SM Energy Company Annual Report 2004

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FY2004 Annual Report · SM Energy Company

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Growing Through Competitive Advantages

A N N U A L R E P O R T 2 0 0 4

FINANCIAL HIGHLIGHTS

In thousands except production, price data, and per share

Income Statement Data

Oil and gas production revenues

Gains on sales and other

Total operating revenues

Net income

2004

2003

2002

2001

2000

$ 413,318

19,781

$ 433,099

$ 92,479

$ 365,114

28,594

$ 393,708

$ 95,575

$ 185,670

10,635

$ 196,305

$ 27,560

$ 203,973

$ 188,407

3,496

$ 207,469

$ 40,459

7,259

$ 195,666

$ 55,620

Diluted earnings per share

$ 2.88

$ 2.80

$ 0.97

$ 1.42

1.97

Cash dividends declared and paid per share

$ 0.10

0.10

Diluted weighted average common

shares outstanding

33,447

35,534

28,391

28,555

28,271

Balance Sheet Data

Working capital

Total assets

Long-term debt

Stockholders’ equity

Average Net Daily Production

Gas (Mcf)

Oil (Bbls)

MCFE (6:1)

Average Sales Price

Gas (per Mcf)

Oil (per Bbl)

Reserves

Gas (Mcf)

Oil (Bbls)

MCFE (6:1)

$ 12,035

3,101

2,050

$ 34,000

$ 40,639

945,460

136,791

484,455

127,316

13,113

205,992

735,854

110,696

390,653

136,062

12,441

210,709

537,139

113,601

299,513

104,558

7,713

150,836

436,989

64,000

286,117

108,195

6,667

148,199

321,895

22,000

250,136

104,769

6,551

144,075

$ 5.52

$ 32.53

$ 4.89

$ 26.96

$ 3.00

$ 25.34

$ 3.73

$ 23.29

3.44

23.53

319,196

56,574

658,638

307,024

47,787

593,744

274,172

36,119

490,887

241,231

23,669

383,247

225,975

20,950

351,673

Shareholders’ Equity ($ millions)

Proved Oil & Gas Reserves (BCFE)

Oil & Gas Production Per Day (MMCFE)

500

400

300

200

100

750

600

450

300

150

250

200

150

100

05
(projected)

Oil & Gas Production Per Share (MCFE)

Operating Cash Flow (000’s)

Capital Expenditures ($ Millions)

3.0

2.5

2.0

1.5

1.0

0.5

250

200

150

100

500

400

300

200

100

05
(budget)

Company at a Glance

OUR MISSION

St. Mary Land & Exploration Company was founded in 1908 and

incorporated in 1915. We are engaged in the exploration, exploitation,

development, acquisition, and production of natural gas and crude oil

in five core areas in the United States.

Our mission is to build value by adding value at every phase of the

business, from prospect generation to reservoir engineering to drilling

to production to marketing to finance and to administration. Our goal is

to provide a long-term return to our stockholders in the top-quartile of

our peers while preserving underlying capital. We plan to achieve this

by attracting, motivating, and retaining a talented staff; the intelligent

use of new technologies; and a focus on growing net asset value per

share. While growing our company, we will not compromise our core

values of integrity, fairness, trust, and social responsibility.

OPERATIONS

We operate in five core areas managed from four regional offices.

The Mid-Continent, Rocky Mountain, ArkLaTex, Gulf Coast, and

Permian Basin regions are operated out of our offices in Tulsa,

Oklahoma; Billings, Montana; Shreveport, Louisiana; and Houston,

Texas. Each office is staffed with a full complement of geologists/

geophysicists, engineers, and landmen who have extensive experi-

ence in the region/basin where they work. Our Denver headquarters

provides the administrative support and oversight for the regions.

We will operate approximately 71% of our $293 million

exploration and development capital expenditures budget in 2005.

By operating such a large amount of our budget, we are able to

maximize the benefit of our expertise in the land, geoscience, and

engineering disciplines. In each core area, we focus on cautious

detailed land and legal work, disciplined geologic interpretations,

reservoir management, efficient completion and stimulation

techniques, and the appropriate application of new technologies

when warranted.

ACQUISITIONS

BILLINGS

Greater Green
River Basin

Williston Basin

Hanging Woman Basin

Powder River Basin

Wind River
Basin

DENVER

Anadarko Basin

TULSA

Permian Basin

Arkoma Basin

ArkLaTex

SHREVEPORT

HOUSTON

Gulf Coast

The acquisition of oil and gas assets and companies is an important part of our growth strategy. We focus our attention on acquisitions in

existing core areas where we can utilize our geologic knowledge of the area, our technical engineering expertise, and our financial flexibility.

Property Acquisitions ($ millions)

At the same time, we are actively seeking larger acquisitions that would allow us to expand our existing

125

100

core areas, acquire additional geoscientists, and/or gain significant interests in a new basin within

the United States.

In 2004, we spent $76.7 million on acquisitions, which represented 24% of our capital expenditures

program. In 2005, we are budgeting $125 million for acquisitions, which is 30% of our budget. Over the last

05
(budget)

five years, we have completed $336.5 million of property acquisitions.

FINANCIAL STRATEG IES

Through consistent economic growth in reserves and production, St. Mary’s objective is to increase per share value in excess of 15% per year.

To achieve the objective, our goal is to replace, on average, 200% of our annual production and to have full cycle economics in the top quartile

of our peer group. Over the past five years, we have replaced, on average, 228% of our production with excellent economics. From December

1992, when we first became a public company, through December 31, 2004, we have provided our stockholders, in dividends and stock value,

Proved Oil & Gas Reserves Per Share
(MCFE)

a compounded rate of return of 18%.

Our strategy is also to maintain a strong balance sheet by keeping our debt to capital ratio below 35%.

A strong balance sheet allows us to weather cycles of low commodity prices and be opportunistic when

capital is not available to our peers. We are willing to become aggressive and increase our debt to capital ratio

during down cycles in order to make strategic acquisitions. At December 31, 2004, we have a debt

to capital ratio of 22%.

Creating Competitive Advantages

Our continued growth is dependent upon establishing

competitive advantages. We must continually ask

ourselves why assets are worth more to us than they are

to our competitors. When we can answer that question,

new economic opportunities will come our way.

Competitive advantages provide the answer to the

question and the edge we need to create value.

