176)
(59)
(646)
447
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
8.94
9.28
7.53
7.68
7.94
8.64
7.00
7.22
6.41
6.66
6.72
7.66
6.70
7.48
6.69
6.82
7.16
7.95
7.30
8.32
7.10
7.18
7.20
8.44
7.79
8.06
7.11
7.38
7.11
8.35
55
Gas Swaps (continued)
Contract Period
2010 -
IF ANR OK
IF NGPL
IF EL PASO
IF HSC
2011 -
IF EL PASO
Weighted-
Average
Contract
Price
(per MMBtu)
Volumes
(MMBtu)
Fair Value at
December 31, 2007
Asset/(Liability)
(in thousands)
60,000
60,000
1,090,000
3,460,000
$
$
$
$
7.98
7.60
6.79
8.25
880,000
$
6.34
(18)
(37)
(1,065)
(421)
(1,220)
All gas swap contracts
$ 14,995
Gas Collars
Contract Period
Volumes
(MMBtu)
First quarter 2008 -
IF CIG
IF PEPL
IF HSC
NYMEX Henry Hub
720,000
1,642,500
240,000
120,000
Second quarter 2008 -
IF CIG
IF PEPL
IF HSC
NYMEX Henry Hub
720,000
1,642,500
240,000
120,000
Third quarter 2008 -
IF CIG
IF PEPL
IF HSC
NYMEX Henry Hub
720,000
1,657,500
240,00
120,000
Fourth quarter 2008 -
IF CIG
IF PEPL
IF HSC
NYMEX Henry Hub
720,000
1,657,500
240,000
120,000
Weighted-
Average
Floor
Price
(per MMBtu)
Weighted-
Average
Ceiling
Price
(per MMBtu)
Fair Value at
December 31, 2007
Asset/(Liability)
(in thousands)
$
35
329
19
14
115
662
30
31
71
549
(1)
25
(35)
314
(47)
(8)
8.72
$
9.42
$
$
9.70
$ 10.57
8.72
$
9.42
$
9.70
$
$ 10.57
8.72
$
9.42
$
$
9.70
$ 10.57
$
8.72
$
9.42
9.70
$
$ 10.57
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
5.60
6.28
6.57
7.00
5.60
6.28
6.57
7.00
5.60
6.28
6.57
7.00
5.60
6.28
6.57
7.00
56
Gas Collars (continued)
Contract Period
2009 -
Volumes
(MMBtu)
IF CIG
IF PEPL
IF HSC
NYMEX Henry Hub
2,400,000
5,510,000
840,000
360,000
2010 -
IF CIG
IF PEPL
IF HSC
NYMEX Henry Hub
2,040,000
4,945,000
600,000
240,000
2011 -
IF CIG
IF PEPL
IF HSC
NYMEX Henry Hub
1,800,000
4,225,000
480,000
120,000
All gas collars
Natural Gas Liquid Contracts
Natural Gas Liquid Swaps
Weighted-
Average
Floor
Price
(per MMBtu)
Weighted-
Average
Ceiling
Price
(per MMBtu)
Fair Value at
December 31, 2007
Asset/(Liability)
(in thousands)
$ 4.75
$ 5.30
$ 5.57
$ 6.00
$ 4.85
$ 5.31
$ 5.57
$ 6.00
$ 5.00
$ 5.31
$ 5.57
$ 6.00
8.82
$
9.25
$
$
9.49
$ 10.35
$
$
$
$
$
$
$
$
7.08
7.61
7.88
8.38
6.32
6.51
6.77
7.25
(1,036)
(2,036)
(516)
(164)
(1,940)
(4,740)
(712)
(252)
(2,350)
(6,066)
(816)
(181)
$ (18,706)
Weighted-
Average
Contract
Price
(per Bbl)
$ 39.54
$ 39.49
$ 39.25
$ 38.63
Volumes
(Bbls)
151,000
170,000
194,000
217,000
627,000
$ 38.61
Fair Value at
December 31, 2007
Asset/(Liability)
(in thousands)
$
(3,581)
(3,190)
(3,403)
(4,026)
(9,053)
$ (23,253)
First quarter 2008
Second quarter 2008
Third quarter 2008
Fourth quarter 2008
2009
All natural gas liquid swaps
Please see Note 10 – Derivative Financial Instruments in Part IV, Item 15 of this report for additional
information regarding our oil and gas hedges.
Summary of Interest Rate Hedges in Place
Effective September 13, 2007, we entered into a one year floating-to-fixed interest rate derivative contract
for a notional amount of $75 million. Under the agreement, we will pay a fixed rate of 4.90 percent and will be paid
a variable rate of the one-month LIBOR rate.
57
In relation to our 5.75% Senior Convertible Notes we entered into fixed-to-floating interest rate swaps on
$50 million of principal in October 2003. Due to an increase in interest rates, we entered into a floating-to-fixed
interest rate swap in April 2005 through the redemption date of the notes on March 20, 2007, for this same notional
amount of $50 million in order to effectively offset our fixed-to-floating interest rate swaps. Under the floating-to-
fixed interest rate swap, we were paid a variable interest rate of 235 basis points above the six-month LIBOR rate as
determined on the semi-annual settlement date and paid a fixed interest rate of 6.85 percent. The impact of this
instrument, when combined with the other interest rate swaps, was that we fixed our net liability related to the
interest rate swaps, and paid a 1.1 percent interest factor on $50 million of notional debt through March 2007. The
payment dates of the swap matched exactly with the interest payment dates of the 5.75% Senior Convertible Notes
and the fixed-to-floating interest rate swaps.
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 rate 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 $285.0 million of floating rate debt outstanding as of
December 31, 2007. Our fixed rate debt outstanding at this same date was $287.5 million associated with the
3.50% Senior Convertible Notes.
Please see Note 10 of Part IV, Item 15 of this report for additional information regarding our interest
rate swaps.
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
$ 615.3
$ 10.1
$ 315.2
$ 290.0
$
Operating Leases
44.2
29.1
13.0
1.9
Other Long-Term Liabilities
511.8
141.8
238.5
130.6
Total
$ 1,171.3
$ 181.0
$ 566.7
$ 422.5
$
-
0.2
0.9
1.1
This table includes our 2007 estimated pension liability payment of approximately $1.9 million expected to
be paid in the second quarter of 2008. The table also includes the remaining unfunded portion of our estimated
pension liability of $4.2 million even though we recognize that we cannot determine with accuracy the timing of
future payments. We have made payments of $2.2 million, $1.3 million, and $1.1 million in 2007, 2006, and 2005,
respectively, towards the pension liability. We have included $216.7 million in other long-term liabilities, which
represents six years of undiscounted forecasted payments for the Net Profits Plan. Payments are expected to be
similar on an annual basis for the years beyond what is shown in this table. The value recorded on the balance sheet
reflects the impact of discounting and therefore differs from the amounts disclosed in this table. The variability in
the amount of the payments will be a direct reflection of commodity prices, capital expenditures, and operating costs
in future periods. Predicting the timing 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 scheduled repayment of the long-term credit facility is in 2010. Accordingly, it has been disclosed in
the table as such. Since this is a revolving credit facility, the actual payments will vary significantly. We anticipate
refinancing this obligation. For purposes of this table, we assume that we will net share settle the 3.50% Senior
Convertible Notes. Additionally, $42.8 million of interest payments related to the 3.50% Senior Convertible
Notes are included in the table above. We have excluded asset retirement obligations because we are not able to
58
accurately predict the precise timing for these amounts. Pension liabilities and asset retirement obligations are
discussed in Note 8 and Note 9 of Part IV, Item 15, respectively, and the Net Profits Plan is discussed in Note 7 of
Part IV, Item 15 of this report.
This table also includes estimated oil and natural gas derivative payments of $282.9 million based on futures
market prices as of December 31, 2007. This amount represents only the cash outflows; it does not include oil and
gas receipts of $20.6 million that would be paid based on December 31, 2007, market prices. The net of
$262.3 million represents cash flows from the intrinsic value of our swap and collar arrangements and differs in
amount from our recorded fair value, which as of December 31, 2007, was a net liability of $264.1 million. The fair
value considers time value and volatility that affect the ultimate fair value. Both the intrinsic value and fair value
will change as oil and natural gas commodity prices change. Please refer to the discussion above under the caption
Summary of Oil and Gas Production Hedges in Place in Part II, Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations and to Note 10 – Derivative Financial Instruments in Part IV, Item 15
of this report for additional information regarding our oil and gas hedges.
We believe that we will continue to pay annual dividends of $0.10 per share. We anticipate making cash
payments for income taxes, dependent on net income and capital spending.
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 and up to December 31, 2007, we have not been
involved in any unconsolidated SPE transactions.
We evaluate our transactions to determine if any variable interest entities exist. If it is determined that we
are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial
statements.
Critical Accounting Policies and Estimates
We are engaged in the exploration, exploitation, development, acquisition, and production of natural gas and
crude oil. Our discussion of financial condition and results of operations is based upon the information reported in
our consolidated financial statements. The preparation of these consolidated financial statements requires us to
make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well
as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our decisions
affecting the estimates we use on historical experience and various other sources that are believed to be reasonable
under the circumstances. Actual results may differ from the estimates we calculate due to changing business
conditions or unexpected circumstances. Policies we believe are critical to understanding our business operations
and results of operations are detailed below. For additional information on our significant accounting policies you
should see Note 1 – Summary of Significant Accounting Policies, Note 9 – Asset Retirement Obligations, and
Note 12 – Disclosures About Oil and Gas Producing Activities in Part IV, Item 15 of this report.
Oil and gas reserve quantities. Estimated reserve quantities and the related estimates of future net cash
flows are the most important estimates for an exploration and production company because they affect the perceived
value of our Company, are used in comparative financial analysis ratios and are used as the basis for the most
significant accounting estimates in our financial statements. The significant accounting estimates include the
periodic calculations of depletion, depreciation, and impairment for our proved oil and gas properties and the
estimates of our liability for future payments under the Net Profits Plan. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing
economic and operating conditions. Future cash inflows and future production and development costs are
determined by applying benchmark prices and costs, including transportation, quality, and basis differentials, in
effect at the end of each period to the estimated quantities of oil and gas remaining to be produced as of the end of
59
that period. Expected cash flows are reduced to present value using a discount rate that depends upon the purpose
for which the reserve estimates will be used. For example, the standardized measure calculation required by
SFAS No. 69, Disclosures about Oil and Gas Producing Activities, requires a ten percent discount rate to be applied.
Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are
more imprecise than those of established producing oil and gas properties, we make a considerable effort in
estimating our reserves, including using independent reserve engineering consultants. We expect that periodic
reserve estimates will change in the future as additional information becomes available or as oil and gas prices and
operating and capital costs change. We evaluate and estimate our oil and gas reserves at December 31 and June 30
of each year. For purposes of depletion, depreciation, and impairment, reserve quantities are adjusted at all interim
periods for the estimated impact of additions and dispositions. Changes in depletion, depreciation, or impairment
calculations caused by changes in reserve quantities or net cash flows are recorded in the period that the reserve
estimates change.
The following table presents information regarding reserve changes from period to period that reflect
changes from items we do not control, such as price, and from changes resulting from better information due to
production history, and well performance. These changes do not require a capital expenditure on our part, but may
have resulted from capital expenditures we incurred to develop other estimated proved reserves.
Years Ended December 31,
2007
Percent of
total
Additions
BCFE
Change
2006
Percent
of total
Additions
2005
BCFE
Change
Percent
of total
Additions
BCFE
Change
Revisions resulting
from price changes
34.5
13%
(52.2)
(23)%
23.1
10%
Revisions resulting
from performance
Total
6.4
40.9
2%
15%
66.3
14.1
29%
6%
10.8
33.9
5%
15%
Over the three-year period, we added 720.7 BCFE of reserves. Of these, 83.5 BCFE, or 12 percent, was a
result of changes in estimates based on the performance of our oil and gas properties. A 5.4 BCFE increase in
reserves was a result of price changes. As previously noted, oil and gas prices are volatile, and estimates of
reserves are inherently imprecise. Consequently, we anticipate we will continue to experience these types of
changes.
The following table reflects the estimated BCFE change and percentage change to our total reported
reserve volumes from the described hypothetical changes:
2007
Years Ended December 31,
2006
2005
BCFE
Change
Percent
Change
BCFE
Change
Percent
Change
BCFE
Change
Percent
Change
A 10% decrease in pricing
A 10% decrease in proved
undeveloped reserves
(16.3)
(2)%
(28.2)
(3)%
(28.9)
(25.0)
(2)%
(20.0)
(2)%
(14.6)
(4)%
(2)%
Additional reserve information can be found in the reserve table and discussion included in Item 2 of
Part I of this report.
Successful efforts method of accounting. Generally accepted accounting principles provide for two
alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two
methods are generally known in our industry as the full cost method and the successful efforts method. Both
methods are widely used. The methods are different enough that in many circumstances the same set of facts will
60
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 analyses of liquidity and capital
resources. We derive our revenue primarily from the sale of produced natural gas and crude oil. We report revenue
as the gross amounts we receive before taking into account production taxes and transportation costs, which are
reported as separate expenses. Revenue is recorded in the month our production is delivered to the purchaser, but
payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless
it is determined that title to the product has transferred to a purchaser. At the end of each month we make estimates
of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our
properties, their historical performance, NYMEX and local spot market prices, and other factors as the basis for
these estimates. Variances between our estimates and the actual amounts received are recorded in the month
payment is received. A ten percent change in our year-end revenue accrual would have impacted net income before
tax by $11.6 million in 2007.
Crude oil and natural gas hedging. Our crude oil and natural gas hedging contracts are intended and usually
qualify for cash flow deferral hedge accounting under SFAS No. 133. Under this accounting pronouncement a
majority of the gain or loss from a contract qualifying as a cash flow hedge is deferred as to statement of
operations recognition. The position reflected in the statement of operations is based on the actual settlements
with the counterparty. If our natural gas and crude oil hedge contracts did not qualify for hedge accounting
treatment or we chose not to use this hedge accounting methodology, our periodic consolidated statements of
operations could include significant changes in the estimate of non-cash derivative gain or loss due to swings in
the value of these contracts. Consequently, we would report a different amount for oil and gas hedge loss in our
statements of operations. These fluctuations could be especially significant in a volatile pricing environment such
as what we have encountered over the last three years. The amounts recorded to accumulated other
comprehensive income (loss) of $(170.0) million, $69.0 million, and $(57.2) million, for 2007, 2006, and 2005,
respectively, would have increased or (decreased) net income after tax if our hedges did not qualify as cash flow
deferral hedges under SFAS No. 133.
Change in Net Profits Plan Liability. We record the estimated liability of future payments for our Net
Profit Plan. The estimated liability is calculated based on a number of assumptions, including estimates of oil and
gas reserves, recurring and workover lease operating expense, product 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.
Asset retirement obligations. We are required to recognize an estimated liability for future costs associated
with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical
experience in abandoning oil and gas wells projected into the future based on our current understanding of federal
and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our
properties, assume what future inflation rates apply to external estimates, and determine what credit adjusted risk-
free rate to use. The impact to the consolidated statement of operations from these estimates is reflected in our
depreciation, depletion, and amortization calculations and occurs over the remaining life of our oil and gas
properties.
Valuation of long-lived and intangible assets. Our property and equipment is recorded at cost. An
impairment allowance is provided on unproved 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 a property, using escalated pricing, with the
related net capitalized costs of the property at the end of each period. When the net capitalized costs exceed the
undiscounted future net revenue of a property, the cost of the property is written down to our estimate of fair value,
which is determined by applying a discount rate that we believe is indicative of the current market. Our criteria for
61
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.
Income taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or
liability and its carrying amount in our financial statements in accordance with SFAS No. 109, “Accounting for
Income Taxes.” This difference will result in taxable income or deductions in future years when the reported
amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in
determining when these events may occur and whether recovery of an asset is more likely than not. Additionally,
our federal and state income tax returns are generally not filed before the consolidated financial statements are
prepared, therefore we estimate the tax basis of our assets and liabilities at the end of each period as well as the
effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments
related to differences between the estimates we used and actual amounts we reported are recorded in the period in
which we file our income tax returns. These adjustments and changes in our estimates of asset recovery could have
an impact on our results of operations. A one percent change in our effective tax rate would have affected our
calculated income tax expense by $2.9 million for the year ended December 31, 2007.
Stock-based compensation. Prior to 2006 we accounted for stock-based compensation using the intrinsic
value recognition and measurement principles detailed in APB No. 25. No stock-based employee compensation
expense relating to stock options has been reflected in our expense as all options granted under our plans had an
exercise price equal to the market value of the underlying common stock on the date of grant. We used the Black-
Scholes option valuation model to calculate the disclosures required under Statement of Financial Accounting
Standards No. 123. As of January 1, 2006, we adopted the provisions of Statement of Financial Accounting
Standards No. 123(R). This statement required us to record expense associated with the fair value of stock-based
compensation. We have recorded expense associated with the issuance of restricted stock units since the plan was
adopted in 2004 and units were first issued. Going forward this expense will decrease on a relative per share basis
for all units that have already been issued because the accounting standard requires cost recognition using fair value
estimates of the restricted stock units, rather than intrinsic value.
Additional Comparative Data in Tabular Format:
Oil and Gas Production Revenues:
Increase in oil and gas production
Change Between Years
2007 and 2006
2006 and 2005
Revenues, net of hedging (in thousands)
$
177,664
$
47,908
Components of Revenue Increases (Decreases):
Oil
Realized price change per Bbl, net of hedging
Realized price percentage 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
$
$
6.00
11%
851
14%
0.26
4%
9,613
17%
$
$
5.67
11%
130
2%
(0.53)
(7)%
4,646
9%
62
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,
2006
45%
55%
2007
46%
54%
2005
42%
58%
39%
61%
39%
61%
41%
59%
Information regarding the effects of oil and gas hedging activity:
Oil Hedging
Percentage of oil production hedged
Oil volumes hedged (MBbl)
Decrease in oil revenue
Average realized oil price per Bbl before hedging
Average realized oil price per Bbl after hedging
Natural Gas Hedging
Percentage of gas production hedged
Natural gas volumes hedged (MMBtu)
Increase (decrease) in gas revenue
Average realized gas price per Mcf before hedging
Average realized gas price per Mcf after hedging
2007
Years Ended December 31,
2006
2005
66%
4,565
$ (34.3 million)
67.56
$
62.60
$
66%
4,021
$ (16.6 million)
59.33
$
56.60
$
24%
1,419
$ (13.3 million)
53.18
$
50.93
$
46%
32.5 million
$ 58.7 million
6.74
$
7.63
$
40%
24.2 million
$ 44.7 million
6.58
$
7.37
$
25%
14.0 million
$ (9.2 million)
8.08
$
7.90
$
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
$
$
2007
Years Ended December 31,
2006
2005
17.0 $
14.4
27.3
58.7 $
9.5
10.2
32.2
51.9
$
$
7.9
8.1
28.9
44.9
63
Comparison of Financial Results and Trends between 2007 and 2006
Oil and gas production revenues. Average net daily production increased 16 percent to a record
294.5 MMCFE for 2007 compared with 254.2 MMCFE in 2006. The following table presents specific
components that contributed to the increase in revenue between the two periods:
Average Net
Daily Production
Added
(MMCFE)
Oil and Gas
Revenue
Added
(In millions)
Production
Costs Added
(In millions)
Sweetie Peck acquisition and drilling,
Permian Basin region
Rockford acquisition and drilling
Williston Basin Middle Bakken Play
Elm Grove Field
James Lime formation
Anadarko Basin fields
Woodford shale formation – horizontal
wells
Other wells completed in 2007 and 2006
Other acquisitions
Total
15.8
1.6
2.2
6.3
3.4
8.5
5.7
54.4
4.1
102.0
65.2
4.6
11.4
16.2
8.9
22.1
11.5
85.1
12.1
237.1
9.3
1.0
1.9
2.0
1.0
3.4
1.1
13.7
3.3
36.7
The revenue increases in this table also reflect the difference in oil and gas prices received between
the comparable periods. The production increases are offset by natural declines in production from older
properties to result in the net increase in production between the years presented. Additional production costs
reflect increases resulting from inflation and competition for resources.
