SM Energy Company Annual Report 2003

FY2003 Annual Report · SM Energy Company

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Annual Report 2003

St. Mary Land & Exploration Company has been one of the top performing E & P companies since going public in 1992.

The extraordinary returns we have provided our stockholders since our Company’s inception in 1908 have been based on a

foundation of core values. For 95 years, St. Mary has embodied a culture of integrity, passion, knowledge, fairness, trust,

and social responsibility. Our consistent growth and returns over a long period of time are due to our proven ability to

repeat success. Operating in five core areas with superior technical teams provides the opportunities necessary to create

and develop projects that will grow St. Mary to the next level. Over the years, each core area has developed a major

project that has provided growth and the repeatability that increases stockholder value year after year.

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.

BILLINGS

DENVER

TULSA

HOUSTON

SHREVEPORT

Proved Property Acquisitions ($ millions)

100

04
(budget)

Reserves Per Share (MCFE)

Operations

St. Mary operates 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/geophysisists, engineers, and landmen who have extensive experience
in the region/basin where they work. Our Denver headquarters provides the
administrative support and oversight for the regions.

St. Mary will operate approximately 75% of its $173 million exploration and
development capital expenditures budget in 2004. 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

The acquisition of oil and gas assets and companies is an important part of our
growth strategy. We focus our attention on smaller niche acquisitions in existing
core areas where we can utilize our geologic knowledge of the area, our technical
engineering expertise, and our financial flexibility. At the same time, we are actively
seeking larger acquisitions that would allow us to expand our existing core areas,
acquire additional geoscientists, and/or gain significant interests in a new basin
within the United States.

In 2003, we spent $77.4 million on niche acquisitions of proved reserves,

which represented 33% of our capital expenditures program. In 2004, we are
budgeting $100 million for acquisitions, which is 37% of our budget. Over the last
five years, we have completed $292.9 million of proved property acquisitions.

Financial Strategies

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 economically 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, 274% of our production
with excellent economics. From December 1992, when we first became a public
company, through December 31, 2003, we have provided our stockholders, in
dividends and stock value, a compounded rate of return of 16%.

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.

FINANCIAL HIGHLIGHTS

In thousands except production, price data, and per share, as adjusted for 2 for 1 split on 9/5/00

2003

2002

2001

2000

1999

Income Statement Data

Oil and gas production revenues

Gains on sales and other

Total operating revenues

Net income

$ 365,114

28,820

$ 393,934

$ 95,575

$ 185,670

10,724

$ 196,394

$ 27,560

$ 203,973

3,496

$ 207,469

$ 40,459

$ 188,407

7,259

$ 195,666

$ 55,620

Diluted earnings per share

$ 2.80

$ 0.97

$ 1.42

1.97

Cash dividends declared and paid per share

$ 0.10

0.10

$ 73,387

1,527

$ 74,914

0.00

0.10

Diluted weighted average common

shares outstanding

35,534

28,391

28,555

28,271

22,329

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)

3,101

2,050

$ 34,000

$ 40,639

$ 13,440

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

230,438

13,000

188,772

62,478

3,790

85,218

$ 4.89

$ 26.96

$ 3.00

$ 25.34

$ 3.73

$ 23.29

3.44

23.53

2.21

16.56

307,024

47,787

593,746

274,172

36,119

490,887

241,231

23,669

383,247

225,975

20,950

351,673

207,642

18,900

321,042

Shareholders’ Equity ($ millions)

Reserve Growth (BCFE)

Production Growth (Daily MMCFE)

400

300

200

100

600

450

300

150

250

200

150

100

04
(projected)

TO OUR SHAREHOLDERS

The year 2003 represented almost the best of all worlds for
the Company: record earnings, high oil and gas prices, a 40%
increase in the Company’s production, a 21% increase in estimated
proved reserves obtained at a low reserve replacement cost,
moderate increases in operating costs, profitable sales of non-
strategic assets, and advancement of the Hanging Woman Basin
coalbed methane project to the development stage. What does this
mean in terms of creating shareholder value? When comparing
the December 31, 2002 balance sheet with the pro forma balance
sheet at December 31, 2003, adjusted for the buy-back of 3.38
million shares from Flying J for $26.92 per share in February
2004, they are very similar. Long term debt net of working capital
were essentially at the same levels and our shares outstanding
increased by only 269,000 shares or 1%. However, our proved
reserves increased by 21% to 594 BCFE. Our pretax SEC PV10
value for our proved reserves increased 55% to $1.278 billion
reflecting the 21% increase in reserves as well as increased oil
and gas prices. In addition, we added new estimated probable
reserves at Hanging Woman of 147 BCFE.