Growing through competitive advantages is a work

in progress that will never be completed. It is similar

to a puzzle. Each puzzle piece represents a competitive

COMP ETIT IVE ADVANTAGE S
Corporate

Strong Balance Sheet

We keep our debt to capital ratio at 35% or
less. A strong balance sheet allows us to
be opportunistic and maintain consistent
exploration and development programs
from year to year.

advantage. When our competitive edge becomes

Financial Discipline

dominant in a region or play, our economic opportunities

will grow rapidly. But each play is discreet and the

competition intense. Therefore, we must continually

establish new competitive strengths, which will be the

springboard for new growth.

We believe we must add value at every phase of

our business. Our annual report discusses some of the

competitive advantages that we have identified

throughout our company. Our job is to capitalize on

these strengths to grow value and to create additional

competitive advantages as we grow.

All capital expenditures must meet minimum
internal rate of return objectives. Corporate
acquisitions must be accretive to our net
asset value. Monthly, quarterly and annually
we continually compare our results to our
expectations in order to assure that our
performance criteria are being met.

To Our Shareholders

The year 2004 was highlighted by high oil and gas prices and record earnings per share; return
on capital employed of 23%; a very competitive acquisition market; growing rig count and
escalating costs; reasonable drilling results; a modest drop in production after increasing 40%
the prior year; and commencement of development and first production at the Hanging Woman
Basin coalbed methane project. We completed $76.7 million of acquisitions in 2004 and grew
our reserve base by 11% and our pre-tax PV10 value of proved reserves by 17% to $1.5 billion.
We repurchased 3.9 million shares of St. Mary stock at an average price of $27.73 per share,
while we saw our stock price increase 46% for the year to $41.74 per share at December 31,
2004. Reserves per share grew 23% to 23.1 MCFE per outstanding share.

Highlights in 2004 include excellent drilling results in the horizontal middle Bakken play in
the Williston Basin where we participated in the drilling and completion of 15 wells with 100%
success. New grassroots completed dual lateral wells drilled in Richland County, Montana cost
approximately $2.7 million, with initial production rates of 350 to 600 Bbls of oil per day and
proved reserves of approximately 350 to 500 MBbl, which results in outstanding economics.
At year-end we had 45 proved undeveloped and probable locations identified in Montana and
North Dakota. We have begun to test the play in North Dakota via re-entry of existing well bores
with single lateral completions which cost approximately 40% of a grassroots dual lateral well.
The middle Bakken dolomite thins as it moves southeast into North Dakota. Our initial results
in North Dakota have been encouraging with unstimulated flow rates of 150 to 300 BOE per
day. We have approximately 80,000 net acres in the middle Bakken fairway.

We had several outstanding individual well completions in 2004. The Paggi Broussard #1
(40% working interest) is currently producing 31.2 MMCFE per day and the Vermillion 273 B3
(50% working interest), which initially produced approximately 15 MMCFE per day, is currently
producing 11 MMCFE per day. The M C Delambre #1 at Judge Digby had an initial rate from
the C-1 pay interval with 15 feet of pay (7.84% working interest) of 15.4 MMCFE per day with
140 feet of pay yet to be completed in the B zones (11.5% working interest). We also have had
continued success in our Red River play in the Williston Basin as well as tight horizontal plays
in the ArkLaTex region, including Huxley, Spider, Driscoll and Walkers Chapel fields, and growing
activity in the Greater Green River Basin.

We began development of our Hanging Woman Basin coalbed methane project by completing

57 wells in 2004. The pipeline and compression facilities
were completed in December 2004 when we began selling
our first gas. Netherland, Sewell and Associates, Inc.
completed a comprehensive geologic and engineering study
of this project, with an estimate of reserves as follows:

HANGING WOMAN BASIN RESERVES
8,159 MMCF
Proved
69,661 MMCF
Probable
644,687 MMCF
Possible
722,507 MMCF
Total

Probable and possible reserves have inherently more risk than proved reserves due to the

fact that such well locations are either not direct offsets to existing wells or represent coal
seams that have not yet produced in commercial quantities. In addition, permitting and timing
of development activities cannot always be accurately estimated. Numerous shallow and
intermediate depth coals have been successfully developed in the northern Powder River
Basin. The deeper coals are estimated to contain significant gas reserves, but they have not yet
been successfully developed in other projects. These deeper coals represent approximately
51% of the total proved, probable and possible reserves.

Net income for the year 2004 was $92.5 million or $2.88 per share compared to $95.6 million
or $2.80 per share for the prior year. Net cash provided by operating activities increased 16% to
$237.2 million. Production decreased 2% to 75.4 BCFE. The average realized price increased 15%
to $5.48 per MCFE. Unit costs increased modestly for the year as lease operating expense (includ-
ing taxes) increased $0.12 to $1.27 per MCFE, DD&A (including impairments) increased $0.15
to $1.22 per MCFE and general and administrative expense increased $0.01 to $0.29 per MCFE.
Proved oil and gas reserves grew by 11% to 659 BCFE. We replaced 190% of our 2004
production at an all-inclusive finding cost of $2.19 per MCFE. We continue to report a very
low PUD percentage of 15% at year-end, despite maintaining a large 1.1 million net acre land
position, of which 69% or 742,000 net acres are undeveloped.

To grow net asset value per share, we set a goal to economically replace 200% of our annual
production. We have successfully achieved this goal over time, providing our shareholders an
18% compounded return since going public in 1992.

MARK A. HELLERSTEIN

CHAIRMAN, PRESIDENT & CEO

Innovative Deal Structures:

We are creative in structuring acquisitions to
meet the financial and tax requirements of
the seller and also meet our internal rate of
return objectives. We have been successful
structuring “win-win” arrangements that
have added value for our shareholders.

We enter 2005 on a positive note:
• We are in excellent financial condition.

Incentive Programs That
Match Performance

• Oil and gas prices are high and the long-term outlook is positive.

• We have an outstanding inventory of prospects to be drilled with multi-year plays in the

Bakken and Red River formations in the Williston Basin, Northeast Mayfield in the Anadarko
Basin and the Hanging Woman Basin.

• We have increased our total capital expenditures budget to $418 million.