Oil and gas realized hedge gain (loss). The 13 percent decrease in total oil and gas hedge gain to
$24.5 million was caused by a change in the composition of our hedge position and changes in oil and gas
commodity prices.
Marketed gas system revenue and expense. Marketed gas system revenue increased $24.2 million to
$45.1 million for the year-ended December 31, 2007, compared with $20.9 million for the comparable period of
2006. The increase is due to the addition of a new marketed gas system in western Oklahoma that increased the
number of wells for which we currently market gas, as well as increased production in the Woodford shale formation
located in Coal County, Oklahoma. Concurrent with the increase in marketed gas system revenue, marketed gas
system expense increased $24.0 million to $42.5 million for the year-ended December 31, 2007, compared with
$18.5 million for the comparable period of 2006.
Other revenues. Other revenues increased $7.8 million to $8.7 million for the year ended
December 31, 2007, compared with $942,000 for the comparable period of 2006. The increase is due primarily to a
$5.2 million gain associated with a global insurance settlement attributed to Hurricane Rita. The gain calculation is
net of approximately $12.1 million of costs associated with the plugging and abandonment of one offshore
platform. We continue to closely monitor the activities associated with these properties. Any significant variation
between actual and estimated plugging and abandonment and outside-operated damage repair costs will impact
the final determination of the insurance settlement gain. We assume that all work will be completed and expect
adjustments to the gain will be finalized during the second quarter of 2008.
Oil and gas production expenses. Total production costs increased $41.6 million or 24 percent to
$218.2 million for 2007, from $176.6 million in 2006. Our current year and prior year acquisition of properties
added $13.6 million of incremental production costs, and other wells completed in 2006 and 2007 added
64
$13.7 million of incremental production costs in 2007 that were not reflected in 2006. The production cost
increases are offset by natural declines in production costs from older properties to result in the net increase in
production costs between the years presented. We experienced an increase in production taxes consistent with
the increase in revenue from higher realized prices.
Total oil and gas production costs per MCFE increased $0.12 to $2.03 for 2007, compared with $1.91
for 2006. This increase is comprised of the following:
• A $0.02 increase in overall transportation cost due to an increase in the Rocky Mountain region
resulting from a change in the sale measurement point, as well as newly drilled wells with higher
transportation costs
• A $0.11 increase in recurring lease operating expense related to continued cost pressure from the oil and
gas service sector
• A $0.05 overall decrease in lease operating expense relating to workover expense, primarily in the
Rockies
• A $0.04 increase in production taxes related to increase production in the Permian region.
Depletion, Depreciation, and Amortization. DD&A increased $73.1 million, or 47 percent, to
$227.6 million in 2007 compared with $154.5 million in 2006. DD&A expense per MCFE increased 27 percent to
$2.12 in 2007 compared to $1.67 in 2006. This increase reflects overall upward cost pressure in the industry and
specifically our drilling in 2007 and 2006 that added costs at a higher per unit rate relative to the prior year’s base.
The DD&A per MCFE rate was further affected by upward adjustments to reserves due to pricing differences
between December 31, 2007, and December 31, 2006 although this had the impact of a general lowering of DD&A
as compared to what DD&A would have been with the upward revisions of 40.9 BCFE of proved reserves.
Exploration expense. Exploration expense increased $6.8 million or 13 percent to $58.7 million in 2007
compared with $51.9 million for 2006. This increase is due to a $7.5 million increase in geologic and geophysical
expense to support a larger overall program as well as a $4.2 million increase in exploratory dry hole expense related
to three wells located in the Gulf Coast region and one in the Rockies region. These increases were offset by a
$4.9 million decrease in exploration overhead expense related to a reduction in amounts recorded in exploration
expense related to payments under the Net Profits Plan. In the current year we had a change in our accounting
estimate to reflect the view that Net Profits Plan distributions should be reclassified to exploration overhead only for
individuals who are currently employed by us and who continue to be involved in our exploration efforts. Therefore
Net Profits Plan payments associated with the distributions under the Net Profits Plan for ex-employees were
reclassified to general and administrative expense since there is no longer any functional link to exploration expense
as there is by definition no periodic costs associated with geologic, geophysical and exploration related work by
those ex-employees.
General and administrative. General and administrative expenses increased $21.3 million or 55 percent
to $60.1 million for 2007, compared with $38.9 million for 2006. G&A increased $0.14 to $0.56 per MCFE for
2007 compared to $0.42 per MCFE for the period in 2006 as G&A grew at a faster rate than the 16 percent
increase in production. A 23 percent increase in employee count has contributed to an increase in base
employee compensation, including taxes and benefits, of approximately 29 percent, or $8.5 million, between the
year ended December 31, 2007, and the same period of 2006.
An increase in oil and gas prices in 2007 triggered additional Net Profits Plan payouts and has increased the
amounts payable to plan participants. Additionally, an increased percentage amount of the distribution dollars under
the Net Profits Plan associated with general and administrative expense contributed to the current period realized
expense associated with the Net Profits Plan increasing by $5.8 million in 2007 compared with the same period in
2006. An increase in employee count resulted in an increase in cash bonus expense of $2.4 million to $5.2 million
for the year ended December 31, 2007, compared with $2.8 million for the year ended December 31, 2006.
RSU bonus expense remained relatively flat decreasing by $100,000 for the year ended December 31, 2007,
compared with the same period in 2006. Compensation expense related to stock options for the year ended
65
December 31, 2007, decreased $1.4 million to $437,000 from $1.9 million in the comparable period in 2006 because
virtually all the stock options are now vested. No stock options have been granted since 2004.
The amounts described above, combined with a net $5.4 million increase in other G&A expense (including
office supplies and employee development), were offset by a $5.0 million decrease in the amount of G&A that was
allocated to exploration expense due to the aforementioned change in our Net Profits Plan accounting estimate and a
$4.3 million increase in COPAS overhead reimbursements. COPAS overhead reimbursements from operations
increased due to an increase in our operated well count from our drilling program.
Change in Future Net Profits Plan Liability. For the year ended December 31, 2007, this expense
increased $27.1 million to $50.8 million from $23.8 million for 2006. This increase reflects a decrease in the
discount rate used to calculate the present value of future payments from a base rate of 15 percent to 12 percent.
The decrease in the discount rate to the 12 percent resulted from our divestiture marketing process and our
assessment that the overall market for proved oil and gas reserves is ever more competitive. 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, production tax rates, and production costs.
Interest expense. Interest expense increased by $11.4 million to $19.9 million for 2007 compared to
$8.5 million for 2006. The increase reflects an increase in our average outstanding borrowings in 2007
compared with 2006. Additionally, the increase reflects that we have $287.5 million of 3.50% Senior
Convertible Notes outstanding at December 31, 2007, compared with 100.0 million of 5.75% Senior
Convertible Notes outstanding as of December 31, 2006. We also capitalized $5.4 million of interest in 2007
compared to $3.5 million in 2006.
Income tax expense. Income tax expense totaled $110.6 million for 2007 and $105.3 million in 2006,
resulting in effective tax rates of 36.8 percent and 35.7 percent, respectively. The effective rate change from
2006 reflects changes in the mix of the highest marginal state tax rates as a result of enacted Texas margin tax
legislation, the benefit of federal and state estimated percentage depletion expense, acquisition and drilling
activity, and also reflects other permanent differences including differing estimated effects between years of the
domestic production activities deduction.
The current portion of income tax expense in 2007 is $17.6 million compared to $30.5 million in 2006.
These amounts are 16 percent and 29 percent of total income tax expense for the respective periods. The
decrease resulted from significant increased drilling activity reflecting the deduction of intangible drilling costs
in the year incurred, thereby reducing current taxable income. We project that the current portion of taxable
income will be similar in 2008.
Comparison of Financial Results and Trends between 2006 and 2005
Oil and gas production revenues. Average net daily production increased six percent to a record
254.2 MMCFE for 2006 compared with 239.4 MMCFE in 2005. The following table presents specific
components that contributed to the increase in revenue between the two periods:
Williston Basin Middle Bakken Play
Wold acquisition
Other wells completed in 2006 and 2005
Other acquisitions
Total
Average Net
Daily Production
Added
(MMCFE)
6.2
3.1
47.2
2.9
59.4
66
Oil and Gas
Revenue
Added
(In millions)
23.5
9.2
80.8
9.7
123.2
Production
Costs Added
(In millions)
2.5
5.2
15.3
1.4
24.4
The revenue increases in this table also reflect the difference in oil and gas prices received between
the comparable periods. The production increases were offset by natural declines in production from older
properties to result in the net increase in production between the years presented. Additional production costs
reflect increases resulting from inflation and competition for resources.
Oil and gas realized hedge gain (loss). The 225 percent increase in total oil and gas hedge gain to
$28.2 million was caused by a change in the composition of our hedge position and changes in oil and gas
commodity prices.
Oil and gas production expenses. Total production costs increased $33.7 million or 24 percent to
$176.6 million for 2006, from $142.9 million in 2005. The acquisition of properties added $1.4 million of
incremental production costs, prior year acquisitions of properties added $5.2 million of incremental production
costs, and other wells completed in 2005 and 2006 added $15.3 million of incremental production costs in 2006
that were not reflected in 2005. We experienced an increase in production taxes consistent with the increase in
revenue from higher realized prices.
Total oil and gas production costs per MCFE increased $0.27 to $1.91 for 2006, compared with $1.64
for 2005. This increase was comprised of the following:
• A $0.02 decrease in production taxes, due to a $0.04 decrease in our Rocky Mountain region resulting
from an increase in new production, which qualifies for incentive tax rates, that was partially offset by a
minor increase in our Mid-Continent region resulting from higher natural gas revenues
• A $0.03 increase in overall transportation cost, due to an increase in the Rocky Mountain region
resulting from a change in the sale measurement point, as well as newly drilled wells with higher
transportation costs
• A $0.20 increase in recurring LOE related to continued increases in costs for oil and gas service sector
resources
• A $0.06 overall increase in LOE relating to workover charges, mainly due to activity in the Rockies.
Depletion, Depreciation, and Amortization. DD&A increased $21.8 million or 16 percent to $154.5 million
in 2006 compared with $132.8 million in 2005. DD&A expense per MCFE increased 10 percent to $1.67 in 2006
compared to $1.52 in 2005. This increase reflected overall upward cost pressure in the industry and specifically our
acquisitions and drilling in 2006 and 2005 that added costs at a higher per unit rate. The DD&A per MCFE rate was
further affected by downward adjustments to reserves due to pricing differences between December 31, 2006 and
December 31, 2005.
Proved Property Impairment. St. Mary recorded a $7.2 million impairment of proved oil and gas properties
in 2006 compared with no impairment in 2005. This impairment was primarily due to declining performance and
downward adjustments to reserves for properties located in East Texas.
Exploration expense. Exploration expense increased $7.0 million or 15 percent to $51.9 million in
2006 compared with $44.9 million for 2005. This increase was due to a $3.3 million increase in exploration
overhead related to increases in payments made under the Net Profits Plan and increases in the size of our
geologic and exploration staff. Additionally, the increase in exploration expense was partially related to an
approximate $2.1 million increase in exploratory dry hole expense and a $1.6 million increase in geologic and
geophysical expense to support a larger overall program.
General and administrative. General and administrative expenses increased $6.1 million or 19 percent
to $38.9 million for 2006, compared with $32.8 million for 2005. G&A increased $0.05 to $0.42 per MCFE for
2006 compared to $0.37 per MCFE for the period in 2005 as G&A grew at a faster rate than the six percent
increase in production.
A 16 percent increase in employee count contributed to an increase in base employee compensation of
approximately 18 percent, or $3.5 million, between the year ended December 31, 2006, and the same period of
2005. Oil and gas price increases triggered additional Net Profits Plan payouts and increased the amounts payable to
67
plan participants. Consequently, the realized expense associated with the Net Profits Plan increased by $5.4 million
in 2006 compared with the same period in 2005. A decrease in the bonus percentage resulted in a decrease in the
accrued cash bonus expense of $5.0 million to $2.8 million for the year ended December 31, 2006, compared with
$7.8 million for the year ended December 31, 2005.
RSU bonus expense was $1.5 million higher for the year ended December 31, 2006, as compared to the year
ended December 31, 2005, which was due to the increase in amortization of stock-based compensation expense. In
2006, we recorded expense for four periods of RSU grants while there were only three grants recorded in 2005.
Also in 2006, we included the grant made in 2006 for 2005 performance and the additional accrual of the expense
estimated for the 2006 plan year. This increase was partially offset by a decrease in RSU bonus expense for the year
ended December 31, 2006, compared with the same period in 2005. This decrease correlated to the decrease in cash
bonus expense and reflected an evaluation of our overall performance for 2006 including reserve replacement,
production, and net asset value per share growth factors.
As a result of the implementation of SFAS No. 123(R) on January 1, 2006, we recorded $2.2 million of
compensation expense in 2006 related to stock options and the ESPP. The above amounts combined with a net
$5.1 million increase in other G&A expense, including payroll tax and 401(k) contribution expense, were offset by a
$3.2 million increase in the amount of G&A that was allocated to exploration expense due to the aforementioned
incentive plan increases as well as increases in the size of our technical exploration staff and a $3.4 million increase
in COPAS overhead reimbursements. COPAS overhead reimbursements from operations increased due to an
increase in our operated well count from our drilling program.
Change in Future Net Profits Plan Liability. For the year ended December 31, 2006, this expense
decreased $82.5 million to $23.8 million from $106.3 million for 2005. This decrease reflects a smaller change in
future oil and gas prices as compared to 2005 when we experienced significant increases in prices. Since the
prices used in the calculation were much more comparable in the year-end 2006 calculation to that of the 2005
calculation, the degree of increase was much less in 2006. 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, production tax rates,
and production costs.
Interest expense. Interest expense increased by $308,000 to $8.5 million for 2006 compared to
$8.2 million for 2005. The increase reflected an increase in our average outstanding borrowings and higher
interest rates on the floating rate portion of our long-term debt. We also capitalized $3.5 million in 2006
compared to $1.9 million in 2005.
Income tax expense. Income tax expense totaled $105.3 million for 2006 and $86.3 million in 2005,
resulting in effective tax rates of 35.7 percent and 36.3 percent, respectively. The effective rate change from
2005 reflected changes in the mix of the highest marginal state tax rates as a result of enacted Texas margin tax
legislation, the benefit of estimated percentage depletion for both federal and state income taxes, acquisition and
drilling activity, and also reflected other permanent differences including differing estimated effects between
years of the domestic production activities deduction.
The current portion of income tax expense in 2006 was $30.5 million compared to $80.8 million in
2005. These amounts comprised 29 percent and 94 percent of total income tax expense for the respective
periods. The decrease resulted from a significant increase in drilling activity, whereby we deducted intangible
drilling costs in the year it was incurred and reduced our current taxable income.
Other Liquidity and Capital Resource Information
Pension Benefits
Substantially all of our employees who meet age and service requirements participate in a non-
contributory defined benefit pension plan. On December 31, 2006, the Company adopted the recognition and
disclosure provisions of Statement of Financial Accounting Standards No. 158, "Employers’ Accounting for
68
Defined Benefit Pension and Other Postretirement Plans, an amendment of Statement of Financial Accounting
Standards No 87, 88, 106 and 132(R)". Statement of Financial Accounting Standards No. 158 requires the
Company to recognize the funded status (i.e., the difference between the fair value of plan assets and the
projected benefit obligation) of its pension plan in the December 31, 2006 consolidated balance sheet as either
an asset or a liability, with a corresponding adjustment to accumulated other comprehensive income, net of tax.
At December 31, 2007, and December 31, 2006, we had a recorded balance of $2.5 million and $2.6 million,
respectively, of pre-tax loss in accumulated other comprehensive income as a result of this new pronouncement.
We believe this obligation will be funded from future cash flow from operating activities. For purposes of
calculating our obligation under the plan, we have used an expected return on plan assets of 7.5 percent. We
think this rate of return is appropriate over the long-term given the 60 percent equity and 40 percent debt
securities mix of investment of plan assets and the historical rate of return provided by equity and debt securities
since the 1920s. Our actual rate of return was 6.5 percent for 2007 and was 14.1 percent for 2006. The
difference in investment income using our projected rate of return compared to our actual rates of return for the
past two years was not material and will not have a material effect on the results of operation or cash flow from
operating activities in future years.
For the 2007 plan year, a 0.20 percentage point increase in the discount rate and a 0.50 percentage point
increase in the lump sum interest rate, netted with a larger than expected increase in base salaries and an increase in
new participants, caused a $161,000 increase in the projected benefit obligation of the plan. We do not believe this
change was material and project that it will not have a material effect on the results of operations or on cash flow
from operating activities in future periods.
We also have a supplemental non-contributory defined benefit pension plan that covers certain
management employees. There are no plan assets for this plan. For the 2007 plan year, a 0.20 percentage point
increase in the discount rate and a 0.50 percentage point increase in the lump sum interest rate caused a $62,000
decrease in the projected benefit obligation for this plan. This plan’s accumulated benefit obligation was
$1.0 million at December 31, 2007, and $1.5 million at December 31, 2006. We believe this obligation will be
funded from future cash flow from operating activities.
Accounting Matters
We refer you to Note 4 – Income Taxes and Note 5 – Long-term Debt in Part IV, Item 15 of this
report for information regarding accounting matters related to FASB Interpretation No. 48, “Accounting for
Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109” and FASB Staff Position APB
14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion
(Including Partial Cash Settlement)”.
In September 2006 the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value
Measurements”, which defines fair value, establishes a framework for measuring fair value, and expands
disclosures about fair value measurements. The provisions of SFAS No. 157 will be effective as of the beginning
of the Company’s 2008 fiscal year. The adoption of SFAS No. 157 has no impact on the Company’s consolidated
financial statements, however, it will require changes in certain disclosures.