Highlights include good drilling results at Huxley in east
Texas, Northeast Mayfield in Oklahoma, and participation in the
new Bakken horizontal dolomite play in the Williston Basin;
better than expected production performance at the Parkway
Delaware waterflood project in the Permian Basin and at Judge
Digby in south Louisiana; as well as increased production from
the acquisition of properties in the Rockies from Flying J in
January 2003 and Burlington Resources in December 2002. We
opened a Houston office, which will now be directing our Gulf
Coast and Permian Basin regional operations.

The many corporate scandals over the last two years were
the catalyst for new legislation and SEC and NYSE rules, which
strengthened the requirements for good corporate governance.
Not only did the new rules expand requirements regarding the
Board’s responsibilities, procedures, and independence, they
also require enhanced and accelerated disclosures, establishment
of an internal audit function, CEO/CFO certifications, adoption of
a code of business conduct and ethics, and shareholder approval
of equity compensation plans. We have complied with these
new rules and have begun implementing procedures for the
upcoming accelerated 10K and 10Q filing framework and
internal control reports for 2004. We received an “A” rating in
corporate governance from the Corporate Library independent
evaluation service.

Net income for the year 2003 was a record $95.6 million or

$2.80 per share compared to $27.6 million or $0.97 per share
for the prior year. Net cash provided by operating activities
increased 44% to $204.3 million. Production increased 40% to
77 BCFE. The average realized price increased 41% to $4.75 per
MCFE. Unit costs increased modestly for the period as production
expenses (including taxes) increased $0.23 to $1.15 per MCFE,
DD&A (including impairments) increased $0.08 to $1.07 per
MCFE, and general and administrative expense increased $0.07
to $0.33 per MCFE.

Oil and gas reserves grew by 21% to 594 BCFE. We replaced

293% of our 2003 production at an all-inclusive finding cost of
$1.05 per MCFE. Ryder Scott has been preparing estimates of
our reserves for at least 80% of our total PV-10 value since we
went public in 1992, and we continue to report a very low PUD

M A R K A . H E L L E R S T E I N • C H A I R M A N , P R E S I D E N T & C E O

percentage, 11% at year-end. We are pleased with these results
and believe they compare favorably with industry results.
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 share-
holders a 16% compounded return since going public in 1992.

We enter 2004 on a positive note:

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

is positive.

• We have an outstanding inventory of prospects to be drilled.
• The country’s ability to supply gas remains challenging, as
the average decline rate for natural gas production has
increased from 17% to 28% over the past 13 years.
• New sources of gas such as LNG, frontier regions (e.g.
deepwater Gulf of Mexico, Mackenzie Delta, Alaska) and
unconventional gas plays are both more costly and have
long lead times, but at some point could have a positive
impact on supply.

• We believe oil prices are unusually high now due to low

inventory levels. Longer term, however, we are beginning to
see excess oil capacity in the world diminish, and OPEC
informally appearing to target a higher price range due to the
decline in the value of the dollar.

• The U.S. and world economies appear to be recovering

from the recent economic downturn, and as they continue
to recover we anticipate the demand for oil and natural
gas will increase.

We enter the year 2004 in very good financial condition and

with a capital expenditure budget of $273 million. Here is our
plan to build value in 2004:

at Trinidad SE, Bethany Longstreet, Dykesville, and Terryville.
In addition, we have two wells planned at Judge Digby in
the Gulf Coast as well as several wells in south Louisiana
targeting attic locations.

• We will begin development of our Hanging Woman Basin
coalbed methane project with the drilling of approximately
100 wells in Wyoming, and the construction of infrastructure
such as an electric grid and pipeline. We currently expect
production of natural gas to begin in 2005.

• We have received newly shot and processed 3-D seismic
data covering our entire 25,000-acre fee land position in
St. Mary Parish, Louisiana. This is the first time we have
had 3-D seismic coverage over the entire property. Cumulative
production from this fee acreage is approximately 3.5 TCF
of gas and 200 million barrels of oil. We have optioned
14,969 acres for lease primarily in the middle portion of our
property where little exploration has historically taken place.
Providing the option is exercised, the lease terms will give
us a 25% royalty interest and the option to participate for
up to 25% as a working interest owner. We believe the 3-D
seismic provides an opportunity to expose us to significant
new reserve potential.