Here is our plan to build value in 2005:
• Production is currently forecast to grow to 81-85 BCFE, up from 75 BCFE in 2004. Based

on NYMEX strip prices of $46.73 per Bbl and $6.26 per Mcf, we would realize approximately
$6.56 per MCFE, after hedges. Lease operating expenses, including taxes, are currently
forecast at $1.37– $1.47 per MCFE, G&A is forecast at $0.30 – $0.35 per MCFE and DD&A
is forecast at $1.35– $1.45 per MCFE.

• Of the $418 million budget, 30% is allocated for acquisitions, 23% for exploration and

development in the Rocky Mountain region, 21% in the Mid-Continent region, 10% in the
Gulf Coast region, 8% in the ArkLaTex region, 6% for our Hanging Woman Basin coalbed
methane play and other coalbed methane projects and 2% in the Permian Basin region. We
completed the acquisition of Agate Petroleum, Inc. in early 2005 recording approximately
$42 million to oil and gas properties. The drilling portion of our budget is up $56 million
representing a 24% increase over 2004. The Rocky Mountain region’s budget is up $30 million
resulting from our success in the horizontal middle Bakken play and acceleration of activity
in the Red River as well as the Greater Green River Basin plays. The Hanging Woman Basin
coalbed methane budget more than doubled to $24.5 million. The ArkLaTex region’s budget is
up $6 million due to drilling at the Elm Grove field where we acquired an interest through the
Border Company acquisition in 2004. The Gulf Coast region’s budget is up $5 million as our
Houston office expands our activity to not only include South Louisiana, but South and
Southeast Texas and the outer continental shelf, including intermediate deep water. Approximately
80% of the Gulf Coast region’s budget will be for low to moderate risk exploration based
either on direct hydrocarbon indicators or attic locations. The Mid-Continent region’s budget
is down $10 million as Northeast Mayfield and our Granite Wash plays are high graded. We
are seeing rig and other service costs increase and are experiencing rig shortages in certain
areas. Therefore, our plan for 2005 will need to be flexible to a changing environment.

Our annual report theme this year is “Growing through Competitive Advantage”. Our ability
to grow St. Mary profitably is dependent on our ability to answer the question, “Why are assets
worth more in our hands than in someone else’s?” We believe the answer to this question
begins at the core of St. Mary: its value systems; its risk / reward profile; its incentive programs
that help us attract, motivate and retain top talent; and its reporting and feedback systems
which help us understand our business better. At the regional level, the answer may lie in better
application of 3-D seismic and geologic knowledge; a large and strategic acreage position; the
ability to apply new technologies and judgment to drill and stimulate wells more effectively and
at lower cost; the ability to market our oil and gas at a premium over others; our ability to
operate at a lower cost; or obtain financing at a lower cost. It also takes a combination of talent,
creativity, focus, attention to detail and proper application of technology. In each of our regions
we strive to establish clear competitive advantages. Once we have a substantial competitive
edge, we believe opportunities will follow. Our business is quite competitive and the discreet
nature of our asset base suggests that advantages do not last forever. Therefore, we are facing an
ongoing struggle for that competitive edge. The battle never ends. We are proud of what we have
accomplished. In this annual report, we will illustrate some of our key competitive advantages
that have helped us become the 9th Best Small Pubic Company in America in 2004 according
to Forbes’ magazine.

March 11, 2005

Mark A. Hellerstein
Chairman, President and Chief Executive Officer

Incentive compensation under our cash
bonus and restricted stock plans is based
on the growth of St. Mary’s net asset
value. Minimum growth objectives must
be met before this performance-based
compensation is earned.

Our net profit pool incentive plan is
designed to reward selected employees with
a portion of cash flow from a pool once
St. Mary has recovered 100% of its costs. It
is a unique program that creates the proper
tension between growth and economics.
Because all participants are in the same pool,
there is pressure for capital to flow to the most
attractive investments. Because participants
have a vested interest in the performance of
the producing wells, they will not only focus
on performance during the drilling phase,
but throughout the life of the well.

We Don’t Destroy Value

Oil and gas exploration is a risk business
and dry holes are inevitable. We manage
our risk by focusing on low to moderate risk
drilling, with a small portion of our budget
available for higher risk / higher reward
projects. By combining superior people with
many years of experience in their region,
attention to detail, focus and performance
feedback, we have learned not to make big
mistakes. Major successes can only have a
big impact when other activities have not
destroyed value.

Operations Overview

We made significant progress this year building an inventory of multi-year exploration and

development programs. An objective in each of our regions is to develop and use competitive

advantages to identify opportunities that will create multi-year programs.

Our participation in the horizontal middle Bakken play in the Williston Basin expanded into

such a program in 2004. From three wells completed in 2003 to 15 completed wells in 2004 and

plans for 30 wells in 2005, we continue to define the potential of the play and the technology

that will allow us to extract maximum value from the play. We have not drilled a dry hole and

have identified 45 proved undeveloped and probable drilling locations at year-end 2004. We

have additional drilling locations identified in the possible category in our approximate 80,000

net acres of leases in the area we have defined as the middle Bakken fairway.

We began development of our Hanging Woman Basin coalbed methane play in 2004 with

57 wells completed at year-end. The natural gas pipeline that connects the project area with

the sales line was completed in mid-December 2004. Although the completed wells are in the

dewatering phase, we did have gas production prior to year-end, which is encouraging. We plan

to drill 150 wells in 2005 and have approximately 2,000 potential locations on the 154,000 net

acres we have leased in the play.

Northeast Mayfield in the Anadarko Basin continues to be an active drilling program.

Results in 2004 failed to meet our expectations as we stepped out and drilled a number of

wells in order to define the limits of the play. We completed 24 of the 28 wells drilled in 2004

and have identified 60 proved undeveloped and probable drilling locations at year-end 2004.

We plan to drill 27 wells in Northeast Mayfield in 2005.

Despite a very competitive acquisition market in 2004, we closed $76.7 million of property

acquisitions that added 52.3 BCFE of proved and 22.6 BCFE of probable reserves. In addition,

in January 2005 we closed on the acquisition of Agate Petroleum, Inc. with approximately

$42 million allocated to oil and gas properties that adds 23.1 BCFE of proved and 5.8 BCFE of

probable reserves in the Williston and Arkoma Basins.

Net proved reserves at December 31, 2004 increased 11% to 658.6 BCFE, of which 85%

are classified as proved developed. Our reserve base at year-end 2004 was 52% oil and 48%

natural gas. During 2004, we participated in drilling 204 conventional wells with a 90% success

rate. We also participated in drilling 83 coalbed methane wells during 2004.