In February 2007 the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair
Value Option for Financial Assets and Financial Liabilities”, which expands the use of fair value accounting but
does not affect existing standards which require assets or liabilities to be carried at fair value. SFAS No. 159
allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value
that are not otherwise required to be measured at fair value. If a company elects the fair value option for an
eligible item, changes in that item's fair value in subsequent reporting periods must be recognized in current
earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to draw comparisons
between entities that elect different measurement attributes for similar assets and liabilities. If elected, SFAS
No. 159 is effective for fiscal years beginning after November 15, 2007. SFAS No. 159 will be effective for the
Company beginning with the 2008 fiscal year. The Company did not elect the fair value option. There is no
impact on the Company’s consolidated financial statements.
69
Environmental
St. Mary’s compliance with applicable environmental regulations has not resulted in any significant capital
expenditures or materially adverse effects to our liquidity or results of operations. We believe we are in substantial
compliance with environmental regulations and do not currently foresee that material expenditures will be required
in the future. However, we are unable to predict the impact that future compliance with regulations may have on
future capital expenditures, liquidity, and results of operations.
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 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 this Annual Report on Form 10-K/A.
Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our
disclosure controls and procedures are effective for the purposes discussed above as of the end of the period covered
by this Annual Report on Form 10-K/A. 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.
70
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 could have a material effect on the financial
statements.
Because of the inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of
December 31, 2007. 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, 2007.
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 21, 2008
/s/ DAVID W. HONEYFIELD
David W. Honeyfield
Senior Vice President – Chief Financial Officer and Secretary
February 21, 2008
71
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, 2007, 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. 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 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 the 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, 2007, 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, 2007, of the
Company, and our report dated February 21, 2008, expressed an unqualified opinion on those financial
statements.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 21, 2008
72
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item concerning St. Mary’s Directors and corporate governance is
incorporated by reference to the information provided under the captions “Election of Directors,” “Nominees for
Election of Directors,” “Corporate Governance” and “Board and Committee Meetings” in St. Mary’s definitive
proxy statement for the 2008 annual meeting of stockholders to be filed within 120 days from December 31, 2007.
The information required by this 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 2008 annual meeting of
stockholders to be filed within 120 days from December 31, 2007.
ITEM 11.
EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the information provided under the
captions, “Director Compensation,” “Compensation Discussion and Analysis,” “Executive Compensation and
Summary Compensation Table,” “Summary Compensation Table,” “Grants of Plan-Based Awards,” “Outstanding
Equity Awards at Fiscal Year-End,” “Nonqualified Deferred Compensation,” “Option Exercises and Stock Vested,”
“Retirement Plans,” “Pension Benefits,” “Equity Compensation Plans,” “Compensation Committee Interlocks and
Insider Participation,” “Compensation Committee Report,” “Employee Agreements and Termination of
Employment,” and “Change-of-Control Arrangements” in St. Mary’s definitive proxy statement for the 2008 annual
meeting of stockholders to be filed within 120 days from December 31, 2007.
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 2008 annual meeting
of stockholders to be filed within 120 days from December 31, 2007.
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 Matters and
Issuer Purchases of Equity Securities, included in this Form 10-K.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information required by this Item is incorporated by reference to the information provided under the
caption “Certain Relationships and Related Transactions,” “Election of Directors,” “Corporate Governance,” and
“Board and Committee Meetings” in St. Mary’s definitive proxy statement for the 2008 annual meeting of
stockholders to be filed within 120 days from December 31, 2007.
73
ITEM 14.
PRINCIPAL ACCOUNTING 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 2008 annual meeting of stockholders to be filed within 120 days from
December 31, 2007.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
PART IV
Audit Report of Independent Registered Public Accounting Firm................................... F-1
Consolidated Balance Sheets.............................................................................................. F-2
Consolidated Statements of Operations.............................................................................. F-3
Consolidated Statements of Stockholders' Equity and Comprehensive Income.............. F-4
Consolidated Statements of Cash Flows............................................................................ F-5
Notes to Consolidated Financial Statements...................................................................... F-7
All other schedules are omitted because the required information is not applicable or is not present in
amounts sufficient to require submission of the schedule or because the information required is included in the
Consolidated Financial Statements and Notes thereto.
(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on
Form 10-K:
Exhibit
Number Description
2.1
2.2
2.3
2.4
3.1
3.2
Purchase and Sale Agreement dated November 1, 2006, among Henry Petroleum LP, Henry Holding LP,
Henry Group, Entre Energy Partners LP, and St. Mary Land & Exploration Company (filed as Exhibit 2.1
to the registrant’s Current Report on Form 8-K filed on December 18, 2006, and incorporated herein by
reference)
Purchase and Sale Agreement dated August 2, 2007, among Rockford Energy Partners II, LLC and St.
Mary Land & Exploration Company (filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K
filed on October 5, 2007, and incorporated herein by reference)
Purchase and Sale Agreement dated December 11, 2007, among St. Mary Land & Exploration Company,
Ralph H. Smith Restated Revocable Trust Dated 8/14/97, Ralph H. Smith Trustee, Kent J. Harrell, Trustee
of the Kent J. Harrell Revocable Trust Dated January 19, 1995, and Abraxas Operating, LLC (filed as
Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on February 1, 2008, and incorporated
herein by reference)
Ratification and Joinder Agreement dated January 31, 2008, among St. Mary Land & Exploration
Company, Ralph H. Smith, Kent J. Harrell, Abraxas Operating, LLC and Abraxas Petroleum Corporation
(filed as Exhibit 2.2 to the registrant’s Current Report on Form 8-K filed on February 1, 2008, and
incorporated herein by reference)
Restated Certificate of Incorporation of St. Mary Land & Exploration Company as amended on May 25,
2005 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
2005 and incorporated herein by reference)
Restated By-Laws of St. Mary Land & Exploration Company amended as of December 18, 2007 (filed as
Exhibit 3.1 to the registrant’s Current Report on Form 8-K filed on December 21, 2007, and incorporated
herein by reference)
74
Exhibit
Number
Description
4.1
4.2
4.3
4.4
4.5
10.1†
10.2†
10.3†
10.4†
10.5†
10.6†
10.7†
10.8†
10.9†
Shareholder Rights Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the registrant’s Quarterly
Report on Form 10-Q/A for the quarter ended June 30, 1999 and incorporated herein by reference)
First Amendment to Shareholders Rights Plan dated March 15, 2002 as adopted by the Board of Directors
on July 19, 2001 (filed as Exhibit 4.2 to the registrant’s Annual Report on Form 10-K for the year ended
December 31, 2001 and incorporated herein by reference)
Second Amendment to Shareholder Rights Plan dated April 24, 2006 (filed as Exhibit 4.1 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 and incorporated herein
by reference)
Indenture related to the 3.50% Senior Convertible Notes due 2027, dated as of April 4, 2007, between
St. Mary Land & Exploration Company and Wells Fargo Bank, National Association, as trustee
(including the form of 3.50% Senior Convertible Note due 2027) (filed as Exhibit 4.1 to the registrant’s
Current Report on Form 8-K filed on April 4, 2007, and incorporated herein by reference)
Registration Rights Agreement, dated as of April 4, 2007, among St. Mary Land & Exploration
Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wachovia Capital Markets,
LLC, for themselves and as representatives of the Initial Purchasers (filed as 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 registrant’s
Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by
reference)
Cash Bonus Plan (filed as Exhibit 10.5 to the registrant’s Registration Statement on Form S-1
(Registration No. 33-53512) and incorporated herein by reference)
Summary Plan Description/Pension Plan dated December 30, 1994 (filed as Exhibit 10.35 to the
registrant’s Annual Report on Form 10-K for the year ended December 31, 1994 and incorporated
herein by reference)
Non-qualified Unfunded Supplemental Retirement Plan, as amended (filed as Exhibit 10.8 to the
registrant’s Registration Statement on Form S-1 (Registration No. 33-53512) and incorporated herein
by reference)
Employee Stock Purchase Plan (filed as Exhibit 10.48 filed to 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 registrants Annual Report on Form 10-K for the year ended December 31, 2004 and
incorporated herein by reference)
Form of Change of Control Severance Agreements (filed as Exhibit 10.1 to the registrant’s Quarterly
Report on Form 10-Q for the quarter ended September 30, 2001 and incorporated herein by reference)
10.11
10.10† Amendment to Form of Change of Control Severance Agreement (filed as Exhibit 10.9 to the registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference)
5.75% Senior Convertible Notes due 2022 Indenture dated March 13, 2002 (filed as Exhibit 10.26 to the
registrant’s Annual Report on Form 10-K for the year ended December 31, 2001 and incorporated herein
by reference)
Amendment to and Extension of Office Lease dated as of December 14, 2001 (filed as Exhibit 10.45 to the
registrant’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein
by reference)
10.12
75
Exhibit
Number
Description
10.13† 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)
10.14† 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)
10.15† Amendment to Restricted Stock Plan, dated December 15, 2005 (filed as Exhibit 10.2 to the registrant’s
10.16†
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
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 of Wachovia Bank, National
Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.3 to the registrant’s
Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by
reference)
Guaranty Agreement by NPC Inc. in favor of Wachovia Bank, National Association, as Administrative
Agent, dated April 7, 2005 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the
quarter ended March 31, 2005 and incorporated herein by reference)
Pledge and Security Agreement between St. Mary Land & Exploration Company and Wachovia Bank,
National Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.5 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and incorporated herein
by reference)
Pledge and Security Agreement between Nance Petroleum Corporation and Wachovia Bank, National
Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.6 to the registrant’s
Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by
reference)
First Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit 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 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 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)
76
Exhibit
Number
10.27†
10.28
10.29†
10.30
Description
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)
10.31***† Summary of 2008 Compensation Arrangements for Non-Employee Directors
10.32
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)
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)
Computation of Ratio of Earnings to Fixed Charges
Code of Business Conduct and Ethics (filed as Exhibit 14.1 to the registrant’s Annual Report on Form
10-K for the year ended December 31, 2003 and incorporated herein by reference)
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
Certification pursuant to U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes –
Oxley Act of 2002
10.33
10.34
12.1***
14.1
21.1***
23.1*
23.2*
23.3*
24.1***
31.1*
31.2*
32.1**
Filed with this Form 10-K/A.
*
** Furnished with this Form 10-K/A.
*** Previously filed.
†
Exhibit constitutes a management contract or compensatory plan or arrangement.
(c) Financial Statement Schedules. See Item 15(a) above.
77
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, 2007 and 2006, and the related
consolidated statements of operations, stockholders’ equity and comprehensive income, and cash
flows for each of the three years in the period ended December 31, 2007. These financial
statements are the responsibility of the Company’s management. Our responsibility is to express
an opinion on these 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, 2007 and 2006, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2007, in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 1 and Note 8 to the financial statements, the Company changed its method
of accounting and disclosure for stock based compensation and its defined benefit plans in 2006.
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company’s internal control over financial reporting as of
December 31, 2007, based on the criteria established in Internal Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our
report dated February 21, 2008, expressed an unqualified opinion on the Company’s internal
control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 21, 2008
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
Refundable income taxes
Prepaid expenses and other
Accrued derivative asset
Deferred income taxes
Total current assets
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties
Less - accumulated depletion, depreciation, and amortization
Unproved oil and gas properties, net of impairment allowance
of $10,319 in 2007 and $9,425 in 2006
Wells in progress
Oil and gas properties held for sale less accumulated depletion,
depreciation, and amortization
Other property and equipment, net of accumulated depreciation
of $11,549 in 2007 and $9,740 in 2006
Noncurrent assets:
Goodwill
Accrued derivative asset
Other noncurrent assets
Total noncurrent assets
Total Assets
Current liabilities:
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued expenses
Short-term note payable
Accrued derivative liability
Deferred income taxes
Deposit associated with oil and gas properties held for sale
Total current liabilities
Noncurrent liabilities:
Long-term credit facility
Senior convertible notes
Asset retirement obligation
Asset retirement obligation associated with oil and gas properties held for sale
Net Profits Plan liability
Deferred income taxes
Accrued derivative liability
Other noncurrent liabilities
Total noncurrent liabilities
Commitments and contingencies
Stockholders' equity:
Common stock, $0.01 par value: authorized - 200,000,000 shares;
issued: 64,010,832 shares in 2007 and 55,251,733 shares in 2006;
outstanding, net of treasury shares: 63,001,120 shares in 2007
and 55,001,733 shares in 2006
Additional paid-in capital
Treasury stock, at cost: 1,009,712 shares in 2007 and 250,000 shares in 2006
Retained earnings
Accumulated other comprehensive income (loss)
Total stockholders' equity
December 31,
2007
December 31,
2006
$
43,510
1,173
159,149
933
14,129
17,836
33,211
269,941
$
1,464
1,450
142,721
7,684
17,485
56,136
-
226,940
2,721,229
(804,785)
134,386
137,417
76,921
9,230
2,274,398
9,452
5,483
12,406
27,341
2,063,911
(630,051)
100,118
97,498
-
6,988
1,638,464
9,452
16,939
7,302
33,693
$
2,571,680
$
1,899,097
$
254,918
-
97,627
-
10,000
362,545
$
171,834
4,469
13,100
14,667
-
204,070
285,000
287,500
96,432
8,744
211,406
257,603
190,262
8,843
1,345,790
640
170,070
(29,049)
878,652
(156,968)
863,345
334,000
99,980
77,242
-
160,583
224,518
46,432
8,898
951,653
553
38,940
(4,272)
695,224
12,929
743,374
Total Liabilities and Stockholders' Equity
$
2,571,680
$
1,899,097
The accompanying notes are an integral part of these consolidated financial statements.
F-2
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
Operating revenues:
Oil and gas production revenue
Realized oil and gas hedge gain (loss)
Marketed gas system revenue
Gain (loss) on sale of proved properties
Other revenue
Total operating revenues
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
General and administrative
Change in Net Profits Plan liability
Marketed gas system expense
Unrealized derivative loss
Other expense
Total operating expenses
Income from operations
Nonoperating income (expense):
Interest income
Interest expense
Income before income taxes
Income tax expense
Net income
For the Years Ended December 31,
2006
2005
2007
$
912,093
24,484
45,149
(367)
8,735
990,094
$
730,737
28,176
20,936
6,910
942
787,701
$
733,544
(22,539)
25,269
222
3,094
739,590
218,208
227,596
58,686
-
4,756
60,149
50,823
42,485
5,458
2,522
670,683
319,411
746
(19,895)
300,262
(110,550)
176,590
154,522
51,889
7,232
4,301
38,873
23,759
18,526
7,094
2,649
485,435
302,266
1,576
(8,521)
295,321
(105,306)
142,873
132,758
44,931
-
5,780
32,756
106,263
24,164
1,615
2,456
493,596
245,994
456
(8,213)
238,237
(86,301)
$
189,712
$
190,015
$
151,936
Basic weighted-average common shares outstanding
Diluted weighted-average common shares outstanding
61,852
64,850
56,291
65,962
56,907
66,894
Basic net income per common share
$
3.07
$
3.38
$
2.67
Diluted net income per common share
$
2.94
$
2.94
$
2.33
The accompanying notes are an integral part of these consolidated financial statements.