Our annual report theme this year is “repeatability.” By
definition our resource base is depleting every day. Sustainability
in our business is dependent on people who have the ability to
create new ideas and new value year after year. St. Mary has
demonstrated over a long period of time its ability to grow value
consistently and to periodically have an idea that moves us to
another level of performance. We have learned that “large” ideas
come in a variety of forms, from exploration to secondary recovery
to opportunistic acquisition, and in a variety of regions. Examples
include the successful Parkway Delaware waterflood project,
Box Church, S. Horseshoe Bayou, King Ranch Energy, Flying J,
and Northeast Mayfield. Our decentralized organization of talented
geoscientists, engineers and landmen in each of our regional
offices, backed by a strong balance sheet and discipline, has
given us the formula for repeating success. Few companies have
done this as well as St. Mary over an extended period of time.

Ron Boone retired last year as Executive Vice President and
Chief Operating Officer having served St. Mary for more than 13
years. He will continue his role as a director of the Company. Ron
was instrumental in helping assemble the talent base, and instilling
disciplined thinking and attention to detail that has helped build
St. Mary into a highly respected public company. I am deeply
appreciative to Ron for his outstanding contribution. Over the
past two years, we have implemented a plan for succession
that has resulted in very strong regional managers and the
preparation of Ron’s successor, Doug York, who has served
St. Mary as an executive officer over the past seven years.
I have great confidence in this group and we embrace the
challenge of repeatability on your behalf.

March 5, 2004

Mark A. Hellerstein
Chairman, President and Chief Executive Officer

Capital Expenditures ($ millions)

300

200

100

04
(budget)

Operating Cash Flow ($ millions)

200

150

100

•

Production is currently forecasted to grow to 78-82 BCFE,
up from 77 BCFE in 2003. Based on NYMEX strip prices of
$30.19 per Bbl and $5.44 per Mcf, as of December 31, 2003,
we would realize approximately $4.68 per MCFE, after
hedges. Assuming this price deck, lease operating expenses,
including taxes, are forecasted at $1.18-$1.25 per MCFE
and G&A is forecasted at $0.32-$0.37 per MCFE.

Of the $273 million capital expenditures budget, 36% is
allocated for acquisitions, 22% for exploration and develop-
ment in the Mid-Continent region, 19% in the Rocky
Mountain region, 8% in the ArkLaTex region, 7% in the Gulf
Coast region, and 4% in the Permian Basin region. Four
percent of the budget is allocated to development of our
Hanging Woman Basin coalbed methane play and other CBM
projects. The drilling portion of the budget represents a 12%
increase over 2003. The significant planned exploitation
activity includes 32 wells at Northeast Mayfield, six wells
in the Arkoma Basin, and six Granite Wash wells, all in
Oklahoma. In the Rockies, we have budgeted eight operated
Bakken wells, four operated Red River wells in the Williston
Basin, and six operated wells in Wyoming at the Big Hand,
Delaney Rim, Monument Lake, and West Madden fields, as
well as 28 wells in the Greater Green River Basin that are
mostly non-operated. In the Permian Basin, we have budgeted
six infill locations at the Parkway Delaware waterflood project,
four injection wells at the East Shugart waterflood project,
seven Canyon wells, and participation in a number of
non-operated wells. In the ArkLaTex region, we are planning
to participate in 41 wells including eight horizontal James
Lime wells in east Texas and north Louisiana, and 18 wells

DOUGLAS W. YORK • EXECUTIVE VICE PRESIDENT AND CHIEF OPERATING OFFICER

OPERATIONS

St. Mary’s operations are a combination of exploration, exploitation,
development, and acquisition of oil and gas properties in five
core areas in the United States. Our five core areas — the
Mid-Continent region, the Rocky Mountain region, the ArkLaTex
region, the Gulf Coast region and the Permian Basin region —
are operated out of four regional offices. Senior managers, each
with more than 20 years of professional experience, head each
regional office. Each office has a full complement of geoscientists,
engineers, land professionals, and support personnel who typically
have spent most of their careers in the basin or region where
they are working. The regional offices are supported by centralized
administration in our Denver office.