We are budgeting $418 million for capital expenditures in 2005. This amount represents a

34% increase over the $313 million spent in 2004. Exploration and development expenditures

are projected to be $293 million and $125 million is budgeted for property acquisitions.

We will operate approximately 71% of our capital expenditures budget in 2005. With our

strong balance sheet, we are not limited by our $125 million budget in looking for acquisition

opportunities. We will be actively sourcing and evaluating opportunities during 2005 for

acquisitions that meet our economic parameters.

We begin 2005 with the largest inventory of drilling prospects in the history of our Company

including several multi-year plays. We have a large land inventory with 1,072,000 net acres,

69% of which are undeveloped. We continue to add experienced geoscientists, engineers, land

professionals, and support personnel in each of our regional offices. With a local presence in

each region, we are aware of new plays and new ideas and are able to react quickly to activity

in each of our core areas.

Following is additional information about the operations in each of our core areas and

more detail of our plans for 2005.

DOUGLAS W. YORK

EXECUTIVE VICE PRESIDENT AND

CHIEF OPERATING OFFICER

Capital Expenditures Budget By Region

21%

10%

30%

23%

n Mid-Continent n ArkLaTex n Gulf
n Rocky Mountain n Coal Bed Methane
n Permian n Acquisitions

Reserve Base By Region

21%

54%

12%

ROCKY MOUNTAIN REGI ON

PROV ED RESERVES

% OF TOTAL RESERVES

GAS/OIL MIX

PROV ED DEVELOP ED R ESE R VES

TOTAL NET LEA SED ACR ES

NET UNDEVELOPED LEA SED AC RE S

CAP ITA L EXPENDI TUR ES BUD GE T: N O N C B M

C OA LB ED ME TH AN E PR OJECT S

COMP ETIT IVE ADVANTAGE S
Rocky Mountain Region

3-D Seismic

36 5. 4 BCF E

55%

23 % / 7 7%

86%

83 9, 000

80%

$ 94. 7 MIL LION

$2 5 .8 MILLIO N

Nance Petroleum Corporation, a wholly owned subsidiary, manages our operations in the

Rocky Mountain region, which include our coalbed methane projects. Our Nance office in

Billings, Montana currently has a 75-person staff. Nance has managed our interests in the

Williston Basin since 1991, initially under a partnership arrangement and since June 1, 1999

as a wholly owned subsidiary. Since 1999, the Nance office has also managed our interests

in other Rocky Mountain Basins.

Our Rocky Mountain region includes the Williston Basin in eastern Montana and western

North Dakota, the Powder River Basin in Montana and Wyoming, and the Greater Green River,

Wind River and Big Horn Basins in Wyoming. Our Hanging Woman Basin coalbed methane

project initiated in 2001 is in the northern portion of the Powder River Basin.

The Rocky Mountain region experienced significant growth in 2004. The horizontal middle

Bakken play in the Williston Basin has provided much of the growth. Our participation in the play

has grown from completing three wells in 2003 to completing 15 wells in 2004 and budgeting

30 wells in 2005. The play that began in Richland County, Montana has crossed the state

boundary into North Dakota where we have recently re-entered four existing well bores with

encouraging results. During 2004 we conducted extensive geologic studies to define the middle

Bakken fairway. Within the identified fairway, we have approximately 80,000 net acres (25,000

in Montana and 55,000 in North Dakota). At year-end 2004 we had two drilling rigs and two

re-entry rigs drilling in the play and plan to add a third drilling rig during 2005.

We continue to be active drilling wells to the Red River formation in the Williston Basin.

Our 86% success rate since 1991 drilling wells in the Williston Basin is largely attributable to

our ability to identify and match structure and porosity development using 3-D seismic. In

In the Williston Basin we are able to map
porosity development in the Red River
formation using 3-D seismic imaging. Our
technical ability has resulted in a 86% drilling
success rate and has allowed us to be a
consolidator of properties in the Williston.

Large Acreage Position

Opportunities come to those owning oil
and gas leases in the right place at the right
time. Because of our large acreage position
in the Williston Basin, we are a major partic-
ipant in the horizontal middle Bakken play
that currently is one of the more active plays
in the Rockies.

2004 we completed four 3-D seismic surveys and have budgeted seven such surveys in 2005.

We plan to drill nine Red River wells in 2005.

Our activity in the Greater Green River, Wind River and Powder River Basins continues to

grow. In 2005 we plan to participate in eight operated and 27 non-operated wells in the

Wamsutter area of the Greater Green River Basin. The acquisition of Goldmark Engineering, Inc.

in November 2004 included the Fourbear field in Park County, Wyoming. An active development

program of the field will begin in 2005 with the drilling of three infill wells and the workover

of numerous wells.

In 2004, the Rocky Mountain region (excluding the coalbed methane programs) drilled and

participated in 51 wells, of which 48, or 94%, were successful. The region spent $98.3 million,

including $34.0 million for acquisitions, which represents 32% of our total capital expenditures

in 2004. The 31.1 BCFE produced from the region was 41% of our total company production.

Coalbed Methane Projects

Development of our Hanging Woman Basin acreage in the northern portion of the Powder

River Basin, along the Montana-Wyoming border, began in 2004. We completed 57 wells in the

Anderson, Canyon and Cook coal seams. The wells are currently dewatering the coal seams

and natural gas is being delivered to sales. We are completing wells using multiple coal seam

completion techniques, which should greatly improve the economics of the play. A pipeline has

been built into the project area connecting the program to several natural gas markets. Natural

gas from the project area can be transported north into either the Northern Border system or

the Williston Basin Interstate system. Natural gas can also be transported south to Glenrock,

Wyoming where it can be sold into various Mid-Continent markets.

Our 2005 capital expenditures budget for the Hanging Woman Basin project is $24.5 million.

The budget includes drilling and completing 150 wells along with additional lease acquisition

costs. The project has the potential to include as many as 2,000 wells on our 154,000-acre

net lease position.

We are also participating as a non-operator in Atlantic Rim coalbed methane projects in

the Greater Green River Basin. We have budgeted $1.4 million for these projects in 2004 to

participate in the drilling of 33 wells.