F-3
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(In thousands, except share amounts)
Common Stock
Shares
57,458,246
Amount
$
574
Additional
Paid-in
Capital
Treasury Stock
Shares
Amount
$
127,374
(500,000)
$
(5,295)
Deferred
Stock-Based
Compensation
$
(5,039)
Retained
Earnings
$
364,567
Accumulated
Other
Comprehensive
Income (Loss)
$
2,274
Total
Stockholders'
Equity
$
484,455
Balances, December 31, 2004
Comprehensive income, net of tax:
Net income
Change in derivative instrument fair value
Reclassification to earnings
Minimum pension liability adjustment
Total comprehensive income
Cash dividends, $ 0.10 per share
Treasury stock purchases
Retirement of treasury stock
Issuance of common stock under Employee
Stock Purchase Plan
Sale of common stock, including income
tax benefit of stock option exercises
Deferred compensation related to issued restricted
stock unit awards, net of forfeitures
Directors' stock compensation
Accrued stock-based compensation
Amortization of deferred stock-based
compensation
-
-
-
-
-
-
(1,411,356)
28,447
936,403
-
-
-
-
Comprehensive income, net of tax:
Net income
Change in derivative instrument fair value
Reclassification to earnings
Minimum pension liability adjustment
Total comprehensive income
SFAS No. 158 transition amount
Cash dividends, $ 0.10 per share
Treasury stock purchases
Retirement of treasury stock
Issuance of common stock under Employee
Stock Purchase Plan
Sale of common stock, including income
tax benefit of stock option exercises
Adoption of Statement of Financial Accounting
Standards No. 123(R)
Stock-based compensation expense
-
-
-
-
-
-
-
(3,275,689)
26,046
1,489,636
-
-
10
16,619
3,404
-
4,009
-
-
-
-
-
-
-
(28,729)
601
-
-
-
-
-
-
-
(122,598)
814
-
-
-
-
-
-
(14)
-
-
-
-
-
-
-
(33)
-
-
-
-
-
-
-
-
-
-
-
-
-
(1,175,282)
1,411,356
-
-
13,926
-
-
-
-
-
-
-
(28,902)
28,743
-
-
-
306
-
-
-
-
-
-
-
-
-
-
-
(3,404)
(306)
-
3,156
151,936
-
-
-
(5,691)
-
-
-
-
-
-
-
-
-
(71,522)
14,366
283
-
-
-
-
-
-
-
-
-
151,936
(71,522)
14,366
283
95,063
(5,691)
(28,902)
-
601
16,629
-
-
4,009
3,156
-
-
-
-
-
-
(3,319,300)
3,275,689
-
-
-
-
-
-
-
-
(123,108)
122,631
-
-
-
-
-
-
-
-
-
-
-
-
190,015
-
-
-
-
(5,603)
-
-
-
-
-
-
-
87,107
(18,129)
(180)
(1,270)
-
-
-
-
-
-
-
190,015
87,107
(18,129)
(180)
258,813
(1,270)
(5,603)
(123,108)
-
814
32,986
-
11,422
16
32,970
(5,593)
10,069
-
43,611
-
1,353
5,593
-
Balances, December 31, 2005
57,011,740
$
570
$
123,278
(250,000)
$
(5,148)
$
(5,593)
$
510,812
$
(54,599)
$
569,320
Balances, December 31, 2006
55,251,733
$
553
$
38,940
(250,000)
$
(4,272)
$
-
$
695,224
$
12,929
$
743,374
Comprehensive income, net of tax:
Net income
Change in derivative instrument fair value
Reclassification to earnings
Pension liability adjustment
Total comprehensive income
Cash dividends, $ 0.10 per share
Treasury stock purchases
Issuance of common stock under Employee
Stock Purchase Plan
Conversion of 5.75% Senior Convertible Notes
due 2022 to common stock, including income
tax benefit of conversion
Issuance of common stock upon settlement of
RSUs following expiration of restriction period,
net of shares used for tax withholdings
Sale of common stock, including income
tax benefit of stock option exercises
Stock-based compensation expense
-
-
-
-
-
-
29,534
7,692,295
302,370
733,650
1,250
-
-
-
-
-
-
-
-
-
-
-
-
-
-
919
77
106,854
3
7
(4,569)
19,011
8,915
-
-
-
-
-
(792,216)
-
-
-
-
-
-
-
-
(25,957)
-
-
-
-
-
32,504
-
1,180
-
-
-
-
-
-
-
-
-
-
-
189,712
-
-
-
(6,284)
-
-
-
-
-
-
-
(154,497)
(15,470)
70
-
-
-
-
-
-
-
189,712
(154,497)
(15,470)
70
19,815
(6,284)
(25,957)
919
106,931
(4,566)
19,018
10,095
Balances, December 31, 2007
64,010,832
$
640
$
170,070
(1,009,712)
$
(29,049)
$
-
$
878,652
$
(156,968)
$
863,345
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)
Reconciliation of net income to net cash provided
by operating activities:
Net income
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on insurance settlement
(Gain) loss on sale of proved properties
Depletion, depreciation, amortization,
and asset retirement obligation liability accretion
Exploratory dry hole expense
Impairment of proved properties
Abandonment and impairment of unproved properties
Unrealized derivative loss
Change in Net Profits Plan liability
Stock-based compensation expense*
Deferred income taxes
Other
Changes in current assets and liabilities:
Accounts receivable
Refundable income taxes
Prepaid expenses and other
Accounts payable and accrued expenses
Income tax benefit from the exercise of stock options**
Net cash provided by operating activities
Cash flows from investing activities:
Proceeds from insurance settlement
Proceeds from sale of oil and gas properties
Capital expenditures
Acquisition of oil and gas properties
Deposits to short-term investments
Receipts from 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
Proceeds from short-term note payable
Income tax benefit from the exercise of stock options**
Proceeds from issuance of senior convertible debt, net of
deferred financing costs
Proceeds from sale of common stock
Repurchase of common stock
Dividends paid
Other
Net cash provided by (used in) financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
For the Years Ended December 31,
2006
2005
2007
$
189,712
$
190,015
$
151,936
(5,243)
367
227,596
14,365
-
4,756
5,458
50,823
10,095
92,955
(10,497)
(6,557)
6,751
19,375
40,769
(9,933)
630,792
5,948
495
(637,748)
(182,883)
(1,168)
1,450
10,034
(803,872)
822,000
(871,000)
(4,469)
-
9,933
280,657
10,007
(25,904)
(6,284)
186
215,126
-
(6,910)
154,522
10,191
7,232
4,301
7,094
23,759
11,422
74,832
(2,479)
22,476
-
(17,886)
5,215
(16,084)
467,700
-
860
(455,056)
(270,639)
-
25
91
(724,719)
935,137
(601,137)
-
4,469
16,084
-
17,716
(123,108)
(5,603)
-
243,558
-
(222)
132,758
8,104
-
5,780
1,615
106,263
7,165
5,547
281
(57,113)
-
(1,210)
42,438
6,037
409,379
-
1,213
(270,881)
(73,905)
(1,502)
1,427
3,869
(339,779)
284,090
(321,090)
-
-
-
-
11,193
(28,902)
(5,691)
(693)
(61,093)
42,046
1,464
43,510
$
(13,461)
14,925
1,464
$
8,507
6,418
14,925
$
* Stock-based compensation expense is a component of Exploration expense and General and administrative expense on the
Consolidated Statements of Operations. During 2007, 2006, and 2005, respectively, approximately $3.2 million, $3.1 million,
and $3.3 million, of stock-based compensation expense was included in Exploration expense. During 2007, 2006, and 2005,
respectively, approximately $6.9 million, $8.3 million, and $3.9 million of stock-based compensation expense was included
in General and administrative expense.
** SFAS 123(R) requires presentation of the income tax benefit from the exercise of stock options to be presented in financing
activities subsequent to adoption. The prior period classification is to remain unchanged under SFAS 123(R).
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:
2007
For the Years Ended December 31,
2006
(in thousands)
2005
Cash paid for interest, net of capitalized interest
$
22,816
$
9,826
$
8,458
Cash paid (refunded) for income taxes
$
(1,156)
$
25,505
$
65,752
As of December 31, 2007, 2006, and 2005, $116.9 million, $73.5 million, and $51.0 million, respectively, are included as
additions to oil and gas properties and as increases to 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.
In May 2007 and 2006, July 2007 and 2006 , and May 2005, the Company issued 26,292, 26,076, 6,212, 3,751 and 13,926
shares, respectively, of common stock from treasury to its non-employee directors pursuant to the Company's
non-employee director stock compensation plan. The Company recorded compensation expense related to the
issuances of shares to non-employee directors of $983,500, $976,000 and $178,000 for the years ended December 31, 2007,
2006 and 2005, respectively.
In March 2007 the Company called the 5.75% Senior Convertible Notes for redemption. 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. 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 and a corresponding increase in additional paid-in
capital that is a result of the recognition of the cumulative excess tax benefit earned by the Company associated with the
contingent interest feature of this note.
In June 2006 the Company hired a new senior executive. In doing so, the Company issued 13,784 shares of stock and
recorded compensation expense of approximately $728,000. Additionally, in March 2007 the Company issued 1,250 shares
of stock to the senior executive as the Company reached certain performance levels. The Company has recognized
approximately $136,000 of expense related to this issuance as of December 31, 2007.
In February 2007, February 2006, and March 2005, the Company issued 78,657, 484,351, and 195,312 restricted stock
units, respectively, pursuant to the Company's restricted stock plan. The total value of the issuances were
$2.5 million, $16.4 million, and $4.5 million, respectively.
In May 2006 the Company closed a transaction whereby it exchanged non-core oil and gas properties for oil and gas
properties located in Richland County, Montana. This transaction is considered a non-monetary exchange for accounting
purposes with a fair value assigned to this transaction of $11.5 million.
The accompanying notes are an integral part of these consolidated financial statements.
F-6
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2007
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 in the continental United States and offshore in the Gulf of Mexico.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of the Company and its wholly-
owned subsidiaries. Subsidiaries that are not wholly-owned are accounted for using full consolidation with minority
interest or by the equity or cost method as appropriate. Equity method investments are included in other noncurrent
assets, and minority interest is included in other noncurrent liabilities in the accompanying consolidated balance
sheets. All significant intercompany accounts and transactions have been eliminated.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the
United States requires management to make estimates and assumptions that affect the reported amounts of oil and
gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could
differ from those estimates. Estimates of oil and gas reserve quantities provide the basis for calculations of
depletion, depreciation, and amortization (“DD&A”), impairment, goodwill, and the Net Profits Interest Bonus Plan
(the “Net Profits Plan”) liability, each of which represents a significant component of the accompanying
consolidated financial statements.
Revenue Recognition
The Company derives revenue primarily from the sale of produced natural gas and crude oil. The Company
reports revenue as the gross amount received before taking into account production taxes and transportation costs,
which are reported as separate expenses. Revenue is recorded in the month the Company’s production is delivered
to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue
is recognized unless it is determined that title to the product has transferred to a 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, the anticipated effect of
weather conditions during the month of production, New York Mercantile Exchange (“NYMEX”) and local spot
market prices, and other factors as the basis for these estimates.
Cash and Cash Equivalents
The Company considers all liquid investments purchased with an initial maturity of three months or less to
be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term
nature of these instruments.
F-7
Short-term Investments
As of December 31, 2007, the Company’s short-term investments consist of a certificate of deposit. As of
December 31, 2006, the Company’s short-term investments consist of investment-grade marketable debt that is
classified as held-to-maturity or available-for-sale. Securities categorized as held-to-maturity are stated at
amortized cost whereas available-for-sale securities are marked-to-market. As of December 31, 2007, and 2006,
the Company held $1.2 million and $1.5 million, respectively, of short-term investments.
Concentration of Credit Risk
Substantially all of the Company's receivables are within the oil and gas industry, primarily from purchasers
of oil and gas and from partners with interests in common properties operated by the Company. Although
diversified among many companies, collectability is dependent upon the financial wherewithal of each individual
company as well as the general economic conditions of the industry. The receivables are not collateralized. To date
the Company has had minimal bad debts.
The Company has accounts with separate banks in Denver, Colorado; Shreveport, Louisiana; Franklin,
Louisiana; Tulsa, Oklahoma; and Billings, Montana. At December 31, 2007, 2006, and 2005, the Company had
$42.8 million, $1.6 million, and $36.8 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 nine separate counterparties for its oil and gas commodity and interest rate
derivatives. The counterparties to the Company’s derivative instruments are all highly-rated entities with corporate
credit ratings at or exceeding A- or A2 as classified by Standard & Poor’s and Moody’s respectively.
Oil and Gas Producing Activities
The Company follows the successful efforts method of accounting for its oil and gas properties. Under this
method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized
when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does
not find proved reserves, the costs of drilling the well are charged to expense. Exploratory dry hole costs are
included in cash flows from investing activities as part of capital expenditures within the accompanying consolidated
statements of cash flows. The costs of development wells are capitalized whether or not proved reserves are found.
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 field-by-field basis
using the units-of-production method based upon proved reserves. The computation of DD&A takes into
consideration restoration, dismantlement, and abandonment costs and the anticipated proceeds from salvaging
equipment. As of December 31, 2007, the Company’s capitalized proved oil and gas properties included
$95.9 million of estimated salvage value, which is excluded from the depletable property costs when calculating
DD&A.
The Company follows Statement of Financial Accounting Standards Staff Position No. FAS 19-1,
“Accounting for Suspended Well Costs,” (“FSP FAS 19-1”). For additional discussion, please see Note 13 –
Disclosures about Oil and Gas Producing Activities under the heading Suspended Well Costs.
The Company reviews its long-lived assets for impairments when events or changes in circumstances
indicate that an impairment may have occurred. The impairment test for proved properties compares the expected
undiscounted future net cash flows on a field-by-field basis with the related net capitalized costs, including costs
associated with asset retirement obligations, at the end of each period. 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
F-8
is based on NYMEX strip pricing, adjusted for basis differentials, for the first five years. At the end of the first
five years a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these
estimates. When the net capitalized costs exceed the undiscounted future net revenues of a field, the cost of the
field is reduced to fair value, which is determined using discounted future net revenues. An impairment write
down is provided on unproved property when the Company determines that either the property will not be
developed or the carrying value is not realizable.
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 this treatment does not significantly affect the units-of-production depletion
rate. A gain or loss is recognized for all other sales of producing properties and is included in the results of
operations.
The sale of a partial interest in an unproved property is accounted for as a recovery of cost when substantial
uncertainty exists as to recovery of the cost applicable to the interest retained. A gain on the sale is recognized to the
extent 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 results of operations.
Assets Held for Sale
In accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment
or Disposal of Long-Lived Assets”, 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 obligation associated with oil and gas properties held for
sale. For additional discussion of assets held for sale, please see Note 3 – Acquisitions, Divestitures, and Assets
Held for Sale.
Other Property and Equipment
Other property and equipment such as office furniture and equipment, automobiles, 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 from three to eight years. When other
property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed
from the accounts.
Gas Balancing
The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized on
all gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the
property. An asset or a 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, 2007, and 2006,
resulted in the recording of $1.9 million and $1.4 million, respectively, to accounts receivable, and $1.1 million and
$791,000, respectively, to accounts payable.
Derivative Financial Instruments
The Company seeks to protect its rate of return on acquisitions of producing properties and other
production by hedging cash flows. The Company intends for derivative instruments used for this purpose to be
designated as, and to qualify as, cash flow hedging instruments under Statement of Financial Accounting
Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS No. 133”) and
related pronouncements. The Company seeks to minimize 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
F-9
proximity to the Company's areas of gas production. For additional discussion of derivatives, please see
Note 10 – Derivative Financial Instruments.
Fair Value of Financial Instruments
The Company’s financial instruments including cash and cash equivalents, accounts receivable, and
accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these
instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at
a floating rate. The Company had $285.0 million in loans outstanding under its revolving credit agreement as of
December 31, 2007, and $334.0 million in loans outstanding under its revolving credit agreement as of
December 31, 2006. The Company’s interest rate swaps are recorded at fair value as discussed in Note 10 –
Derivative Financial Instruments. The Company’s 3.50% Senior Convertible Notes due 2027 (the “3.50% Senior
Convertible Notes”) are recorded at cost, and the fair value is disclosed in Note 5 – Long-Term Debt. The
Company has other financial instruments and investments in available-for-sale securities that are marked-to-
market for which changes in fair value are recorded in accumulated other comprehensive income in the
accompanying consolidated balance sheets. Since considerable judgment is required to develop estimates of fair
value, the estimates provided are not necessarily indicative of the amounts the Company could realize upon the
sale or refinancing of such instruments.
Net Profits Plan
The Company records the estimated fair value of the liability for future payments under the Net Profits Plan.
The estimated liability is a discounted calculation and has underlying assumptions including estimates of oil and
gas reserves, recurring and workover lease operating expense, production and ad valorem tax rates, present value
discount factors, and pricing assumptions. The estimates the Company uses in calculating the long-term liability
are adjusted from period-to-period based on the most current information attributable to the underlying
assumptions. Changes in the estimated liability of future payments associated with the Net Profits Plan are
recorded as increases or decreases to expense in the current period as a separate line item in the accompanying
consolidated statements of operations as these changes are considered changes in estimates. The estimated Net
Profits Plan liability is recorded separately as a noncurrent liability in the accompanying consolidated balance
sheets.
The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash
compensation related to periodic operations are recognized as compensation expense and are included within general
and administrative expense and exploration expense in the accompanying consolidated statements of operations.
The corresponding current liability is included in accounts payable and accrued expenses in the accompanying
consolidated balance sheets. This treatment provides for a consistent matching of cash expense with net cash flows
from the oil and gas properties in each respective pool of the Net Profits Plan. For additional discussion, please see
Note 7 – Compensation Plans under the heading Net Profits Plan.
Income Taxes
The Company accounts for deferred income taxes utilizing Statement of Financial Accounting Standards
No. 109, “Accounting for Income Taxes,” ("SFAS No. 109") as amended. SFAS No. 109 prescribes an asset and
liability method whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary
differences between the carrying amount on the financial statements and the tax bases of assets and liabilities, as
measured by current enacted tax rates. These differences will result in taxable income or deductions in future years
when the reported amount of the asset or liability is recovered or settled, respectively. When appropriate, in
accordance with SFAS No. 109, the Company evaluates the need for a valuation allowance to reduce deferred tax
assets.
F-10
Earnings per Share
Basic net income per common share of stock is calculated by dividing net income available to common
stockholders by the weighted-average basic common shares outstanding for the respective period. The shares
represented by vested restricted stock units (“RSUs”) are included in the calculation of the weighted-average basic
common shares outstanding. The basic earnings per share calculations reflect the impact of any repurchases of
shares of common stock made by the Company.
Diluted net income per common share of stock is calculated by dividing adjusted net income by the
weighted-average diluted common shares outstanding, which includes the effect of potentially dilutive securities.
Potentially dilutive securities for the diluted earnings per share calculations consist of unvested RSUs, in-the-money
outstanding stock options to purchase the Company’s common stock, shares into which the 5.75% Senior
Convertible Notes due 2022 (the “5.75% Senior Convertible Notes”) were convertible for the periods those notes
were outstanding, and shares into which the 3.50% Senior Convertible Notes due 2027 are convertible.
The shares underlying the unvested grants of RSUs are included in the diluted earnings per share calculation
beginning on the grant date of the RSUs. Following the lapse of restriction periods, the shares underlying the units
are issued and therefore are included in the number of issued and outstanding shares.
The treasury stock method is used to measure the dilutive impact of stock options. The following table
details the weighted-average dilutive and anti-dilutive securities related to stock options and RSUs for the years
presented:
For the Years Ended December 31,
2006
2007
2005
Dilutive
Anti-dilutive
1,441,556
-
1,978,577
-
2,293,768
-
Prior to the conversion of the Company’s 5.75% Senior Convertible Notes on March 16, 2007, potentially
dilutive shares associated with this instrument were accounted for using the if-converted method for the
determination of diluted earnings per share. Adjusted net income used in the if-converted method was derived by
adding interest expense paid on the 5.75% Senior Convertible Notes back to net income and then adjusting for
nondiscretionary items that are based on net income and would have changed had the 5.75% Senior Convertible
Notes been converted at the beginning of the period. The 5.75% Senior Convertible Notes were called for
redemption by the Company on March 16, 2007, and all of the note holders elected to convert the notes to shares of
the Company’s common stock. The Company issued 7.7 million common shares in connection with the conversion
of the 5.75% Senior Convertible Notes. Upon conversion, these shares were included in the calculation of weighted-
average common shares outstanding. The diluted earnings per share calculation for the year ended
December 31, 2007, was adjusted for the conversion and included a time-weighted average of approximately
1.6 million potentially dilutive shares related to the 5.75% Senior Convertible Notes. A total of 7.7 million
potentially dilutive shares related to the 5.75% Senior Convertible Notes were included in the calculation of diluted
earnings per share for the years ended December 31, 2006, and 2005.
The Company’s 3.50% Senior Convertible Notes have a net-share settlement right, and the treasury stock
method is used to measure the potentially dilutive impact of shares associated with that conversion feature. The
3.50% Senior Convertible Notes issued April 4, 2007 have not been dilutive for the entire time they have been
outstanding and therefore do not impact the diluted earnings per share calculation for the period ended
December 31, 2007.
The dilutive impact of unvested RSUs and stock options is considered in the detailed calculations below.
There were no anti-dilutive securities related to stock options or RSUs for the years ended December 31, 2005,
2006, and 2007.