This year was highlighted by excellent drilling results in
Northeast Mayfield in the Anadarko Basin, successful horizontal
exploitation of the James Lime formation in the Huxley field in
east Texas, improving waterflood performance in the Permian
Basin, and our participation in the horizontal Bakken play in the
Williston Basin. In addition, we closed on $77.4 million of property
acquisitions that added 113.0 BCFE of proved reserves and nearly
500,000 acres of undeveloped leases, which will provide future
exploration, development, and exploitation opportunities.

In 2003, we grew our production 40% to 76.9 BCFE, or an
average daily production rate of 210.7 MMcfe per day. Net proved
reserves at December 31, 2003 increased 21% to 593.7 BCFE,
89% proved developed, after we sold 45.6 BCFE of non-core

assets. Our reserve base at year-end 2003 was 52% natural gas
and 48% oil. During 2003, we participated in drilling 181 wells
with an 86% success rate.

We are budgeting $273 million for capital expenditures in

2004. This represents an 18% increase over the $231 million
spent in 2003. Exploration and development expenditures are
projected to be $173 million and $100 million is budgeted for
property acquisitions. We will operate approximately 75% of our
capital expenditures budget in 2004. With our strong balance
sheet, we are not limited by our $100 million budget in looking
for acquisition opportunities. We will be actively sourcing and
evaluating opportunities during 2004 for acquisitions that meet
our economic parameters.

We begin 2004 with the largest inventory of drilling
prospects in the history of our Company. We continue to add
experienced geoscientists, engineers, land professionals, and
support personnel in each of our regions. Using the extensive
proprietary databases we have compiled in each of our regions,
our growing technical teams are able to increase their prospect
generation capabilities. With offices 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.

The exploration and development programs that replaced
146% of our production through the drill bit in 2003 will continue
in 2004. In 2004, we plan to drill more than double the number
of wells we completed in 2003 in Northeast Mayfield in the
Anadarko Basin, where we have not drilled a dry hole. Our
horizontal exploitation of the James Lime formation in the
ArkLaTex region moves to the Spider field in northern Louisiana,

Reserve Base By Region

Mid-Continent – 26%

ArkLaTex – 11%

Gulf – 6%

Rocky Mountain – 49%

Permian – 8%

Capital Expenditures Budget By Region

Mid-Continent – 22%

ArkLaTex – 8%

Gulf – 7%

Rocky Mountain– 23%

Permian – 4%

Acquisitions – 37%

(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
which is similar to but geologically more complex than the Huxley
field we developed in 2003 in east Texas. We will be drilling
several infill wells in the Parkway Delaware Unit waterflood and we
anticipate production to continue to increase in the East Shugart
waterflood in the Permian Basin where we saw a production
response in 2003 to this significant secondary recovery project.
Our participation in the horizontal Bakken play in the Williston
Basin will increase significantly in 2004 as the activity moves
toward our major lease holdings in the area.

In addition, we will be participating in two new exciting
opportunities with long-term potential. In early 2004, we received
processed 3-D seismic data over our fee lands in St. Mary
Parish, Louisiana. Our fee property has produced more than 200
million barrels of oil and 3.5 TCF of natural gas since the initial
discoveries in 1938. This is the first time the middle portion of
our property has been shot with 3-D seismic and the first time
new 3-D has been shot since the early 1990s. We have optioned
the unleased acres, which if exercised, provides us with a 25%
royalty interest on any production from the property and the
right to participate for up to a 25% working interest. This election
is on a well-by-well basis. We believe there is not only a deep
untested structure on the property, but shallow potential as well.
In late 2003, we made a decision to proceed with our
coalbed methane program in the Hanging Woman Basin, which
is in the northern portion of the Powder River Basin in Montana
and Wyoming. We have 139,000 acres of net leases in Montana
and Wyoming and will begin development on the 65,000 net
acres in Wyoming. We have estimated probable reserves of 147
BCFE from five of the coal seams and acreage in Wyoming. In
addition, we believe there is significant potential in the coal
seams and acreage we have not yet evaluated. We plan to begin
drilling during the second quarter of 2004 with first production
anticipated in early 2005.

The locations for approximately 93% of our drilling
expenditures in 2004 have been identified. Our major programs
will extend well beyond 2004 on leases currently in our inventory.
Our task in 2004, as it is every year, is to continue to develop
prospects that will economically grow our reserves and production
as we have done year after year. Following is additional information
about the operations in each of our core areas and more detail
of our plans for 2004.