M I D D L E B A K K E N P L AY

Technology Leader in
Horizontal Middle Bakken Play

C U R R E N T A C R E A G E P O S I T I O N

MONTANA

GROSS

76,000

NET

48,000

NORTH DAKOTA

203,000

133,000

TOTAL

279,000

181,000

BAKKEN TREND

107,000

80,000

R IC H LA ND CO UN TY

M O N T A N A

B A K KEN FA IR WAY ACTIVI TY

PRODUCING WELL

P UD LOC ATION

P ROB LO CATION

N O R T H D A K O T A

McK EN ZIE CO UN TY

BI LL ING S CO UNT Y

The horizontal Middle Bakken play is the most active play in the Williston
Basin, and one of the more active plays in the U.S. It is located in Richland
County, Montana and Billings and McKenzie Counties, North Dakota.
Although we did not initiate this play, our tremendous HBP (“Held by
Production”) acreage position allowed us to monitor the efforts of several private
companies who applied new horizontal drilling and fracturing technologies to
the middle Bakken. Once they were successfully completing horizontal wells in
the middle Bakken, we were able to capitalize on our acreage position, which
we believe to be the largest position held by a public company in the play.

Our tremendous Rocky Mountain acreage position represents a key
strategic advantage for the Company and did not happen by accident. It began
with our proprietary ability to map both structure and porosity in the Red
River formation allowing us to realize an 86% success rate since 1991. Our
success allowed us to be competitive acquiring assets from companies that
were exiting the Basin, at least partially, because they had not been able to
achieve repeatable success exploring in the Red River. Since 2001 we have
made the following acquisitions:

Choctaw II Oil & Gas, Ltd.

Burlington Resources Oil & Gas Company L.P.

Flying J Oil & Gas, Inc. and Big West Oil & Gas, Inc.

Agate Petroleum, Inc.

2001

2002

2003

2005

These acquisitions came with developed and undeveloped oil and gas
leases throughout the Williston Basin (and other basins in the Rockies),
including leases in Richland County, Montana and Billings and McKenzie
Counties, North Dakota.

Although initial drilling in the middle Bakken began in 2001, the play
became active in 2003. With wells producing at initial rates of 300 to 600 barrels
of oil per day and reserves per well estimated from 350,000 barrels to 500,000
barrels of oil, leases became very expensive and made it difficult for new
companies to enter the play. We have accumulated 181,000 net acres of leases
in the three counties where the middle Bakken is currently being explored and
developed. Within our interpretation of the middle Bakken fairway, we have
80,000 net leased acres.

From drilling dual laterals to open hole
fracs, we are applying technology to the
play. With each new well we are refining our
techniques to enhance well productivity.

Higher Oil Price Realization

We bid out our oil production frequently.
Because we are a major producer in the
Williston Basin we are able to attract
competing offers. Indexing the price of our
oil to NYMEX and conducting the bidding
process at selected times each year have
resulted in higher oil price realizations than
are received by our competitors in the Basin.

CO MPETITIVE ADVANTAGES
Hanging Woman Basin

Large Acreage Position

H A N G I N G W O M A N B A S I N

Fidelity CX Field

Fidelity CX Field
Expansion

.
I
.
B
W

SHERIDAN

J.M. Huber
& Pennaco
Prarie Dog

.
I
.

Proposed
J.M. Huber
& Pennaco

Nance 2004
Development Area

Nance 2005
Development Area

Pinnacle

M O N T A N A

W Y O M I N G

6 "

G R A S S L A N D S 1

–

W . B . I .

Continental/Wolverine

C M S 20"

Pennaco Gibbs

BITTER CREEK 16"

12"

16"

R I M R O C K

J.M. Huber &
CH4 LX Bar

T
H
U
N
D
E
R
C
R
E
E
K

Over the years we have consistently allocated 10% to 15% of our capital
expenditures budget for higher risk, higher potential exploration ideas, non-
conventional exploration and opportunistic acquisitions. In 2000, we used
these funds to option approximately 70,000 acres of leases over coalbed
methane reserves in the Hanging Woman Basin, located in the northern
portion of the Powder River Basin. We believed the area had the potential to
become a legacy asset of the company.

After initial studies, in 2001 we exercised our option to lease and obtained
additional leases that increased our holdings in the area. We hired and developed
the technical expertise to evaluate the project and conducted two pilot well
programs during 2002. After extensive study and modeling of the project
using the results of our pilot projects and two existing coalbed methane programs
operating west of our project area, we made the decision in 2003 to proceed
with development. In 2004 we completed 57 wells and have budgeted to
complete 150 wells in 2005, out of the potential 2,000 well locations on our
154,000 net acre lease position.

We now have a major project that will be developed over many years. Once
the wells have been dewatered, which is estimated to take nine to 18 months per
well, the program is expected to provide a base of production for many years.
The program continues to have the potential to be a legacy asset of the company.
In our Hanging Woman Basin program, we have developed competitive
advantages. Our large, mostly contiguous lease position allows us to develop the
properties in an efficient, orderly manner. Because of the contiguous lease posi-
tion, we are able to space wells on 160 acres rather than 80 acres, which improves
economics and minimizes the environmental impact. Our technical expertise
has developed multi-seam completion techniques that will reduce the number
of wells necessary to develop the properties and will improve economics.

We have added shareholder value by acquiring a large lease position over
coalbed reserves, building the technical expertise to evaluate the properties
and building the team to operate a multi-well, multi-year development program.

Our large, mostly contiguous lease position
allows for the efficient development of our
coalbed reserves on 160 acre spacing rather
than 80 acre spacing. Wells are spaced to
maximize our economic return rather than
to protect our position from being drained
by others. Project facilities are scaled for
maximum efficiency.

Technical Expertise in
Coalbed Natural Gas

From geology to land to engineering to
operations, we have assembled a superior
technical team. Developing the technology
to complete multiple coal seams in the same
well bore significantly improves economics
and minimizes environmental impact.

Legacy Asset

With approximately 2,000 well locations,
we plan to develop the Hanging Woman
Basin program over many years. The
program is expected to provide a place to
economically deploy capital and create a
growing production base.

MID-CONTINENT REGION

PROV ED RESERVES

% OF TOTAL RESERVES

GAS/OIL MIX

PROV ED DEVELOP ED R ESE R VES

TOTAL NET LEA SED ACR ES

NET UNDEVELOPED LEA SED AC RE S

CAP ITA L EXPENDI TUR ES BUD GE T

COMP ETIT IVE ADVANTAGE S
Mid-Continent Region

Land Expertise

13 5. 7 BCF E

21%

95 % / 5 %

88%

93 ,0 00

29%

$87 .0 MILL IO N

Our Mid-Continent region primarily includes our operations in the Anadarko and Arkoma

Basins in Oklahoma and Texas. The region, where we have been operating since 1973, is

managed out of our Tulsa, Oklahoma office by our 42-person staff.