F-11
The following table sets forth the calculation of basic and diluted earnings per share:
For the Years Ended December 31,
2007
2005
2006
(In thousands, except per share amounts)
Net income
$ 189,712
$ 190,015
$ 151,936
Adjustments to net income for dilution:
Add: Interest expense not incurred if 5.75% Senior
Convertible Notes converted
Less: Other adjustments
Less: Income tax effect of adjustment items
Net income adjusted for the effect of dilution
Basic weighted-average common shares outstanding
Add: Dilutive effect of stock options and unvested
1,285
(13)
(469)
$ 190,515
6,337
(63)
(2,237)
$ 194,052
6,337
(64)
(2,275)
$ 155,934
61,852
56,291
56,907
restricted stock units
1,441
1,979
2,295
Add: Dilutive effect of 5.75% Senior Convertible
Notes using the if-converted method
Diluted weighted-average common shares outstanding
1,557
64,850
7,692
65,962
7,692
66,894
Basic earnings per common share:
Diluted earnings per common share:
$
$
3.07
2.94
$
$
3.38
2.94
$
$
2.67
2.33
Stock-Based Compensation
At December 31, 2007, the Company had stock-based employee compensation plans that included RSUs
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. Prior to 2006, the Company had accounted
for stock-based compensation using the intrinsic value recognition and measurement principles detailed in
Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” ("APB Opinion No. 25")
and related interpretations. No stock-based employee compensation expense relating to stock options has been
reflected in the Company’s accompanying consolidated statements of operations for any period presented prior to
2006 since all options granted under the plans had an exercise price equal to the market value of the underlying
common stock on the date of grant. The Company used the Black-Scholes option valuation model to calculate the
disclosures required under Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based
Compensation” (“SFAS No. 123”). Beginning January 1, 2006, the Company adopted the provisions of Statement
of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS No. 123(R)”). This statement
requires the Company to record expense associated with the fair value of stock-based compensation. The total
unrecognized compensation expense associated with unvested stock options at the date of adoption of this standard
totaled $2.4 million. The Company elected to use the modified-prospective adoption method for the standard and
consequently recognized additional compensation expense of $1.9 million in 2006 and $437,000 in 2007, and
expects to recognize expense of $17,000 in 2008 related to the vesting of these stock options. The Company has
recorded compensation expense associated with the issuance of RSUs since the plan was adopted in 2004 and units
were first granted. The Company recognizes costs associated with these grants based on the estimated fair value of
the RSUs as determined at the time of the grant.
F-12
The following table illustrates the pro forma effect on net income and earnings per share if the Company
had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation prior to
the implementation of SFAS No. 123(R):
For the Year Ended December 31, 2005
(In thousands, except per share amounts)
Net income
As reported:
Add: stock-based employee compensation
expense included in reported net income, net
of related tax effects
Less: stock-based employee compensation
expense determined under fair value method for
all awards, net of related income tax effects
Pro forma
Pro forma basic earnings per share
Pro forma diluted earnings per share
$ 151,936
4,453
(6,282)
$ 150,107
$
2.64
$
2.30
For purposes of pro forma disclosures, the estimated fair values of the options and employee stock
purchase plan grants are amortized to expense over the options’ vesting periods. The effects of applying
SFAS No. 123 in the pro forma disclosure are not necessarily indicative of actual future amounts.
Recently Issued Accounting Standards
In December 2007 the FASB issued Statement of Financial Accounting Standards No. 141(R), “Business
Combinations” (“SFAS No. 141(R)”), which requires the acquiring entity in a business combination to recognize
and measure all assets and liabilities assumed in the transaction and any non-controlling interest in the acquiree at
fair value as of the acquisition date. SFAS No. 141(R) also establishes guidance for the measurement of the
acquirer shares issued in consideration for a business combination, the recognition of contingent consideration,
the accounting treatment for pre-acquisition gain and loss contingencies, the treatment of acquisition related
transaction costs, and the recognition of changes in the acquirer's income tax valuation allowance and deferred
taxes. SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008, and is to be applied
prospectively as of the beginning of the fiscal year in which the statement is applied. Early adoption is not
permitted. SFAS No. 141(R) will be effective for the Company beginning with the 2009 fiscal year. The
Company is currently evaluating the impact of SFAS No. 141(R) on its accompanying consolidated financial
statements when effective, but the nature and magnitude of the specific effects will depend upon the nature, terms,
and size of the acquisitions the Company consummates after the effective date.
In December 2007 the FASB issued Statement of Financial Accounting Standards No. 160,
“Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB 51” (“SFAS No. 160”),
which establishes accounting and reporting standards that require noncontrolling interests to be reported as a
component of equity. SFAS No. 160 also requires that changes in a parent's ownership interest while the parent
retains its controlling interest be accounted for as equity transactions and that any retained noncontrolling equity
investment upon the deconsolidation of a subsidiary be initially measured at fair value. SFAS No. 160 is effective
for fiscal years beginning after December 15, 2008, and is to be applied prospectively as of the beginning of the
fiscal year in which the statement is applied. The Company is required to adopt SFAS No. 160 beginning with
the 2009 fiscal year. The Company is currently evaluating the potential impact, if any, of the adoption of
SFAS No. 160 on its accompanying consolidated financial statements when effective.
F-13
In February 2007 the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair
Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which expands the use of fair
value accounting but does not affect existing standards that require assets or liabilities to be carried at fair value.
SFAS No. 159 allows entities to choose, at specified election dates, to use fair value to measure eligible financial
assets and liabilities that are not otherwise required to be measured at fair value. If a company elects the fair
value option for an eligible item, changes in that item's fair value in subsequent reporting periods must be
recognized in current earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed
to draw comparisons between entities that elect different measurement attributes for similar assets and liabilities.
If elected, SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. SFAS No. 159 will be
effective for the Company beginning with the 2008 fiscal year. The Company did not elect the fair value option.
There is no impact on the Company’s consolidated financial statements.
In September 2006 the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value
Measurements” (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value,
and expands disclosures about fair value measurements. The provisions of SFAS No. 157 will be effective as of
the beginning of the Company’s 2008 fiscal year. The adoption of SFAS No. 157 has no impact on the
Company’s consolidated financial statements, however, it will require changes in certain disclosures.
Comprehensive Income
Comprehensive income consists of net income, the unrealized gain or loss for the effective portion of
derivative instruments classified as cash flow hedges, and the accrued pension benefit obligation in excess of plan
assets. Comprehensive income is presented net of income taxes in the accompanying consolidated statements of
stockholders’ equity and comprehensive income.
The changes in the balances of components comprising other comprehensive income and loss are
presented in the following table:
Derivative
Instruments
Pension
Liability
Adjustment
(In thousands)
Other
Comprehensive
Income (Loss)
For the period ending December 31, 2005
Before tax income (loss)
Tax benefit (expense)
After deferred tax income (loss)
$
$
(92,097)
34,941
(57,156)
For the period ending December 31, 2006
Before tax income (loss)
Tax benefit (expense)
After deferred tax income (loss)
$ 111,437
(42,459)
68,978
$
For the period ending December 31, 2007
Before tax income (loss)
Tax benefit (expense)
After deferred tax income (loss)
$ (272,655)
102,688
$ (169,967)
$
$
$
$
$
$
455
(172)
283
(290)
110
(180)
119
(49)
70
$
$
$
$
$
$
(91,642)
34,769
(56,873)
111,147
(42,349)
68,798
(272,536)
102,639
(169,897)
F-14
Major Customers
During 2007 and 2006 no customer individually accounted for more than ten percent of the Company’s total
oil and gas production revenue. During 2005 one customer individually accounted for 13 percent of the Company’s
total oil and gas production revenue.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration, exploitation, development,
acquisition, and production of natural gas and crude oil. All of the Company’s operations are conducted in the
continental United States and the Gulf of Mexico. Consequently, the Company currently reports as a single industry
segment. The Company’s gas marketing department provides mostly internal services, acting as a first purchaser of
natural gas and natural gas liquids produced by the Company and as such the majority of the Company’s marketing
activity is eliminated in consolidation. The small amount of third-party income these operations generate is not
material to the Company’s financial position, and segmentation of such net income would not provide a better
understanding of the Company’s performance. However, gross revenue and expense related to gas marketing
operations are presented discreetly in the accompanying consolidated statements of operations.
Intangible Assets
As of December 31, 2007, and 2006, the Company’s accompanying consolidated balance sheets include
$2.4 million and $3.4 million, respectively, of intangible assets. These assets arise from acquired oil and gas sale
contracts with favorable pricing terms. They do not qualify as derivatives or hedges under SFAS No. 133.
Intangible assets of the Company are amortized using the units-of-production method and are evaluated for
impairment if such indicators arise. Intangible assets are included in other noncurrent assets on the Company’s
accompanying consolidated balance sheets.
Goodwill
Goodwill is measured as the excess of the acquisition costs over the sum of the amounts assigned to the
identifiable assets acquired less liabilities assumed. Goodwill was recorded as a result of the acquisition of Agate
Petroleum, Inc. in January 2005. Goodwill is reviewed for impairment annually or more frequently if impairment
indicators arise. The goodwill review is conducted at the reporting unit level. A reporting unit is defined as the oil
and gas properties in a region.
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, 2007, 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.
F-15
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
Other
Total accounts receivable
As of December 31,
2007
2006
(In thousands)
$ 115,534
37,860
5,755
$ 159,149
$ 95,036
33,309
14,376
$ 142,721
Accounts payable and accrued expenses are comprised of the following:
As of December 31,
2007
2006
(In thousands)
Accrued drilling costs
Revenue payable
Accrued lease operating expense
Accrued taxes
Accrued interest
Accrued compensation
Trade payables
Accrued payments to hedge contract
counterparties
Plug and abandonment liability on offshore
platform related to Hurricane Rita
Accrued marketed gas system expense
Other
$ 112,481
37,048
14,604
5,042
3,590
17,887
28,187
9,640
3,108
13,520
9,811
$ 68,326
27,591
11,153
2,358
2,846
10,323
37,152
665
-
6,396
5,024
Total account payable and accrued expenses
$ 254,918
$ 171,834
Note 3 – Acquisitions, Divestitures, and Assets Held for Sale
Rockford Acquisition
On October 4, 2007, the Company completed the purchase of certain oil and gas properties in the Gold
River project area targeting the Olmos shallow gas formation located primarily in Webb and Dimmit Counties,
Texas. The assets were purchased from Rockford Energy Partners II, LLC for $148.9 million of cash, which is
net of normal purchase price adjustments of $2.1 million. The acquisition was funded with cash on hand and
borrowings under the Company’s existing revolving credit facility. The Company allocated $127.2 million to
proved oil and gas properties, $23.1 million to unproved oil and gas properties, and a net $292,000 to other assets.
The Company also recorded $1.7 million in asset retirement obligation liability associated with the acquired
properties. This property acquisition is adjacent to the recently acquired Catarina project area discussed below.
The Company has hedged the equivalent of the first three years of natural gas production and the first two years
of associated natural gas liquids production related to this acquisition.
F-16
Variable Interest Entity
The acquisition of the properties in the Gold River project area was structured to qualify as the first step
of a reverse like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended ("the
IRC"), and I.R.S. Revenue Procedure 2000-37. Prior to closing on the Rockford acquisition, the Company
assigned all of its rights and duties under the purchase and sale agreement to NBF Reverse Exchange, LLC, an
indirect wholly-owned subsidiary of Comerica Incorporated, which further assigned all of its rights and duties
under the purchase and sale agreement to St. Mary Land & Exploration Acquisition, LLC (“SMLEA, LLC”), a
company unaffiliated with St. Mary. The Gold River assets were acquired by NBF Reverse Exchange, LLC as an
exchange accommodation titleholder. SMLEA, LLC held the assets pursuant to a qualified exchange
accommodation agreement until the second step of the like-kind exchange was completed in conjunction with the
divestiture of certain non-core oil and gas properties discussed below under Assets Held for Sale. As of the date
of closing on October 4, 2007, the assets held by SMLEA, LLC, were leased by St. Mary under a triple net lease
whereby St. Mary enjoyed the benefits and risks of all revenues and costs attributed to the properties. The Gold
River assets were managed by St. Mary under the terms of a management agreement with SMLEA, LLC.
In connection with the reverse like-kind exchange described above, St. Mary loaned an amount equal to
the purchase price of the assets to SMLEA, LLC. Based on the provisions of FASB Interpretation No. 46(R),
“Consolidation of Variable Interest Entities”, the Company determined that SMLEA, LLC is a variable interest
entity for which St. Mary is the primary beneficiary. Accordingly, SMLEA, LLC was consolidated into St. Mary
subsequent to the completion of the purchase of oil and gas properties on October 4, 2007. As a result of the
consolidation, St. Mary recognized all oil and gas reserves and production as well as all revenues and expenses
attributed to the Rockford acquisition beginning on October 4, 2007.
Catarina Acquisition
On June 1, 2007, the Company acquired oil and gas properties located primarily in the Catarina project
area in Webb County, Texas in exchange for $30.0 million of cash. The Company allocated $29.9 million to
proved oil and gas properties, $535,000 to unproved oil and gas properties, and a net $215,000 to other assets.
The Company also recorded $623,000 in 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.
Permian Basin Acquisition
On December 14, 2006, the Company acquired oil and gas properties in the Permian Basin in West Texas
from private parties in exchange for $243.1 million of cash, which is net of normal purchase price adjustments of
approximately $4.3 million. The Company recorded $199.1 million to proved oil and gas properties,
$41.5 million to unproved oil and gas properties, $3.0 million to intangible assets, a net $326,000 to other assets,
and $859,000 to asset retirement obligation liability. The Company allocated the purchase price based on the
estimated fair value of the assets and liabilities acquired. The acquisition was accounted for using the purchase
method and was funded with cash on hand and borrowings under the Company’s credit facility.
Richland County, Montana Acquisition
On May 15, 2006, the Company closed on a transaction whereby it exchanged oil and gas properties
located in the Uinta Basin of Utah for oil and gas properties located in Richland County, Montana. The
transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code of
1986, as amended, and I.R.S. Revenue Procedure 2000-37. For financial reporting purposes, the transaction is
considered a non-monetary exchange and was accounted for at estimated fair value. The exchange of properties
resulted in recognition of approximately $6.4 million of gain.
F-17
Assets Held for Sale
In December 2007 St. Mary reached an agreement for the sale of its previously announced divestiture
package, and on January 31, 2008, the Company completed the divestiture of certain non-strategic oil and gas
properties located primarily in the Rocky Mountain and Mid-Continent regions to Abraxas Petroleum Corporation
and Abraxas Operating, LLC. The cash received at closing before commission costs was $131.1 million. The final
sale price is subject to normal post-closing adjustments and settlements and is expected to be finalized during the
second quarter of 2008. The transaction has an effective date of December 1, 2007. The accompanying
consolidated balance sheet as of December 31, 2007, presents the $76.9 million assets held for sale, net of
accumulated depletion, depreciation and amortization. The corresponding asset retirement obligation of $8.7 million
and a $10.0 million deposit associated with oil and gas properties held for sale are also separately presented. Under
FASB Emerging Issues Task Force Issue No. 03-13, the Company determined that these sales do not qualify for
discontinued operations accounting.
Note 4 – Income Taxes
The provision for income taxes consists of the following:
Current taxes:
Federal
State
Deferred taxes
Total income tax expense
For the Years Ended December 31,
2005
2006
2007
(In thousands)
$ 15,136
2,459
92,955
$ 110,550
$ 28,557
1,917
74,832
$ 105,306
$ 75,848
4,906
5,547
$ 86,301
F-18
As a result of the exercise of stock options, the Company was able to reduce its income tax payable in each
year presented. The tax benefit to the Company of stock option exercises was $9.9 million in 2007, $16.1 million in
2006, and $6.0 million in 2005.
The components of the net deferred tax liability are as follows:
Deferred tax liabilities:
Oil and gas properties
Unrealized derivative asset
Interest on Senior Convertible Notes
Other
Total deferred tax liabilities
Deferred tax assets:
Net Profits Plan liability
Unrealized derivative liability
Stock compensation
State tax net operating loss carryforward or carryback
State and federal income tax benefit
Other long-term liabilities
Employee benefits and other
Deferred capital loss
Other
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,
2007
2006
(In thousands)
$
$
412,669
-
2,596
1,429
416,694
79,552
93,829
8,849
6,808
2,939
1,724
1,543
-
614
195,858
(3,556)
192,302
224,392
(1,425)
34,636
257,603
933
(105)
$
$
$
$
$
$
299,082
17,184
6,925
59
323,250
59,537
8,174
8,104
4,589
2,285
2,026
1,391
619
-
86,725
(2,660)
84,065
239,185
(17,188)
2,521
224,518
7,293
391
At December 31, 2007, the Company had estimated state net operating loss carryforwards of approximately
$162.5 million that expire between 2008 and 2027 and state tax credits of $145,000 that expire between 2008 and
2016. A portion of the Company’s valuation allowance relates to state net operating loss carryforwards, state tax
credits, and state and federal income tax benefit amounts that the Company anticipates will expire before they can be
utilized. The Company has concluded that permanent items included in the calculation of income tax for certain
states may impact its ability to deduct net operating losses and realize federal income tax deduction benefits of those
states and has adjusted its valuation allowances accordingly. The remaining portion of the valuation allowance
relates to the Net Profits Plan liability and reflects an estimate of future executive compensation that may not be
deductible for income tax purposes when future cash payments occur under the plan.
F-19
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, and other permanent differences, as
follows:
Federal statutory taxes
Increase (reduction) in taxes resulting from:
State taxes (net of federal benefit)
Statutory depletion
Domestic production activities deduction
Other
Change in valuation allowance
Income tax expense from operations
For the Years Ended December 31,
2005
2006
2007
(In thousands)
$ 105,092
$ 103,504
$ 83,307
5,111
(407)
(384)
242
896
$ 110,550
2,081
(315)
(287)
235
88
$ 105,306
4,185
(224)
(1,717)
(108)
858
$ 86,301
Acquisitions, drilling, and basis differentials impacting the prices received for crude oil and natural gas,
affect the apportionment of taxable income to the states where the Company owns properties. As these factors
change, the Company’s blended state income tax rate changes. This change applied to the Company’s total
temporary differences will impact 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 upon completion of the prior year
income tax return and after significant acquisitions are closed during the current year.
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various
states. With few exceptions, the Company is no longer subject to U.S. federal or state income tax examinations
by these tax authorities for years before and including 2003. The Internal Revenue Service completed audits for
the 2000, 2002, and 2003 tax years during the quarter ended March 31, 2007. There was no change to the
provision for income tax as a result of these examinations.
In the third quarter of 2007 the Company received a refund of income tax and interest of $3.1 million
from a carryback of net operating losses to the 2000 tax year. An additional $1.0 million due to the Company for
income tax refunds and accrued interest resulting from a carry over of minimum tax credits to the 2003 tax year
was received in January 2008. These amounts have been previously recognized by the Company.
The Company adopted the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in
Income Taxes" (“FIN No. 48”), on January 1, 2007. There was no financial statement adjustment required as a
result of adoption. At adoption, the Company had a long-term liability for unrecognized tax benefit of
$1.0 million and accumulated interest liability of $92,000. The entire amount of unrecognized tax benefit would
affect the Company’s effective tax rate if recognized. Interest expense in the 2007 accompanying consolidated
statements of operations includes a nominal $4,000 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, 2007.