M I L A M R A N D O L P H P H A R O • V I C E P R E S I D E N T – L A N D A N D L E G A L

ACQUISITIONS ARE PART OF OUR GROWTH

St. Mary’s objective is to grow its per share net asset value
in excess of 15% per year. If we consistently grow net asset
value, our stock price will follow. The 16% compounded rate of
return we have provided our stockholders in dividends and stock
value over the past 11 years reflects the growth in net asset
value we have achieved.

Our growth has been a combination of organic growth through

the drill bit (the exploration, development, and exploitation
of our properties), property acquisitions, and the occasional
divestiture of non-strategic assets in overheated markets. The
synergies of exploration, development, and exploitation work
with the synergies of acquisitions and divestitures. The technical
expertise necessary to drill and exploit properties is the same
expertise needed to evaluate acquisition opportunities. In addition
to adding oil and gas reserves, acquisitions provide an inventory
of exploration, exploitation, and development opportunities. Our
goal is to replace, on average, 200% of our production, which
approximately equates to a 15% growth rate in reserves. Our
technical expertise and strong acreage positions have allowed
us to economically replace, on average, approximately 100% to
115% of our annual production organically through the drill bit.

Although our focus is to make acquisitions in our five core
areas, we also consider acquisitions that will provide an entreé
into new core areas. Niche acquisitions in our core areas allow
us to utilize our technical expertise specific to the area and take
advantage of operational efficiencies. Acquisitions outside our
core areas will be made if we believe we can develop the technical
expertise to grow the area.

With a strong balance sheet and highly regarded stock, we
have the financial capability to make significant acquisitions. Each
year we allocate approximately 40% of our capital expenditures
budget for acquisitions. In 2004 we have an acquisitions budget of
$100 million. This is a goal, but not a limit as we have substantial
unused financial capability. In the past, we have used our
Company’s stock to make acquisitions and may use stock in
the future if the acquisition is accretive to St. Mary on a net

asset value basis. Because of our strong balance sheet and
historical record, we have the reputation of being able to close
acquisitions, which can be a significant advantage in a highly
competitive environment.

The flexibility of being able to use either cash or stock or
both, has enabled us to be creative in structuring acquisitions that
are both accretive to St. Mary and responsive to the needs of
the seller. An example is the acquisition of oil and gas properties
from Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. that
closed in January 2003. In the transaction, we issued 3,380,818
restricted shares of St. Mary common stock, which represented
10% of our combined outstanding shares, for properties that
represented 15% of our combined reserves at the time of
negotiation and doubled our undeveloped leasehold inventory.
To respond to the sellers’ need for cash, we lent them $71.6
million in the form of a note, and secured the note with the
shares they received. To assure the sellers that they could
exchange their shares in full payment of the note, we granted
them the right to put their shares of St. Mary common stock to
the Company as payment of the $71.6 million note ($21.18 per
share) plus accrued interest for 30 months, and in return we
were granted the right, during that same 30-month period, to
redeem the St. Mary common stock they received for $28.82
per share. On a strictly stock-for-assets basis, the acquisition
was clearly accretive to net asset value and other metrics.
In February 2004, after substantial growth in our reserves,
production, and net asset value, we repurchased the 3,380,818
common shares for a negotiated $26.92 per share. Again, the
share repurchase is accretive to book value, earnings and EBITDAX
per share and at the same time resulted in a good outcome to
Flying J and Big West.

Because natural gas properties have generally been selling
at premiums that do not meet our return objectives, our recent
acquisitions have been primarily oil properties. Oil properties
have been less competitive, and we have been able to make
acquisitions that fit within our disciplined evaluation standards.
Our financial and evaluation criteria include acceptable returns
from the producing properties and an opportunity to add value
using our geologic concepts, reservoir management, and well
completion and production techniques. We price our acquisitions
using commodity strip pricing and generally hedge a minimum
of the first two years of estimated production from the properties.
We believe that by reducing commodity price risk, we are able
to bid more aggressively and make acquisitions that fit our
return objectives.

In 2003, we closed on $77.4 million of acquisitions that added

113.0 BCFE of proved reserves. Over the past three years, we
have closed $206.3 million of acquisitions that represent 34% of
our capital expenditures. Also in 2003, we received proceeds of
$23.5 million from the sale of non-core properties. We recorded
a before-tax gain of $7.3 million from the sale of these properties.