The Mid-Continent region continues to be our most active drilling core area. In 2004

the region drilled and participated in 108 wells, of which 98 were successful for a 91%

success rate. The region spent $104.0 million, which represents 33% of our total capital

expenditures in 2004.

As in 2003, our most active drilling area in the Mid-Continent region in 2004 was in western

Oklahoma in our Northeast Mayfield prospect area. Due to increased industry activity and

expiring leases in the field, drilling in 2004 was more exploratory than in prior years as we

stepped out to the south and to the west to test the limits of the play. Results were not as

productive as they were in 2003 when we primarily drilled development locations. We completed

24 of the 28 wells drilled in the field in 2004. We are planning to drill 27 wells in 2005, which

will include a higher percentage of development wells than we drilled in 2004. We will be

drilling several exploratory wells in 2005 as we continue to evaluate our leases in the field.

We have operated in the Mid-Continent
region for over 30 years. Our land profes-
sionals have many years of experience in
the region negotiating lease agreements,
working with other interest owners and
solving lease issues.

With 18 identified Morrow sands, five identified Atoka pay intervals and Granite Wash potential

Drilling Expertise

on the 68 sections where we have interests in the play, we will continue developing this field

over a multi-year period. At the end of 2004, we have identified 60 proved undeveloped and

probable locations and have additional reserves classified as possible in the field. We are planning

to spend $36 million, or 41% of our Mid-Continent capital expenditures budget, to drill and

complete wells in Northeast Mayfield in 2005.

We have increased our presence in the Oklahoma portion of the Arkoma Basin where we

have allocated $22 million or 25% of our 2005 Mid-Continent capital expenditures budget. We

plan to drill 13 wells in the Centrahoma field where we are targeting the Cromwell, Wapanucka,

Woodford and Oil Creek formations. We continue to evaluate our Arkoma acreage through

geological mapping and 3-D seismic. In 2005 we will be conducting a 20-square-mile 3-D

seismic survey in the area to develop additional prospects in the McLish, Oil Creek, Viola,

Cromwell and Wapanucka zones.

The balance of our $87.0 million Mid-Continent 2005 capital expenditures budget is being

allocated to prospects throughout the region. We are planning to drill six Granite Wash wells

and ten Cottage Grove and Osborne wells in various fields in the Anadarko Basin. We will also

be drilling ten horizontal coalbed methane wells in the Arkoma Basin on leases that are part of

the January 2005 acquisition of Agate Petroleum, Inc.

In 2005 we plan to operate three to five drilling rigs throughout the year in the Mid-Continent

region and operate 80% of our capital expenditures budget.

We have many years of experience directing
drilling operations in the Mid-Continent.
Being the low cost operator drilling 20,000
foot wells in Northeast Mayfield is a testament
to our expertise.

Large Acreage Position

A large lease inventory in Oklahoma provides
exploration and development opportunities.
Our leasehold position cannot easily be
duplicated. Lease owners in Oklahoma are
able to force a well to be drilled, even
though the lease owner may own a minority
lease position in the drill site (forced pooling).

Geologic Expertise

Our geologic managers have spent their
entire careers in the Mid-Continent region.
Their knowledge of the various plays, the
performance of various formations and the
opportunities that remain are vital to our
continued growth of the region.

ARKLATE X REGION

PROV ED RESERVES

% OF TOTAL RESERVES

GAS/OIL MIX

PROV ED DEVELOP ED R ESE R VES

TOTAL NET LEA SED ACR ES

NET UNDEVELOPED LEA SED AC RE S

NET MINERAL S ERV ITUD E ACR ES

CAP ITA L EXPENDI TUR ES BUD GE T

COMP ETIT IVE ADVANTAGE S
ArkLaTex Region

Horizontal Drilling Expertise

75 .6 BCF E

12%

89 % / 1 1%

83%

43 ,0 00

29%

9,5 14

$34 .6 MILL IO N

Our ArkLaTex region includes properties in east Texas, northern Louisiana, southern Arkansas,

and southern Mississippi. Our 18-person office in Shreveport, Louisiana, manages the region

where we have operated since 1992. The ArkLaTex region has grown through a combination of

niche acquisitions, new field discoveries, and field extensions.

The ArkLaTex region had excellent drilling results in 2004. The region drilled and

participated in 32 wells, of which 29 were successful, for a 91% success rate. The region

spent $28.8 million for exploration and development and $38.2 million for proved property

acquisitions in 2004. The $67.0 million of capital expenditures represented 21% of our total

capital expenditures in 2004.

We had continued success in 2004 drilling horizontal wells in the James Lime formation.

Our success in 2003 drilling in the Huxley field in east Texas was followed up in 2004 by

drilling seven successful horizontal James Lime wells in our Spider, Bridges East and Huxley

fields. In 2004 we also began drilling horizontal wells in the Pettet formation, which, like the

James Lime formation, is a fractured limestone. We completed three Pettet wells in our

Driscoll and Walker’s Chapel prospects in 2004. We are planning to drill 12 horizontal James

Lime and Pettet wells in 2005, which represents 30% of the $34.6 million capital expenditures

budget for the ArkLaTex region. The wells are expected to provide good economics as

the average completed well cost is approximately $1.3 million, and per well reserves are

estimated at 1.2 BCFE.

In December 2004 we closed on a $38.2 million acquisition of oil and gas properties located

primarily in the Elm Grove field in northern Louisiana. Included in the acquisition was a

substantial inventory of drillable prospects in the Cotton Valley formation. We have included

$8.4 million in our 2005 capital expenditures budget to participate in 42 Cotton Valley wells in

the Elm Grove field this year.

The balance of our $34.6 million ArkLaTex 2005 capital expenditures budget is being

allocated to a mix of exploratory and development projects that include wells in our Box

Church, Trinidad Southeast and Garrison fields in east Texas. We plan to operate 46% of our

ArkLaTex capital expenditures budget in 2005.

Our success drilling horizontal James Lime
and Pettet wells over the past two years has
created new horizontal well opportunities.
Our expertise in geo-steering and well
design of laterals has transformed formerly
sub-economic reservoirs into low risk
economic wells.