F-20
The total amount recorded for unrecognized tax benefits for the year ended December 31, 2007, is
presented below (in thousands):
Balance at January 1, 2007
Additions for tax positions of prior years
Reductions for lapse of statute of limitations
$
1,112
233
(388)
Balance at December 31, 2007
$
957
Note 5 – Long-term Debt
Revolving Credit Facility
The Company’s revolving credit facility specifies a maximum loan amount of $500 million and has a
maturity date of April 7, 2010. Borrowings under the facility are secured by a pledge in favor of the lenders of
collateral that includes the majority of the Company’s oil and gas properties and the common stock of the material
subsidiaries of the Company. The borrowing base under the credit facility as authorized by the bank group as of
the date of this filing is $1.25 billion and is subject to regular semi-annual redeterminations. The borrowing base
redetermination process considers the value of St. Mary’s oil and gas properties and other assets, as determined by
the bank syndicate. The Company has elected an aggregate commitment amount of $500 million under the credit
facility. The Company must comply with certain financial and non-financial covenants under its existing credit
facility. The Company is in compliance with all covenants associated with the credit facility. The payment of
dividends is subject to covenants under the Company’s existing credit facility, including the requirement that the
Company maintain certain levels of stockholders’ equity and the limitation of the Company’s annual dividend rate to
no more than $0.25 per share per year. Interest and commitment fees are accrued based on the borrowing base
utilization percentage table below. Euro-dollar loans accrue interest at London Interbank Offered Rate
(“LIBOR”) plus the applicable margin from the utilization table, and Alternative Base Rate (“ABR”) loans accrue
interest at Prime plus the applicable margin from the utilization table. Commitment fees are accrued on the
unused portion of the aggregate commitment amount and are included in interest expense in the accompanying
consolidated statements of operations.
Borrowing base
utilization percentage
Euro-dollar loans
ABR loans
Commitment fee rate
<50%
1.000%
0.000%
0.250%
>50%<75%
1.250%
0.000%
0.300%
>75%<90%
1.500%
0.250%
0.375%
>90%
1.750%
0.500%
0.375%
The Company had $285.0 million and $180.0 million in outstanding loans under its revolving credit
agreement on December 31, 2007, and February 15, 2008, respectively.
5.75% Senior Convertible Notes Due 2022
The Company called for redemption of its 5.75% Senior Convertible Notes on March 16, 2007. The call
for redemption resulted in the note holders electing to convert the notes to common stock in accordance with the
conversion provision in the original indenture. The 5.75% Convertible Note holders converted all $100 million of
the 5.75% Senior Convertible Notes to common shares at a conversion price of $13.00 per share. The Company
issued 7.7 million common shares in connection with the conversion.
3.50% Senior Convertible Notes Due 2027
On April 4, 2007, the Company issued $287.5 million aggregate principal amount of 3.50% Senior
Convertible Notes. The 3.50% Senior Convertible Notes mature on April 1, 2027, unless earlier converted,
redeemed, or purchased by the Company. The 3.50% Senior Convertible Notes are unsecured senior obligations
F-21
and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and
senior in right of payment to any future subordinated debt.
Holders may convert their notes based on a conversion rate of 18.3757 shares of the Company’s common
stock per $1,000 principal amount of the 3.50% Senior Convertible Notes (which is equal to an initial conversion
price of approximately $54.42 per share), subject to adjustment, contingent upon and only under the following
circumstances: (1) if the closing price of the Company's common stock reaches specified thresholds or the trading
price of the notes falls below specified thresholds, (2) if the notes are called for redemption, (3) if specified
distributions to holders of the Company’s common stock are made or specified corporate transactions occur, (4) if
a fundamental change occurs, or (5) during the ten trading days prior to, but excluding, the maturity date. The
notes and underlying shares have been registered under a shelf registration statement. If the Company becomes
involved in a material transaction or corporate development, it may suspend trading of the 3.50% Senior
Convertible Notes under the prospectus. In the event the suspension period exceeds 45 days within any three-
month period or 90 days within any twelve-month period, the Company will be required to pay additional interest
to all holders of the 3.50% Senior Convertible Notes, not to exceed a rate per annum of 0.50 percent of the issue
price of the 3.50% Senior Convertible Notes; provided that no such additional interest shall accrue after
April 4, 2009.
Upon conversion of the 3.50% Senior Convertible Notes, holders will receive cash or common stock, or
any combination thereof as elected by the Company. At any time prior to the maturity date of the notes, the
Company has the option to unilaterally and irrevocably elect to settle its obligations upon conversion of the notes
in cash and, if applicable, shares of common stock. If the Company makes this election, then, for each $1,000
principal amount of notes converted, the Company will pay the following to holders 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 offering memorandum as business conditions warrant.
If a holder elects to convert its notes in connection with certain events that constitute a change of control
before April 1, 2012, the Company will pay, to the extent described in the related indenture, a make-whole
premium by increasing the conversion rate applicable to the 3.50% Senior Convertible Notes. In addition, the
Company will pay contingent interest in cash, commencing with any six-month period beginning on or after
April 1, 2012, if the average trading price of a note for the five trading days ending on the third trading day
immediately preceding the first day of the relevant six-month period equals 120 percent or more of the principal
amount of the 3.50% Senior Convertible Notes.
On or after April 6, 2012, the Company may redeem for cash all or a portion of the 3.50% Senior
Convertible Notes at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed
plus accrued and unpaid interest, if any, up to but excluding, the applicable redemption date. Holders of the
3.50% Senior Convertible Notes may require the Company to purchase all or a portion of their notes on each of
April 1, 2012, April 1, 2017, and April 1, 2022, at a purchase price equal to 100 percent of the principal amount
of the notes to be repurchased plus accrued and unpaid interest, if any, up to but excluding the applicable purchase
date. On April 1, 2012, the Company may pay the purchase price in cash, in shares of common stock, or in any
combination of cash and common stock. On April 1, 2017, and April 1, 2022, the Company must pay the
purchase price in cash. Based on the market price of the 3.50% Senior Convertible Notes, the estimated fair value
of the notes was approximately $296 million as of December 31, 2007.
In August 2007 the FASB proposed FASB Staff Position APB 14-a, “Accounting for Convertible Debt
Instruments That May Be Settled in Cash Upon Conversion (including Partial Cash Settlement)” (“FSP
APB 14-a”). FSP APB 14-a proposes that the accounting treatment for certain convertible debt instruments that
may be settled in cash, shares of common stock, or any portion thereof at the election of the issuing company be
accounted for utilizing a bifurcation model under which the value of the debt instrument would be determined
F-22
without regard to the conversion feature. As of the date of this filing, FSP APB 14-a remains a proposed FASB
staff position under redeliberation.
Weighted-Average Interest Rate Paid and Capitalized Interest
The weighted-average interest rate paid in 2007, 2006, and 2005 was 5.4 percent, 7.6 percent, and
7.1 percent, respectively, including commitment fees paid on the unused portion of the credit facility aggregate
commitment, amortization of deferred financing costs, amortization of the contingent interest embedded derivative
associated with the 5.75% Senior Convertible Notes, and the effect of interest rate swaps. The average outstanding
loan balance in 2007 grew at a faster rate than the aforementioned items resulting in a lower weighted-average
interest rate. Capitalized interest costs for the Company for the years ended December 31, 2007, 2006, and 2005,
were $5.4 million, $3.5 million, and $1.9 million, respectively.
Note 6 – Commitments and Contingencies
The Company has entered into various operating leases, some of which include drilling rig contracts of,
approximately $25.5 million, office space leases of approximately $14.1 million, and compressor contracts of
approximately $2.0 million. The annual minimum lease payments for the next five years and thereafter are
presented below:
Years Ending December 31,
2008
2009
2010
2011
2012
Thereafter
Total
(In thousands)
$ 29,119
5,882
3,747
3,352
1,335
814
$ 44,249
The Company leases office space under various operating leases with terms extending as far as
May 31, 2014. Rent expense, net of sublease income, was $1.9 million, $1.5 million, and $1.3 million in 2007,
2006, and 2005, respectively. The Company also leases office equipment under various operating leases. The
Company has a non-cancelable sublease through May 2012, of approximately $816,000, with payments of $185,000
per year through 2011 and $77,000 in 2012.
The Company is subject to litigation and claims that have arisen in the ordinary course of business. The
Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In
the opinion of management, the results of such litigation and claims will not have a material effect on the results of
operations, the financial position, or cash flows of the Company. Management believes it has sufficiently provided
for such items to the extent necessary in the consolidated balance sheets.
Note 7 – Compensation Plans
Cash Bonus Plan
The Company has a cash bonus plan under which the Company can award participants a cash bonus of up to
50 percent of their aggregate base salary. Any awards under the cash bonus plan are based on Company and
regional performance, and then are further refined by individual performance. The Company accrues cash bonus
expense related to the current year’s performance. Included in the general and administrative and exploration
expense line items in the accompanying consolidated statements of operations are $3.6 million, $1.9 million, and
$7.4 million of cash bonus expense related to the specific performance year for the years ended December 31, 2007,
2006, and 2005, respectively.
F-23
Net Profits Plan
Under the Company’s Net Profits Plan, all oil and gas wells that are completed or acquired during a year
are 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 become entitled to payments under the Net Profits Plan after the Company
has received net cash flows returning 100 percent of all costs associated with that pool. Thereafter, ten percent of
future net cash flows generated by the pool are allocated among the participants and distributed at least annually.
The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the
Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits
Plan at the ten percent level. The Net Profits Plan has been in place since 1991. Pool years prior to and including
2005 are fully vested. The 2006 and 2007 Pool years carry a vesting period of three years, whereby one-third is
vested at the end of the year for which participation is designated and one-third vests on each of the following two
anniversary dates. The 2006 and 2007 Pool years include a cap whereby the maximum benefit to full participants
from a particular year’s pool is limited to 300 percent of a participating individual’s adjusted base salary paid
during the year to which the pool relates. In December 2007 the Board approved a restructuring of the
Company’s incentive compensation programs. The change in the incentive compensation structure is designed to
replace the current programs involving the grant of RSUs and the grant of participation interests in the Net Profits
Plan with a single long-term incentive program utilizing performance shares. As a result, the 2007 Net Profits
Plan pool will be the last pool established by the Company.
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. Historically and for a
predominate number of the pools, a discount rate of 15 percent was used to calculate this liability and is intended
to represent the best estimate of the present value of expected future payments under the Net Profits Plan. During
the fourth quarter of 2007, the Company adjusted the discount rate used to calculate the present value of future
payments from a base rate of 15 percent to 12 percent. The decrease in the discount rate to 12 percent was based
on experience gained from the divestiture marketing process, an overall sense of the valuation of oil and gas
assets and an assessment of the current market for proved oil and gas reserves.
The Company’s estimate of its liability is highly dependent on the price and cost assumptions, as well as
the discount rates used in the calculations. The commodity price assumptions are formulated by applying a price
that is derived from a rolling average of actual prices realized over the prior 24 months together with adjusted
NYMEX strip prices for the ensuing 12 months for a total of 36 months of data. This average is adjusted to
include the effect of hedge prices for the percentage of forecasted production hedged in the relevant period. The
forecasted non-cash expense associated with this significant management estimate is highly volatile from period
to period due to fluctuations that occur in the crude oil and natural gas commodity markets. Higher commodity
prices experienced in recent years have moved more pools into payout status. The Company continually
evaluates the assumptions used in this calculation in order to include the current market environment for oil and
gas prices, costs, discount rates, and overall market conditions.
No published market quotes exist on which to base the Company’s estimate of fair value of the Net
Profits Plan. As such, it is entirely based on management estimates which are described within this footnote.
While some inputs to the Company’s calculation to estimate the fair value of the Net Profits Plan’s future
payments are from published sources, others are derived from the Company’s own calculations and estimates,
such as the approximated discount rate and the expected future cash flows.
F-24
The following table presents the changes in the estimated future liability attributable to the Net Profits
Plan. These amounts relate to the realized results for the years presented from oil and gas operations for the
properties associated with the respective pools that have achieved payout status.
As of December 31,
2007
2006
(In thousands)
Liability balance for Net Profits Plan as of the beginning of
the period
Increase in liability
$
160,583
82,734
$
136,824
49,900
Reduction in liability for cash payments made or accrued
and recognized as compensation expense
(31,911)
(26,141)
Liability balance for Net Profits Plan as of the end of
the period
$
211,406
$
160,583
The calculation of the estimated liability for the Net Profits Plan is highly sensitive to price estimates and
discount rate assumptions. For example, if the commodity prices used in the calculation changed by five percent,
the liability recorded at December 31, 2007, would differ by approximately $19 million. A one percentage point
decrease in the discount rate would result in an increase to the liability of approximately $12 million. While a
one percentage point increase in the discount rate would result in a decrease to the liability of approximately
$10 million. Actual cash payments to be made to participants in future periods are dependent on realized actual
production, prices, and costs associated with the properties in each individual pool of the Net Profits Plan.
Consequently, actual cash payments will be inherently different from the amounts estimated.
The Company records changes in the present value of estimated future payments under the Net Profits Plan
as a separate item in the accompanying consolidated statements of operations. The change in the estimated liability
is recorded as a non-cash expense or benefit in the current period. The amount recorded as an expense or benefit
associated with the change in the estimated liability is not allocated to general and administrative expense or
exploration expense because it is associated with the future net cash flows from oil and gas properties in the
respective pools rather than results realized in the current period. The table below presents the estimated allocation
of the change in the liability if the Company did allocate the adjustment to these specific functional line items based
on the current allocation of actual distributions being made by the Company. The change in allocation of costs to
the functional classification relates to the current composition of employees as compared to those individuals that
have terminated employment with the Company. For the years ended December 31, 2007, 2006, and 2005,
22 percent, 54 percent, and 51 percent, respectively, of payments made under the Net Profits Plan were classified as
exploration expense in the accompanying consolidated statements of operations. As time progresses, less of the
distribution relates to prospective exploration efforts as more of the distributions are made to employees that have
terminated employment and thereby do not provide any period exploration support.
General and administrative expense
Exploration expense
Total
401(k) Plan
$
$
2007
For the Years Ended December 31,
2006
(In thousands)
10,342
$
13,417
23,759
$
$
$
41,803
9,020
50,823
2005
51,419
54,844
106,263
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 contributions up to six percent of the employee's base
F-25
salary and may make additional contributions at its discretion. The Company’s contributions to the 401(k) Plan
were $1.5 million, $1.2 million, and $966,000 for the years ended December 31, 2007, 2006, and 2005, respectively.
No discretionary contributions were made by the Company to the 401(k) Plan in any of these years.
Employee Stock Purchase Plan
Under the St. Mary Land & Exploration Company Employee Stock Purchase Plan (“the ESPP”), eligible
employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent
of eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the
stock on the first or last day of the purchase period, and shares issued under the ESPP are restricted for a period of
18 months from the date issued. The ESPP is intended to qualify under Section 423 of the IRC. The Company
has set aside 2,000,000 shares of its common stock to be available for issuance under the ESPP, of which
1,599,811 shares are available for issuance as of December 31, 2007. Shares issued under the ESPP totaled
29,534 in 2007, 26,046 in 2006, and 28,447 in 2005. Total proceeds to the Company for the issuance of these
shares were $919,000 in 2007, $814,000 in 2006, and $601,000 in 2005.
The fair value of ESPP shares are measured at the date of grant using the Black-Scholes option-pricing
model. The fair values of ESPP shares issued were estimated using the following weighted-average assumptions:
Risk free interest rate
Dividend yield
Volatility factor of the expected market
price of the Company's common stock
Expected life (in years)
For the Years Ended December 31,
2007
2005
2006
4.1%
0.3%
5.1%
0.3%
2.5%
0.4%
27.19%
0.5
36.7%
0.5
36.3%
0.5
For the ESPP offering periods during 2007 and 2006, the Company expensed $260,000 and $243,000,
respectively, based on the estimated fair values of grants on the respective grant dates. There was no expense
related to ESPP shares recorded in 2005.
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. For example, the Company
ceased issuing stock options and began issuing restricted stock or RSUs to employees and directors in 2004.
These disclosures reflect the culmination of the disclosure requirements for all equity awards still outstanding.
In May 2006 the stockholders approved the 2006 Equity Incentive Compensation Plan (the “2006 Equity
Plan”) to authorize the issuance of restricted stock, RSUs, non-qualified stock options, incentive stock options,
stock appreciation rights, and stock-based awards to key employees, consultants, and members of the Board of
Directors of St. Mary or any affiliate of St. Mary. The 2006 Equity Plan serves as the successor to the St. Mary
Land & Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock
Option Plan, the St. Mary Land & Exploration Company Restricted Stock Plan, and the St. Mary Land &
Exploration Company Non-Employee Director Stock Compensation Plan (collectively referred to as the
“Predecessor Plans”). All grants of equity are now made out of the 2006 Equity Plan, and no further grants will
be made under the Predecessor Plans. Each outstanding award under a Predecessor Plan prior to the effective date
of the 2006 Equity Plan continues to be governed solely by the terms and conditions of the instruments
evidencing such grants or issuances.
Effective January 1, 2006, the Company adopted SFAS No. 123(R) using the modified-prospective
transition method. Under that transition method, compensation expense recognized in 2006 and 2007 includes:
(a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006,
based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and
F-26
(b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant
date fair value estimated in accordance with the provisions of SFAS No. 123(R).
As of December 31, 2007, 2.6 million shares of common stock remained available for grant under the
2006 Equity Plan. Any issuance of a direct share benefit such as an outright grant of common stock, a grant of a
restricted share, or a RSU counts as two shares for each share issued against the amount eligible to be granted
under the 2006 Equity Plan. Each stock option and similar instrument granted counts as one share for each share
issued against the eligible shares authorized to be issued under the 2006 Equity Plan.
St. Mary anticipates granting Performance Share Plan (“PSP”) awards in lieu of RSUs beginning in 2008.
The performance shares are expected to be subject to vesting periods and pre-established performance criteria.
PSP awards will result in tradable shares of St. Mary common stock being issued immediately upon final vesting
at the end of the planned three-year performance measurement period. The Company expects that awards granted
under the PSP will be granted under the existing stockholder approved 2006 Equity Plan. The Company does
have outstanding stock option grants under the Predecessor Plans and RSU grants under the Predecessor Plans
and the 2006 Equity Plan. The following sections describe the details of RSU grants and stock options
outstanding as of December 31, 2007.
Restricted Stock Incentive Program Under the Equity Incentive Compensation Plan
The Company has a long-term incentive program whereby grants of restricted stock or RSUs have been
awarded to eligible employees, consultants, and members of the Board of Directors. Restrictions and vesting
periods for the awards are determined at the discretion of the Board of Directors and are set forth in the award
agreements. Each RSU represents a right for one share of the Company’s common stock to be delivered upon
settlement of the award at the end of a specified period. These grants are determined annually based on a formula
consistent with the cash bonus plan.