Rocky Mountain Region

PROVED RESERVES

% OF TOTAL RESERVES

GAS / OIL MIX

PROVED DEVELOPED RESERVES

CAPITAL EXPENDITURES BUDGET:

NON-CBM

COALBED METHANE PROJECTS

290.1 BCFE

49%

22% / 78%

95%

$51.7 MILLION

$12.2 MILLION

Nance Petroleum Corporation, a wholly owned subsidiary,
manages our operations in the Rocky Mountain region, which
now include our coalbed methane projects. Our Nance office in
Billings, Montana currently has a 58-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 and the
Permian Basin. In 2004 management of the Permian Basin was
moved to our newly opened office in Houston, Texas.

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
and Wind River Basins in Wyoming. The Williston Basin, where
we have been a dominant operator since 1991, anchors our
activity in the Rocky Mountain region. Our operations in the
Powder River (excluding coalbed methane), Greater Green
River, and Wind River Basins were primarily initiated through
acquisitions made during the past three years. 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 2003. We closed the two largest acquisitions in the history
of our company with the December 2002 acquisition from
Burlington Resources and the January 2003 Flying J acquisition.
These two acquisitions more than doubled our proved oil and
gas reserves in the Rocky Mountain region, included a large
undeveloped lease inventory, and provided numerous exploitation
opportunities. During the first part of 2003, exploration and
development activity in the Rocky Mountain region was delayed
somewhat as the majority of our time was spent assimilating
these new properties into our operations.

In 2003, the Rocky Mountain region drilled and participated

in 42 wells, of which 38, or 90%, were successful. At year-end,
two wells were completing. The region spent $100.3 million,
including $72.2 million for acquisitions, which represents 43% of
our total capital expenditures in 2003. The 28.4 BCFE produced
from the region was 37% of our total production. The Rocky
Mountain region replaced 452% of its production in 2003.

Since 1991, when we began operating in the Williston Basin,

we have had a 92% drilling success rate. Our success rate is

largely attributable to our ability to identify and match structure
and porosity development in the Red River formation using 3-D
seismic. In 2003, we completed four 3-D seismic surveys in the
Basin. Based on the 3-D results, we drilled the Steinbeisser 7-2
in the Ridgelawn field that had an initial production rate of 320
Bbls of oil per day and 1,000 Mcf of gas per day from the Red
River. We have budgeted four additional wells in the Ridgelawn
field in 2004. We are also planning to drill seven operated wells
in other prospects in 2004, all based on 3-D seismic. We have
included six 3-D seismic surveys in our capital expenditures
budget in 2004.

Primarily because of leasehold acreage acquired in
the Burlington and Flying J acquisitions, we have a significant
lease position in the horizontal Bakken dolomite play that has
become the most active new play in the Williston Basin. We have
approximately 22,000 leased acres in the fairway of this play,
where wells are being drilled with initial rates of 250 to 650 Bbls
per day and anticipated reserves of 350,000 to 750,000 barrels
of oil equivalent. We drilled and participated in three horizontal
Bakken wells. The wells were drilled in the dolomite section that
lies 20 to 30 feet below the extensively drilled Bakken shale,
which has been drilled extensively in the Basin. Acquired from
Burlington Resources, the Strand 22-27H was a marginal well in
which we own a 100% working interest and 100% net revenue
interest. This well was producing from the Bakken shale. We
reentered the Strand well bore and drilled a horizontal lateral in
the Bakken dolomite, which increased production to 340 Bbls of
oil per day. In 2003, we drilled two horizontal laterals from the
Vaira 2-35H in the Bakken dolomite. Each lateral has tested at
approximately 400 Bbls of oil per day. When combined, the well
had an initial production rate of 650 Bbls of oil per day. On our
leases we have identified 18 proven and probable locations for
horizontal Bakken wells and have budgeted to drill or reenter
wells on nine of the locations in 2004. With our lease position,
the additional leases we control east of the current exploration

WILLISTON BASIN
HORIZONTAL BAKKEN DOLOMITE PLAY

STRAND 22-27H

VAIRA 2-35H

BR 44x-1

2003 SUCCESSFUL
NANCE WELLS

SUCCESSFUL HORIZONTAL
BAKKEN WELLS

2004 WELLS TO DRILL

FUTURE IDENTIFIED LOCATIONS

M ONTAN A

NORTH
DAKOTA

Rocky Mountain Capital Expenditures
($ millions)

100

04
(budget)

Exploration & Development (cid:2) Acquisitions

Rocky Mountain Proved Reserves (BCFE)

300

200

100

Rocky Mountain Technical Employees

(cid:2)
area, and depending upon how far the Bakken dolomite play
extends, we could be actively drilling wells in this area for the
next two to three years or more.