Frac Technology

We have been able to enhance production
using recent developments in frac technology.
Water and hybrid fracs have enhanced vertical
production in tight gas sands. Improving the
economics of sub-economic reservoirs has
added to our inventory of drillable prospects.

Geologic Expertise

Our geologic managers have spent their
entire careers exploring in east Texas and
northern Louisiana. Their knowledge of the
various plays, the performance of various
formations and the opportunities that
remain are vital to our continued growth
of the region.

C OMP ETITIVE ADVANTAGES
Gulf Coast Region

Direct Hydrocarbon Indicator
(DHI) Expertise

GULF COAST AND PERMIAN BASIN REGIONS

In February 2004, we closed our office in Lafayette, Louisiana, and moved the management

of our Gulf Coast region to our newly opened office in Houston, Texas. At the same time,

management of our Permian Basin assets was moved from our office in Billings, Montana, to

Houston. Under new leadership and an experienced technical team, our 18-person office in

Houston has revitalized our Gulf Coast Region.

The ability of our geophysical staff to identify
DHI improves our prospect inventory and
reduces our risk. DHI is a valuable tool used
to evaluate opportunities in south Texas,
south Louisiana and offshore.

Fee Property

Gulf Coast Region

P RO V ED R ESE RVES

% O F TO TA L RES ERVE S

G AS /O I L MIX

P RO V ED D EVE LOPED R ESERVE S

TO TA L N ET L EASED ACR ES

N ET U ND E VELO PED LEASE D ACRE S

FE E A CR ES

C AP ITA L E XPEN DITU RES BU DG ET

3 3.5 BCF E

5 %

93% / 7%

9 3%

4 2,000

1 4%

24,914

$ 40.8 MILLION

Our Gulf Coast region includes properties in the Gulf of Mexico and onshore in south

Louisiana and south Texas. Our presence in south Louisiana dates back to the early 1900s

when our founders acquired a franchise property in St. Mary Parish on the shoreline of the

Gulf of Mexico. We have been receiving oil and gas royalty income from these 24,914 acres of

fee lands since 1938. The fee lands represent a smaller portion of our company’s production

each year but still yielded $5.5 million of oil and gas royalty revenue to St. Mary in 2004. The

onshore Gulf Coast and Gulf of Mexico became a core area in 1999 with the acquisition of

King Ranch Energy.

The region is focused on development and exploitation opportunities. Exploration is directed

toward low and moderate risk opportunities with a direct hydrocarbon indicator (DHI) or areas

where we have niche expertise. We anticipate drilling several exploration wells using DHI in

2005 that are the result of participation in a nearly 900 square mile 3-D seismic survey along

the Gulf Coast of Texas and Louisiana. Approximately 25% of our $40.8 million Gulf Coast

budget has been allocated to these opportunities.

We plan to participate in approximately three DHI exploration wells in the shelf of the Gulf

Cumulative production from our 24,914
acres of fee lands on the shoreline of the
Gulf of Mexico exceeds 200 million barrels
of oil and 3.5 TCF of gas. A 3-D seismic
survey was conducted over the entire
property in 2003.

Excellent Leadership

of Mexico in 2005. In addition, we plan to participate for the first time in an intermediate

deepwater well. Approximately 43% of our Gulf Coast budget has been allocated to these

offshore opportunities.

We continue to participate in the successful development of the Judge Digby field, located

in Point Coupe Parish outside Baton Rouge, Louisiana. Although the field is nearing the end of

new drilling, we participated in the M C Delambre #1 well in 2004 that had an initial production

rate of 15 MMCFD from the C-1 pay interval and logged 140 feet of sand in B zones that are

currently behind pipe. We plan to participate in the drilling of one well and the recompletion of

several wells in Judge Digby in 2005. As producing zones deplete, the wells are recompleted

to the next uphole pay interval. Because of the multiple potential pay zones in each of the wells,

we anticipate recompletion activity to continue in the Judge Digby field for many more years.

As the result of a 3-D seismic survey conducted over our 24,914-acre fee property in

2003, we issued leases on 2,845 acres in 2004. The lease terms allowed us to retain a 25%

mineral owner’s royalty and the right to participate for up to a 25% working interest in any well

drilled on the lease. This election is on a spacing unit basis. We anticipate wells being drilled

on the leased acres in 2005. Past 2-D seismic surveys conducted over these properties have

indicated deep structures that could be productive in the Marge A and Rob Chambersi sections.

Since cumulative production from our fee property now exceeds 200 million Bbls of oil and 3.5

TCF of gas, newly defined 3-D structures could have significant potential to St. Mary, as we will

have the opportunity to participate in new exploration in a very meaningful way.

We have assembled a talented team of
professionals that are well connected within
the oil and gas industry. The manager of our
Gulf Coast region has many years of experi-
ence successfully managing exploration and
operations of other Gulf Coast operators.

Permian Basin Region

PROVE D RESERVES

% OF TOTAL RESERVES

GAS/OIL MIX

PROVE D DEVELOPED RE SE RVE S

TOTAL NET LEAS ED A CRE S

NE T UNDEV ELOP ED L EASED ACRE S

CAPI TAL EXPENDITUR ES BU D G E T

COMP ETIT IVE ADVANTAGE S
Permian Region

Waterflood Expertise

48 .5 BCF E

14 % / 8 6%

63%

15 ,0 00

56%

$10 .0 MILL IO N

Our Permian Basin region includes our properties in eastern New Mexico and western Texas.

Our operations in the region range from exploration to exploitation to secondary recovery projects.

Our activity in 2004 was primarily directed toward continued development of our waterflood

projects at Parkway and East Shugart in Lea and Eddy Counties, New Mexico. Production at

the Parkway Delaware Unit waterflood, which we initiated in 1999 when production was 350

Bbls per day, was enhanced by two infill wells drilled in 2004. Production in 2004 averaged

1,700 Bbls per day, up 46% from 2003. Production at the East Shugart Delaware Unit

waterflood, which is an analog to the Parkway Delaware Unit, increased 5% in 2004 as the

formation continues to respond to water injection. The Permian Basin region’s $10.0 million

2005 capital expenditures budget is being allocated primarily to 11 infill locations at Parkway

and eight injection wells at East Shugart.