St. Mary issued 78,657 RSUs on February 28, 2007, related to 2006 performance, 484,351 RSUs on
February 28, 2006, related to 2005 performance and 195,312 RSUs on March 15, 2005 related to 2004
performance. The total fair value associated with these issuances was $2.5 million in 2007, $16.4 million in 2006,
and $4.5 million in 2005 as measured on the respective grant dates. The granted RSUs vest 25 percent
immediately upon grant and 25 percent on each of the next three anniversary dates of the grant. Compensation
expense is recorded monthly over the vesting period of the award. Vested shares of common stock underlying the
2005 RSU grant will be issued on the third anniversary of the grant, at which time the shares carry no further
restrictions. For all awards subsequent to the 2005 RSU grant, St. Mary has eliminated the restriction period that
extends beyond the vesting period so that shares will be issued without restriction upon vesting, rather than on the
third anniversary of the award. This change was effected within the safe harbor adoption provisions of the newly
enacted U.S. Treasury regulations interpreting IRC laws governing deferred compensation. The mutual election
of the employee and the Company were required to effect this change. Essentially all of the awards were
modified for this mutual election and as such the incremental value associated with removing this restriction
period will be amortized over the remaining service period for these awards. For grants made beginning with the
2006 grant period, the Company is using the accelerated amortization method as described in FASB Interpretation
No. 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans – an
interpretation of APB Opinions No. 15 and 25,” whereby approximately 48 percent of the total estimated
compensation expense is recognized in the first year of the vesting period. Expense for grants made for plan years
prior to 2006 is being amortized under the straight-line method since this method was allowed prior to the
adoption of SFAS No. 123(R). As of December 31, 2007, a total of 684,264 RSUs were outstanding, of which
394,879 were vested. Total compensation expense related to the RSUs recognized in the year ended
December 31, 2007, was $8.4 million. This amount includes $2.8 million of compensation expense related to the
2007 equity plan year for vesting of the estimated value of grants expected to be issued in 2008.
St. Mary also issued 23,977 RSUs and 13,500 RSUs for various grants to specific employees during 2007
and 2006, respectively. No special grants were issued during 2005. These grants have various vesting schedules.
The fair value of these awards will be recorded to compensation expense over the respective vesting periods using
the same basic framework as described above.
F-27
In 2007, 2006, and 2005, the Company issued 32,504, 29,827, and 13,926 shares, respectively, of
common stock from treasury to its non-employee directors pursuant to the Company’s non-employee director
stock compensation plan. The Company recorded compensation expense related to the issuances of shares to non-
employee directors of $983,500, $976,000 and $178,000 for the years ended December 31, 2007, 2006 and 2005,
respectively.
On June 30, 2007, the Company converted 427,059 RSUs, which were granted on June 30, 2004, into
common stock based on the original terms of the RSU award. The Company and the majority of the 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 original award agreements. As a result, the Company issued a net
302,370 shares of common stock associated with this grant. The remaining 124,689 shares were withheld to
satisfy income and payroll tax withholding obligations that occurred upon the delivery of the shares underlying
those RSUs.
In measuring compensation expense from the grant of RSUs, SFAS No. 123(R) requires companies to
estimate the fair value of the award on the grant date. The fair value of the RSUs is inherently less than the
market value of an unrestricted security. The fair value of RSUs has been measured using the Black-Scholes
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 grant. The fair values of granted RSUs
were estimated using the following weighted-average assumptions:
Risk free interest rate
Dividend yield
Volatility factor of the expected market
price of the Company's common stock
Expected life of the awards (in years)
For the Years Ended
December 31,
2007
4.5%
0.3%
32.0%
3
2006
2005
4.7%
0.3%
4.0%
0.4%
36.6%
3
26.7%
3
Upon the adoption of SFAS No. 123(R), the deferred compensation balance of $5.6 million related to
outstanding RSU awards was reclassified to additional paid-in-capital within the shareholders’ equity section of
the balance sheet. This deferred compensation balance had been recorded in accordance with APB Opinion
No. 25. The Company had recorded compensation expense in periods prior to January 1, 2006, for restricted
stock awards based on the intrinsic value on the date of grant. The intrinsic value was recorded as deferred
compensation in a separate component of shareholders’ equity and was amortized to compensation expense over
the vesting period. SFAS No. 123(R) requires expense recognized subsequent to the adoption date to be based on
fair value.
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.
Approximately $728,000 of compensation expense was recorded related to this award in 2006. In addition to this
award, the employee may 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. The
fair value of this award will be recorded as compensation expense over the vesting period. For the years ended
December 31, 2007 and 2006 the Company recorded compensation expense of $136,000 and $27,000
respectively, related to the contingent award.
F-28
A summary of the status and activity of non-vested stock awards and RSUs for the year ended
December 31, 2007, is presented below:
Non-vested, at December 31, 2006
Granted
Vested
Forfeited
Weighted-
Average
Grant-Date
Fair Value
28.92
32.45
25.94
31.77
Shares
506,161
102,634
(268,123)
$
$
$
(51,287) $
Non-vested, at December 31, 2007
289,385
$
32.26
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 St. Mary Land & Exploration Company Incentive Stock Option Plan. The last issuance of
stock options was December 31, 2004. Stock options to purchase shares of the Company’s common stock had
been issued to eligible employees and members of the Board of Directors. All options granted to date under the
option plans have been granted at exercise prices equal to the respective closing market price of the Company’s
underlying common stock on the grant dates, which generally occurred on the last date of a fiscal period. All
stock options granted under the option plans are exercisable for a period of up to ten years from the date of grant.
During the year ended December 31, 2007, the Company recognized stock-based compensation expense
of approximately $437,000 related to stock options that were outstanding and unvested as of January 1, 2006.
There was no cumulative effect adjustment from the adoption of SFAS No. 123(R).
Prior to adopting SFAS No. 123(R), all tax benefits resulting from the exercise of stock options were
presented as operating cash flows in the accompanying consolidated statements of cash flows. SFAS No. 123(R)
requires cash flows resulting from excess tax benefits to be classified as a part of cash flows from financing
activities. Excess tax benefits are realized tax benefits from tax deductions for exercised options in excess of the
deferred tax asset attributable to stock compensation costs for such options. The Company has recorded
$9.9 million and $16.1 million of excess tax benefits for the years ended December 31, 2007, and 2006,
respectively, as cash inflows from financing activities. Cash received from option exercises under all share-based
payment arrangements for the years ended December 31, 2007, 2006, and 2005, was $9.1 million, $16.9 million,
and $10.6 million, respectively.
F-29
A summary of activity associated with the Company’s Stock Option Plans during the last three years
follows:
For the period ended December 31, 2005
Outstanding, start of year
Granted
Exercised
Forfeited
Outstanding, end of year
Vested or expected to vest, end
of year
Exercisable, end of year
For the period ended December 31, 2006
Outstanding, start of year
Granted
Exercised
Forfeited
Outstanding, end of year
Vested or expected to vest, end
of year
Exercisable, end of year
For the period ended December 31, 2007
Outstanding, start of year
Granted
Exercised
Forfeited
Outstanding, end of year
Vested or expected to vest, end
of year
Exercisable, end of year
Weighted-
Average
Exercise Price
Aggregate
Intrinsic
Value
$12.06
-
11.31
13.24
$12.21
$12.21
$12.07
$12.21
-
11.35
14.33
$12.56
$12.56
$12.56
$12.56
-
12.38
7.34
$12.62
$12.62
$12.62
$ 115,595,735
$ 115,595,735
$ 101,972,732
$ 75,800,322
$ 75,800,322
$ 72,049,258
$ 62,007,749
$ 62,007,749
$ 61,814,737
Shares
5,651,350
-
(936,403)
(16,704)
4,698,243
4,698,243
4,121,424
4,698,243
-
(1,489,636)
(87,005)
3,121,602
3,121,602
2,966,944
3,121,602
-
(733,650)
(2,452)
2,385,500
2,385,500
2,378,000
F-30
A summary of additional information related to options outstanding as of December 31, 2007, follows:
Options Outstanding
Weighted-
Average
Remaining
Contractual
Number
Outstanding
Life
Options Exercisable
Weighted-
Average
Exercise
Price
Number
Exercisable
Weighted
Average
Remaining
Contractual
Life
Weighted-
Average
Exercise
Price
464,747
469,156
388,139
368,847
239,129
387,078
68,404
2,385,500
2.9 years
4.5 years
5.1 years
5.6 years
6.0 years
3.0 years
7.0 years
$
7.77
11.65
12.50
13.25
14.25
16.66
20.87
464,747
469,156
388,139
361,347
239,129
387,078
68,404
2,378,000
2.9 years $
4.5 years
5.1 years
5.6 years
6.0 years
3.0 years
7.0 years
7.77
11.65
12.50
13.25
14.25
16.66
20.87
Range of
Exercise Prices
$ 4.62
10.86
12.08
12.66
14.25
16.66
20.87
Total
- $ 10.60
12.03
-
12.53
-
13.65
-
14.25
-
16.66
-
20.87
-
The fair value of options was measured at the date of grant using the Black-Scholes option-pricing model.
Note 8 – Pension Benefits
The Company has a non-contributory pension plan covering substantially all employees who meet age
and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory
pension plan covering certain management employees (the “Nonqualified Pension Plan”).
On December 31, 2006, the Company adopted the recognition and disclosure provisions of Statements of
Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans – an Amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”).
This standard requires the Company to recognize the funded status (i.e., the difference between the fair value of
plan assets and the projected benefit obligation) of its pension plan in the consolidated balance sheets as either an
asset or a liability, with a corresponding adjustment to accumulated other comprehensive income, net of tax. The
adjustment to accumulated other comprehensive income at adoption represented the net unrecognized actuarial
losses and unrecognized prior service costs, both of which were previously netted against the plan’s funded status
in the Company’s consolidated balance sheets pursuant to the provisions of Statements of Financial Accounting
Standards No. 87, “Employers’ Accounting for Pensions” (“SFAS No. 87”). These amounts will be subsequently
recognized as net periodic pension cost pursuant to the Company’s accounting policy for amortizing such
amounts. Further actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic
pension cost in the same periods will be recognized as a component of other comprehensive income. Those
amounts will be subsequently recognized as a component of net periodic pension cost on the same basis as the
amounts recognized in accumulated other comprehensive income at adoption of SFAS No. 158.
F-31
The incremental effects of adopting the provisions of SFAS No. 158 on the Company’s statement of
financial position at December 31, 2006, are presented in the following table. The adoption of SFAS No. 158 had
no effect on the Company’s accompanying consolidated statements of operations for the year ended
December 31, 2006, or for any prior period presented, and it will not affect the Company’s operating results in
future periods. The effect of recognizing this additional liability is included in the table below in the column
labeled “Prior to Adopting SFAS No. 158.”
At December 31, 2006
Prior to
Adopting SFAS
No. 158
Effect of
Adopting
SFAS No.
158
(In thousands)
As Reported
Accrued pension liability
Deferred income taxes
Accumulated other comprehensive income
$
$
$
3,355
(932)
-
$
$
$
2,619
(990)
2,619
$
$
$
5,974
(1,922)
2,619
Actuarial gains and losses are comprised of experience changes and effects of changes in actuarial
assumptions. Experience changes are the effects of differences between previous actuarial assumptions and what
actually occurred. Included in accumulated other comprehensive income at December 31, 2007, are the following
amounts that have not yet been recognized in net periodic pension cost:
As of
December 31, 2007
(In thousands)
Unrecognized actuarial losses
Unrecognized prior service costs
Accumulated other comprehensive income
$
$
2,500
-
2,500
The estimated net loss for the Qualified Pension Plan and the Nonqualified Pension Plan (“the Pension
Plans”) that will be amortized from accumulated other comprehensive income into net periodic benefit cost over
the next fiscal year is $112,000.
F-32
Obligations and Funded Status for Both Pension Plans
2007
For the Years Ended December 31,
2006
(In thousands)
2005
Change in benefit obligations:
Projected benefit obligation at beginning of year
Service cost
Interest cost
Actuarial (gain) loss
Benefits paid
Projected benefit obligation at end of year
Change in plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contribution
Benefits paid
Fair value of plan assets at end of year
Funded status:
Accumulated Benefit Obligation
$
$
$
$
$
$
13,763
1,911
793
95
(1,818)
14,744
7,789
536
2,248
(1,818)
8,755
$
$
$
$
11,900
1,684
652
7
(480)
13,763
5,955
968
1,346
(480)
7,789
$
$
$
$
10,174
1,385
535
(4)
(190)
11,900
4,675
412
1,058
(190)
5,955
(5,989)
$
(5,974)
$
(5,945)
10,416
$
9,922
$
8,429
The combined underfunded status for the Pension Plans of $6.0 million at December 31, 2007, is
recognized in the accompanying statement of financial position as long-term accrued pension liability. No plan
assets of the Qualified Pension Plan are expected to be returned to the Company during the fiscal year ended
December 31, 2008. There are no plan assets in the Nonqualified Pension Plan.
Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets for Both Plans
As of December 31,
2007
2006
(In thousands)
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
$
$
$
14,744
10,416
8,755
$
$
$
13,763
9,922
7,789
F-33
Components of Net Periodic Benefit Cost for Both Pension Plans
2007
For the Years Ended December 31,
2006
(In thousands)
2005
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
$ 1,911
793
(540)
-
218
$ 2,382
$ 1,684
652
$ 1,385
535
(427)
-
296
$ 2,205
(354)
-
241
$ 1,807
Prior service costs are amortized on a straight-line basis over the average remaining service period of active
participants. Gains and losses in excess of ten percent of the greater of the benefit obligation and the market-related
value of assets are amortized over the average remaining service period of active participants.
Assumptions
Weighted-average assumptions to measure the Company’s projected benefit obligation and net periodic
benefit cost are as follows:
Projected benefit obligation
Discount rate
Rate of compensation increase
Net periodic benefit cost
Discount rate
Expected return on plan assets
Rate of compensation increase
Plan Assets
As of December 31,
2007
2006
6.1%
6.2%
5.9%
7.5%
6.2%
5.9%
6.2%
5.5%
7.5%
6.2%
The Company’s weighted-average asset allocation for the Qualified Pension Plan is as follows:
Asset Category
Equity securities
Debt securities
Other
Total
Target
2008
60.0%
40.0%
-
100.0%
As of December 31,
2007
57.5%
42.5%
2006
64.8%
35.2%
-
100.0%
-
100.0%
Equity securities do not include any shares of the Company’s common stock for any period presented.
There is no asset allocation for the Nonqualified Pension Plan since that plan does not have its own assets. An
expected return on plan assets of 7.5 percent was used to calculate the Company’s obligation under the Qualified
Pension Plan. Factors considered in determining the expected return include the 60 percent equity and 40 percent
debt securities mix of investment for plan assets and the long-term historical rate of return provided by the equity
and debt securities markets. The estimated rate of return on plan assets was 7.5 percent for 2007 and 2006. The
F-34
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 operation or on cash flows from
operating activities in future years.
Contributions
The Company contributed $2.2 million, $1.3 million, and $1.1 million, to the Pension Plans in the years
ended December 31, 2007, 2006, and 2005, respectively. St. Mary expects to contribute approximately $2.9 million
to the Pension Plans in 2008.
Benefit Payments
The Pension Plans made actual benefit payments of $1.8 million, $480,000, and $190,000 in the years ended
December 31, 2007, 2006, and 2005, respectively. Expected benefit payments over the next ten years follows:
Years Ended December 31,
2008
2009
2010
2011
2012
2013 through 2017
$
(in thousands)
1,612
479
734
1,254
1,529
$ 13,793
Note 9 – Asset Retirement Obligations
The Company recognizes an estimated liability for future costs associated with the abandonment of its oil
and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to
the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The
increase in carrying value is included in proved oil and gas properties in the accompanying 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 a 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 6.50 percent to 7.25 percent. Revisions to the liability could occur
due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new
requirements regarding the abandonment of wells.
F-35
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,
2007
2006
(In thousands)
77,242
10,851
(12,276)
5,458
27,009
108,284
$
$
66,078
7,555
(1,484)
4,926
167
77,242
Accounts payable and accrued expenses as of December 31, 2007, contain $3.1 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 Rita. Plugging and abandonment of
the platform is expected to be completed during the second quarter of 2008. Please refer to Note 12 – Insurance
Settlement for additional details. Accounts payable and accrued expenses did not contain any amount related to
the Company’s asset retirement obligation as of December 31, 2006.
Note 10 – Derivative Financial Instruments
Oil and Gas Commodity Hedges
To mitigate a portion of the potential exposure to adverse market changes, the Company has entered into
various derivative contracts. The Company’s derivative contracts in place include swap and collar arrangements
for the sale of oil, natural gas, and natural gas liquids. Please refer to the tables under Summary of Oil and Gas
Production Hedges in Place in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and
Results of Operations, for details regarding the Company’s hedged volumes and associated prices. As of
December 31, 2007, the Company has hedge contracts in place through 2011 for a total of approximately
11.4 million Bbls of anticipated crude oil production, 70.2 million MMBtu of anticipated natural gas production,
and 1.4 million Bbls of anticipated natural gas liquids production.
The Company attempts to qualify its oil and natural gas derivative instruments as cash flow hedges for
accounting purposes under SFAS No. 133 and related pronouncements. The Company formally documents all
relationships between the derivative instruments and the hedged production, as well as the Company’s risk
management objective and strategy for the particular derivative contracts. This process includes linking all
derivatives that are designated as cash flow hedges to the specific forecasted sale of oil or gas at its physical
location. The Company also formally assesses (both at the derivative’s inception and on an ongoing basis)
whether the derivatives being utilized have been highly effective at offsetting changes in the cash flows of hedged
production and whether those derivatives may be expected to remain highly effective in future periods. If it is
determined that a derivative has ceased to be highly effective as a hedge, the Company will discontinue hedge
accounting prospectively. If hedge accounting is discontinued and the derivative remains outstanding, the
Company will recognize all subsequent changes in its fair value on the Company’s consolidated statements of
operations for the period in which the change occurs. As of December 31, 2007, all oil and natural gas derivative
instruments qualified as cash flow hedges for accounting purposes. The Company anticipates that all forecasted
transactions will occur by the end of their originally specified periods. All contracts are entered into for other than
trading purposes.
The Company’s oil and gas hedges are measured at fair value and are included in the accompanying
consolidated balance sheets as assets or liabilities. The Company evaluates market prices in active markets to
establish the valuation of derivative instruments. The Company compares valuation estimates against mark-to-
market statements from counterparties for reasonableness. 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.
F-36
The oil and gas derivative markets are highly active. The fair value of oil and natural gas derivative contracts
designated and qualifying as cash flow hedges under SFAS No. 133 was a net liability of $264.1 million at
December 31, 2007.
The Company realized a net gain of $19.3 million, a net gain of $20.5 million, and a net loss of
$24.4 million from its oil and gas derivative contracts for the years ended December 31, 2007, 2006, and 2005,
respectively.
After-tax changes in the fair value of derivative instruments designated as cash flow hedges, to the extent
they are effective in offsetting cash flows attributable to the hedged risk, are recorded in other comprehensive
income until the hedged item is recognized in earnings upon the sale of the hedged production. As of
December 31, 2007, the amount of unrealized loss net of deferred income taxes to be reclassified from accumulated
other comprehensive income to oil and gas production operating revenues in the next twelve months was
$48.0 million.
Any change in fair value resulting from ineffectiveness is recognized currently in unrealized derivative
loss in the accompanying consolidated statements of operations. Unrealized derivative loss for the years ended
December 31, 2007, 2006, and 2005, includes net losses of $4.1 million, $8.1 million, and $1.8 million, respectively,
from ineffectiveness related to oil and natural gas derivative contracts.
Gains or losses from the settlement of oil and gas derivative contracts are reported in the total operating
revenues section of the accompanying consolidated statements of operations.
The Company seeks to minimize ineffectiveness by entering into oil derivative contracts indexed to
NYMEX and natural gas derivative contracts indexed to regional index prices associated with pipelines in
proximity to the Company’s areas of production. As the Company’s derivative contracts contain the same index
as the Company’s sale contracts, this results in hedges that are highly correlated with the underlying hedged item.
The following table summarizes derivative instrument realized gain (loss) activity:
Derivative contract settlements included in
realized oil and gas hedge gain (loss)
Ineffective portion of hedges qualifying for
hedge accounting included in
unrealized derivative loss
Non-qualified derivative contracts
2007
For the Years Ended December 31,
2006
(In thousands)
2005
$ 24,484
$ 28,176
$ (22,539)
(4,123)
(8,087)
(1,754)
included in unrealized derivative loss
(1,335)
Interest rate derivative contract settlements
226
993
(550)
139
(247)
Total realized gain (loss)
$ 19,252
$ 20,532
$ (24,401)
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 will pay a fixed rate of 4.90 percent and will
be paid a variable rate based on the one-month LIBOR rate. The interest rate derivative contract is measured at fair
value using quoted prices in active markets. The liability in the accompanying consolidated balance sheet at
December 31, 2007, was $447,000. The interest rate swap is a straightforward, non-complex, non-structured
instrument that is highly liquid This derivative qualifies for cash flow hedge treatment under SFAS No. 133 and
related pronouncements. The Company recorded a net derivative gain of $57,000 in the accompanying
F-37
consolidated statements of operations for the year ended December 31, 2007, related to this interest rate derivative
contract.
Convertible Note Derivative Instrument
In relation to the Company’s 5.75% Senior Convertible Notes converted in March 2007, the Company
entered into fixed-to-floating interest rate swaps on $50 million of principal in October 2003. Due to the
continued increases in interest rates, the Company entered into a floating-to-fixed interest rate swap in April 2005
through March 20, 2007, for this same notional amount of $50 million in order to effectively offset our fixed-to-
floating interest rate swaps. The impact of this instrument, when combined with the other interest rate swaps, was
that the Company fixed the net liability related to the interest rate swaps, and paid a 1.1 percent interest factor on
$50 million of notional debt through March 2007. The contingent interest provision of the 3.50% Senior
Convertible Notes is a derivative instrument. However, the value of the derivative was determined to be de
minimis at the inception of the instrument.
Note 11 – Repurchase of Common Stock
Stock Repurchase Program
In July 2006 the Company’s Board of Directors approved an increase of 5,473,182 shares to the
remaining authorized number of shares that can be repurchased under the Company’s original authorization
approved in August 1998, for a total number of shares to be repurchased under the plan of 6 million. As of the
date of this filing, the Company has Board authorization to repurchase up to 5,207,784 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 flow, and borrowings under the credit facility. During 2007 the Company repurchased 792,216 shares
of its outstanding common stock in the open market at a weighted-average price of $32.76 per share, including
commissions, for a total of $26.0 million. During 2006 the Company repurchased 3,319,300 shares of its
outstanding common stock in the open market at a weighted-average price of $37.09 per share, including
commissions, for a total of $123.1 million. During 2005 the Company repurchased 1,175,282 shares of its
outstanding common stock in the open market at a weighted-average price of $24.59 per share, including
commissions, for a total of $28.9 million. The Company did not retire any shares in 2007. The Company retired
3,275,689 shares in 2006 and 1,411,356 shares in 2005.
Note 12 – Insurance Settlement
In April of 2007 the Company reached a global insurance settlement for reimbursement of damages
sustained during Hurricane Rita. St. Mary’s net amount of the final settlement was approximately $33 million.
As a result of this settlement, the Company recorded a gain of $5.2 million in other revenue in the accompanying
statement of operations for the year ended December 31, 2007. The Company experienced significant weather-
related delays in its plug and abandonment efforts during 2007 and consequently accrued an additional
$2.1 million of plug and abandonment costs for one offshore platform during the fourth quarter of 2007. The gain
calculation takes into consideration a total of approximately $12.1 million of costs associated with the plugging
and abandonment of the above-mentioned offshore platform. Any significant variation between actual and
estimated plugging and abandonment and outside-operated damage repair costs will impact the final
determination of the gain associated with the insurance settlement. The Company expects adjustments to the gain
to be completed by the second quarter of 2008.
F-38
Note 13 – Disclosures about Oil and Gas Producing 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. The 2007, 2006, and 2005 amounts include $27.6 million,
$7.8 million, and $22.8 million, respectively, of capitalized costs associated with asset retirement obligations.
2007
For the Years Ended December 31,
2006
(In thousands)
2005
Development costs
Exploration
Acquisitions:
Proved
Unproved
Leasing activity
Total
Suspended Well Costs
$ 591,013
111,470
$ 367,546
126,220
$ 249,518
69,817
161,665
23,495
38,436
$ 926,079
238,400
44,472
28,816
$ 805,454
84,981
2,853
14,330
$ 421,499
The following table reflects the net changes in capitalized exploratory well costs during 2007, 2006, and
2005. The table does not include amounts that were capitalized and either subsequently expensed or reclassified
to producing well costs in the same period.
2007
For the Years Ended December 31,
2006
(In thousands)
2005
Beginning balance at January 1,
Capitalized exploratory well costs charged to expense
upon adoption of FSP FAS 19-1
Additions to capitalized exploratory well costs pending
$ 22,799
$ 7,994
$
189
-
-
-
the determination of proved reserves
29,551
17,693
7,994
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,
(9,237)
(183)
$ 42,930
(2,888)
-
$ 22,799
(189)
-
$ 7,994
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
F-39
2007
For the Years Ended December 31,
2006
(In thousands)
$ 17,958
4,841
$ 22,799
$ 7,994
-
$ 7,994
2005
$ 29,368
13,562
$ 42,930
3
1
-
The exploratory well costs capitalized for more than one year includes $4.8 million for a well that was
drilled in 2005 and 2006 and is located offshore in the Gulf of Mexico. A Reserve Analysis and Reservoir
Simulation Study has been completed for this well. Construction of a long lead-time infrastructure began in 2007
and is expected to be completed during the fourth quarter of 2008. Production from this well is expected to
commence in 2009. The operational plan is to build the connection and process facilities in support of the already
recognized costs. The Company believes these costs are realizable.
The exploratory well costs capitalized for more than one year also includes $5.7 million and $3.1 million
of costs related to two additional wells located offshore in the Gulf of Mexico that were drilled in 2006. Reserve
Analysis and Reservoir Simulation Studies have been completed for these wells to support the ongoing project
economics. The wells were both waiting on the construction of production facilities, which were completed in
late 2007. Production from both of these wells is expected to commence during the first quarter of 2008. Based
on the operational plan and project economics for these wells, the Company believes these costs are realizable.
Oil and Gas Reserve Quantities (Unaudited)
For all years presented, Netherland, Sewell and Associates, Inc. (“NSAI”) prepared the reserve information
for the Company’s coalbed methane projects at Hanging Woman Basin in the northern Powder River Basin as well
as the Company’s non-operated coalbed methane interests in the Green River Basin. The Company engaged Ryder
Scott Company, L.P. to review internal engineering estimates for 80 percent of the PV-10 value of its proven
conventional oil and gas reserves in 2007 and 2006. In 2005, Ryder Scott Company, L.P. prepared the reserve
estimates for at least 80 percent of the PV-10 value of the Company's conventional oil and gas assets. St. Mary
personnel prepared the reserve estimates for the remainder of all properties. The Company emphasizes that reserve
estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more
imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected
to change as future information becomes available.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that
geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those
expected to be recovered through existing wells with existing equipment and operating methods. All of the
Company’s proved reserves are located in the continental United States and offshore in the Gulf of Mexico.
F-40
Presented below is a summary of the changes in estimated reserves of the Company:
2007
Oil or
Condensate
(MBbl)
For the Years Ended December 31,
2006
Oil or
2005
Oil or
Gas
(MMcf)
Condensate
(MBbl)
Gas
(MMcf)
Condensate
(MBbl)
Gas
(MMcf)
74,195
5,238
1,166
482,475
9,489
28,483
62,903
524
857
417,075
10,946
36,723
56,574
1,593
2,553
319,196
24,354
21,998
Developed and undeveloped:
Beginning of year
Revisions of previous estimate
Discoveries and extensions
Infill reserves in an existing
proved field
4,592
69,090
4,131
49,107
3,286
83,093
Purchases of minerals in
place
Sales of reserves
Production
End of year (a) (b)
Proved developed reserves:
Beginning of year
End of year
567
(4)
(6,907)
78,847
91,374
(1,400)
(66,061)
613,450
11,857
(20)
(6,057)
74,195
28,030
(2,958)
(56,448)
482,475
4,831
(7)
(5,927)
62,903
20,823
(588)
(51,801)
417,075
61,519
68,277
358,477
426,627
55,971
61,519
313,125
358,477
47,992
55,971
272,295
313,125
(a) At December 31, 2007, 2006, and 2005 amounts include approximately 316, 523, and 435 MMcf, respectively,
representing the Company's net underproduced gas balancing position.
(b) Subsequent to the year ended December 31, 2007, the Company divested of certain non-core properties, which
included 40.4 BCFE of reserves that were owned by the Company as of December 31, 2007.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities”
(“SFAS No. 69”) prescribes guidelines for computing a standardized measure of future net cash flows and changes
therein relating to estimated proved reserves. The Company follows these guidelines, which are briefly discussed
below.
Future cash inflows and future production and development costs are determined by applying benchmark
prices and costs, including transportation, quality, and basis differentials, in effect at year end to the year-end
estimated quantities of oil and gas to be produced in the future. Each property the Company operates is also charged
with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using
current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting
future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor.
Future operating costs are determined based on estimates of expenditures to be incurred in developing and
producing the proved oil and gas reserves in place at the end of the period using year-end costs and assuming
continuation of existing economic conditions, plus Company overhead incurred by the central administrative office
attributable to operating activities.
F-41
The assumptions used to compute the standardized measure are those prescribed by the FASB and the
Securities and Exchange Commission. These assumptions do not necessarily reflect the Company's expectations 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:
2007
2006
2005
Gas (per Mcf)
Oil (per Bbl)
$ 7.56
$ 88.71
$ 5.54
$ 53.65
$ 8.34
$ 55.63
The following summary sets forth the Company's future net cash flows relating to proved oil and gas
reserves based on the standardized measure prescribed in SFAS No. 69:
Future cash inflows
Future production costs
Future development costs
Future income taxes
Future net cash flows
10 percent annual discount
2007
$ 11,629,679
(3,672,857)
(611,288)
(2,316,637)
5,028,897
(2,321,983)
As of December 31,
2006
(In thousands)
$ 6,653,455
(2,283,452)
(429,303)
(1,125,955)
2,814,745
(1,238,308)
2005
$ 6,979,279
(2,146,590)
(385,379)
(1,448,444)
2,998,866
(1,286,568)
Standardized measure of discounted
future net cash flows
$ 2,706,914
$ 1,576,437
$ 1,712,298
F-42
The principle sources of change in the standardized measure of discounted future net cash flows are:
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
2007
For the Years Ended December 31,
2006
(In thousands)
$ 1,712,298
$ 1,576,436
2005
$ 1,033,938
(693,885)
1,320,994
(554,147)
(661,074)
(590,671)
725,154
462,952
265,285
123,630
280,822
263,762
67,864
422,481
132,185
55,324
(32,566)
166,428
215,745
(1,915)
(573,259)
(122,931)
$ 2,706,914
114,007
34,940
249,417
(8,991)
200,858
(123,319)
$ 1,576,437
(42,710)
117,763
150,112
(1,000)
(314,685)
24,407
$ 1,712,298
F-43
Note 14 – Quarterly Financial Information (Unaudited)
The Company’s quarterly financial information for fiscal 2007 and 2006 is as follows (in thousands, except
per share amounts):
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Year Ended December 31, 2007
Total operating revenues
Total operating expenses (1)
Income from operations
Income before income taxes
Net income
Basic net income per common share
Diluted net income per common share
Dividends declared per common share
Year Ended December 31, 2006
Total operating revenues
Total operating expenses
Income from operations
$ 221,006
151,494
$ 69,512
$ 63,562
$ 39,950
0.70
$
0.63
$
0.05
$
$ 247,154
149,171
$ 97,983
$ 94,387
$ 59,235
0.93
$
0.91
$
-
$
$ 246,687
151,336
$ 95,351
$ 91,624
$ 57,653
0.91
$
0.89
$
0.05
$
$ 193,588
112,902
$ 80,686
$ 193,381
128,296
$ 65,085
$ 198,040
110,818
$ 87,222
Income before income taxes
Net income
$ 80,131
$ 50,526
$ 64,076
$ 40,080
$ 85,142
$ 55,877
Basic net income per common share
Diluted net income per common share
Dividends declared per common share
$
$
$
0.88
0.76
0.05
$
$
$
0.70
0.61
-
$
$
$
1.01
0.88
0.05
$ 275,247
218,682
56,565
$
$
$
$
$
$
50,689
32,874
0.52
0.51
-
$ 202,692
133,419
69,273
$
$
$
$
$
$
65,972
43,532
0.78
0.69
-
(1) General and administrative and exploration expense are components of total operating expenses. As a result of a
change in circumstances in 2007, the Company began classifying all payments made under the Net Profits Plan to
exploration overhead only for those individuals who are currently employed by St. Mary and who continue to be
involved in the Company’s exploration efforts. Therefore, the quarterly financial information presented in the following
table reflects a reconciliation from what was previously reported in the quarterly reports on Form 10-Q, to the
reclassified balances, which reflect current distributions being made and accrued for under the Net Profits Plan for
former employees as being fully allocated to general and administrative expense since there is no longer any functional
link to geologic and geophysical or exploration related work by those former employees. The reclassification was
determined in the fourth quarter, therefore, no reclassification was necessary as the amounts reported for the fourth
quarter were accounted for consistent with the current presentation. The change had no impact on total operating
expenses, income from operations, income before income taxes, net income, basic net income per share, or diluted net
income per share as it was simply a reclassification between two line items within the accompanying consolidated
statements of operations as shown below.
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(In thousands)
General and administrative:
As previously reported
Net Profits Plan Adjustment
Adjusted general and administrative
Exploration:
As previously reported
Net Profits Plan Adjustment
Adjusted exploration
$ 11,141
1,750
$ 12,891
$ 20,769
(1,749)
$ 19,020
$
$
$
$
13,697
2,569
16,266
13,643
(2,569)
11,074
$
$
$
$
13,110
2,695
15,805
15,257
(2,695)
12,562
$
$
$
$
15,187
-
15,187
16,030
-
16,030
F-44
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: March 4, 2008
ST. MARY LAND & EXPLORATION COMPANY
(Registrant)
By:
/s/ ANTHONY J. BEST
Anthony J. Best
President, Chief Executive Officer,
and Director
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,
March 4, 2008
and Director
*
David W. Honeyfield
Senior Vice President-Chief Financial
Officer and Secretary
March 4, 2008
*
Mark T. Solomon
*
Mark A. Hellerstein
Controller
March 4, 2008
Chairman of the Board of Directors
March 4, 2008
Signature
*
Barbara M. Baumann
*
Larry W. Bickle
*
William J. Gardiner
*
Julio M. Quintana
*
John M. Seidl
*
William D. Sullivan
Title
Director
Date
March 4, 2008
Director
March 4, 2008
Director
March 4, 2008
Director
March 4, 2008
Director
March 4, 2008
Director
March 4, 2008
* By: /s/ ANTHONY J. BEST
Anthony J. Best
(as attorney-in-fact for each of the persons indicated)
March 4, 2008
STOCKHOLDER INFORMATION
I N V E S T O R S E R V I C E S
You can reach our corporate office at:
St. Mary Land & Exploration Company
1776 Lincoln Street, Suite 700
Denver, CO 80203
303-861-8140
Fax: 303-861-0934
We also have offices in Tulsa, Oklahoma; Shreveport, Louisiana;
Billings, Montana; Houston, Texas; and Midland, Texas
St. Mary Land & Exploration Company
7060 South Yale, Suite 800
Tulsa, OK 74136-5741
918-488-7600
St. Mary Land & Exploration Company
330 Marshall Street, Suite 1200
Shreveport, LA 71101
318-424-0804
St. Mary Land & Exploration Company
550 N. 31st Street, Suite 500
Billings, MT 59101
406-245-6248
St. Mary Land & Exploration Company
777 N. Eldridge Pkwy., Suite 1000
Houston, TX 77079
281-677-2800
St. Mary Land & Exploration Company
3300 N. A Street, Bldg. 7, Suite 200
Midland, TX 79705
432-688-1700
DESIGN BY: MARK MULVANY GRAPHIC DESIGN (DENVER, COLORADO)
PHOTOGRAPHY BY: RON COPPOCK-KING (DENVER, COLORADO)
I N V E S T O R R E L AT I O N S C O N TA C T
Stockholders, securities analysts, or portfolio managers who have
questions or need information concerning St. Mary may contact
Brent Collins, Director of Investor Relations at 303-861-8140.
E-mail: bcollins@stmaryland.com
Annual Reports, 10Ks, 10Qs
To receive an information packet on St. Mary or to be added to
our mailing list, contact Pam Sweet at 303-861-8140.
E-mail:
information@stmaryland.com
Please visit our web site at: www.stmaryland.com
Stock Transfer Agent
Any stockholder with questions or inquiries regarding stock certificate
holdings, changes in registration address, lost certificates, dividend
payments, and other stockholder account matters should be directed
to St. Mary Land & Exploration Company’s transfer agent at the
following address or phone number:
Computershare Trust Company NA
350 Indiana Street, Suite 800
Golden, CO 80401
303-262-0600
NYSE: SM
The Company’s common stock is listed for trading on the New York
Stock Exchange under the symbol SM.
The price ranges of the Company’s common stock by quarter for
the last two years are provided below. As of February 15, 2008 the
Company had 63,020,524 shares of common stock outstanding, net
of 1,009,712 treasury shares owned by the Company.
Market Prices
2007— Quarter Ended
2006— Quarter Ended
March 31
June 30
September 30
December 31
high
low
high
low
$38.20
$33.55
$44.69
$34.70
40.19
37.15
44.50
34.91
31.20
35.40
45.59
43.92
40.85
34.38
34.77
33.43
OTHER INFORMATION
In 2007, St. Mary submitted to the New York Stock Exchange a
certificate of the Chief Executive Officer of St. Mary certifying that he
was not aware of any violation by St. Mary of the New York Stock
Exchange corporate governance listing standards. St. Mary has filed
with the SEC certifications of the Chief Executive Officer and the Chief
Financial Officer required under Section 302 of the Sarbanes-Oxley
Act as exhibits to the Annual Report on Form 10-K/A for the year
ended December 31, 2007.
St. Mary Land & Exploration Company • www.stmaryland.com