We have been able to design and implement
two successful waterflood operations of the
Delaware formation in the Permian Basin.
This expertise will assist us in identifying
additional waterflood opportunities.

In every region,
we create value for our
shareholders by
answering the question:

Why are assets worth more
in our hands?

DIRECTORS

OFFICERS

INFORMATION ABOUT RESERVES

Barbara M. Baumann (1),(3),(4)
Denver, Colorado
President
Cross Creek Energy Corporation

Larry W. Bickle (2),(4)
Houston, Texas
Managing Director
Haddington Ventures, L.L.C.

Ronald D. Boone
Denver, Colorado
Former Executive Vice President and
Chief Operating Officer
St. Mary Land & Exploration Company

Thomas E. Congdon (1)
Denver, Colorado
Former Chairman
St. Mary Land & Exploration Company

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

Mark A. Hellerstein (1)
Denver, Colorado
Chairman, President and
Chief Executive Officer
St. Mary Land & Exploration Company

John M. Seidl (2),(3)
Aspen, Colorado

William D. Sullivan (2),(4)
The Woodlands, Texas
Former Executive Vice President
Anadarko Petroleum Corporation

(1) Executive Committee

(2) Nominating and Corporate

Governance Committee

(3) Audit Committee

(4) Compensation Committee

Mark A. Hellerstein
Chairman, President and
Chief Executive Officer

Douglas W. York
Executive Vice President and
Chief Operating Officer

Robert L. Nance
Senior Vice President

Jerry R. Schuyler
Senior Vice President –
General Manager, Gulf Coast

Kevin E. Willson
Senior Vice President –
Mid-Continent, Drilling and Production

Robert T. Hanley
Vice President – Investor Relations
and Management Reporting

W. David Hart
Vice President – Geology, ArkLaTex

David W. Honeyfield
Vice President – Finance, Treasurer
and Secretary

Milam Randolph Pharo
Vice President – Land and Legal,
Assistant Secretary

Julian C. Pope
Vice President – Mid-Continent,
Land and Administration,
Assistant Secretary

Paul M. Veatch
Vice President – General Manager,
ArkLaTex

Garry A. Wilkening
Vice President – Administration
and Controller

Linda A. Ditsworth
Assistant Vice President –
Land and Assistant Secretary

Michael F. Roach
Assistant Vice President –
External Reporting

Mark T. Solomon
Assistant Vice President –
Financial Reporting

David J. Whitcomb
Assistant Vice President –
Gas Marketing

The SEC permits oil and gas companies to
disclose in their public filings with the SEC only
proved reserves, which are reserve estimates
that geological and engineering data demonstrate
with reasonable certainty to be recoverable in
future years from known reservoirs under existing
economic and operating conditions. St. Mary uses
in portions of this annual report which are not
publicly filed with the SEC the terms “probable”
and “possible” reserves, which SEC guidelines
prohibit from being included in public filings with
the SEC. Probable reserves are unproved reserves
which analysis of geological and engineering data
suggests are more likely than not to be recoverable.
Possible reserves are unproved reserves which
are less likely to be recoverable than probable
reserves. Estimates of probable and possible
reserves which may potentially be recoverable
through additional drilling or recovery techniques
are by their nature more uncertain than estimates
of proved reserves and accordingly are subject
to substantially greater risk of not actually being
realized by the Company. In addition, our produc-
tion forecasts and expectations for future periods
are dependent upon many assumptions, including
estimates of production decline rates from existing
wells and the undertaking and outcome of
future drilling activity, which may be affected by
significant commodity price declines or drilling
cost increases.

INFORMATION ABOUT FORWARD
LOOKING STATEMENTS

This annual report contains forward looking
statements within the meaning of securities laws,
including forecasts and projections for future
periods. The words “will,” “believe,” “anticipate,”
“intend,” “estimate,” “forecast,” “plan” and “expect”
and similar expressions are intended to identify
forward looking statements. These statements
involve known and unknown risks, which may
cause St. Mary’s actual results to differ materially
from results expressed or implied by the forward
looking statements. These risks include such factors
as discussed in the “Risk Factors” and “Cautionary
Statement about Forward Looking Statements”
sections of the accompanying 2004 Annual Report
on Form 10-K. Although St. Mary may from time to
time voluntarily update its prior forward looking
statements, it disclaims any commitment to do so
except as required by securities laws.

SHAREHOLDER INFORMATION

INV ES T OR SERVICES

You can reach our corporate office at:
St. Mary Land & Exploration Company
1776 Lincoln Street, Suite 700
Denver, CO 80203
303-861-8140

We also have offices in Tulsa, Oklahoma; Billings, Montana;
Shreveport, Louisiana; and, Houston, 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

Nance Petroleum Corporation
550 N. 31st Street, Suite 500
Billings, MT 59101
406-245-6248

St. Mary Land & Exploration Company
580 Westlake Park Blvd., Suite 600
Houston, TX 77079
281-677-2800

DESIGN BY: MARK MULVANY GRAPHIC DESIGN (DENVER, COLORADO)

PHOTOGRAPHY BY: RON COPPOCK-KING (DENVER, COLORADO)

INVESTOR RELATIONS CONTACT

Stockholders, securities analysts or portfolio managers who
have questions or need information concerning St. Mary may
contact Bob Hanley, Vice President–Investor Relations and
Management Reporting, at 303-863-4377.
E-mail: bhanley@stmaryland.com

Annual Reports, 10Ks, 10Qs
To receive an information packet on St. Mary, or to be added to
our mailing list, contact: Jim Robertson at 303-863-4322
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 Investor Services
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, 2005 the
Company had 28,798,362 shares of common stock outstanding.

Market Prices

2004— Quarter Ended

2003— Quarter Ended

March 31

June 30

September 30

December 31

high

low

high

low

$34.14

$27.74

$27.23

$23.80

37.19

40.13

43.00

31.80

31.76

37.12

29.75

28.85

29.19

24.65

24.45

OTHER INFORMATION
In 2004, 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 each of the Chief
Executive Officer and the Vice President-Finance required under
Section 302 of the Sarbanes-Oxley Act as exhibits to the Annual
Report on Form 10-K for the year ended December 31, 2004.

St. Mary Land & Exploration Company

1776 Lincoln Street

Suite 700

Denver, Colorado 80203

Telephone: (303) 861-8140

Fax: (303) 861-0934

Internet: www.stmaryland.com