The $51.7 million capital expenditures budget in 2004 for

the Rocky Mountain region (excluding the coalbed methane
projects discussed in the following section) is an 83% increase
over the $28.1 million spent for exploration and development
drilling in 2003. Approximately 70% of the Rocky Mountain
region budget has been allocated to the Williston Basin to drill
the previously mentioned operated wells, wells anticipated to be
proposed by other operators, recompletions, seismic, and land
costs. The balance of the budget is planned for six operated
wells in the Greater Green River, Wind River and Powder River
Basins and 28 non-operated wells primarily in the Greater Green
River Basin, along with seismic and land costs. We will operate
approximately 79% of the Rocky Mountain capital expenditures
budget (excluding the coalbed methane projects).

Coalbed Methane Projects
The Hanging Woman Basin is in the northern part of the Powder
River Basin along the Montana-Wyoming border. Since our entry
into the Basin in 2001, we have amassed a 139,000-acre net
lease position over coalbed methane reserves. Using pilot projects
that include 21 wells, extensive field geology, production
analysis and economic modeling to evaluate the potential of the
properties, we made a decision in November of 2003 to proceed
with development of the reserves. There are 10 different coal
seams present on our properties. Our initial evaluation has been
focused on 65,000 of the acres in Wyoming and five of the 10
coal seams. We have estimated probable reserves of 147 BCF,
net to our interest, from the Wyoming portion of these five
seams. These are the Anderson, Canyon, Brewster/Arnold, Nance
and Roberts coals.

Our 2004 capital expenditures budget for the Hanging
Woman Basin project is $11.0 million. The budget includes
drilling and completing 108 wells and installing power lines and
gathering facilities. Drilling is expected to begin during the second
quarter of 2004. Gas production is expected to be minimal
in 2004 and begin increasing in 2005. We anticipate drilling
approximately 175 wells per year beginning in 2005. Based on
160-acre spacing units and assuming all wells are completed
in separate coal seams (the coals are not commingled), there
is potential for approximately 1,350 wells to be drilled on
the 65,000 acres. The 139,000 total acres could include
approximately 2,600 wells.

We are also participating as a non-operator in the Atlantic Rim
Doty Mountain and Jolly Roger coalbed methane projects in the
Greater Green River Basin. For these projects in 2004, we have
budgeted $1.2 million to participate in the drilling of 14 wells
and for other associated costs.

HANGING WOMAN BASIN
COALBED METHANE PROJECT

Nance Leases

FIDELITY CX FIELD

J.M. HUBER
PRAIRIE DOG

PROPOSED
PENNACO

I N E

T O N O R T H E R N B O R D E R , N D
E D B I S O N L

P R O P O S

A N D S

– G R A

. I .

W .

BIGHORN

BITTER CREEK

R I M R O C K 1 6 "

Mid-Continent Region

PROVED RESERVES

% OF TOTAL RESERVES

GAS / OIL MIX

PROVED DEVELOPED RESERVES

CAPITAL EXPENDITURES BUDGET

152.1 BCFE

26%

96% / 4%

85%

$59.5 MILLION

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 35-person staff.

The Mid-Continent region was our most active drilling area in
2003. The region drilled and participated in 77 wells, of which 69
were successful, for a 90% success rate. The region spent $72.3
million, which represents 31% of our total capital expenditures
in 2003. The 24.7 BCFE produced from the region was 32% of
our total production. The Mid-Continent region replaced 120%
of its production through drilling in 2003.

The most active drilling area in the Mid-Continent region in
2003 was in western Oklahoma in our Northeast Mayfield prospect
area. Our entry into the area was through a 1996 acquisition of
one marginal well with interesting pressure performance that
produced from the Crook sand below 19,000 feet. We believed the
well was producing from a larger reservoir than was indicated
from the marginal production. Subsequent wells in the prospect
area confirmed our premise and led to our drilling 14 Crook sand
wells, which were all completed as producers. As our activity in
the area has increased, we have compiled a significant amount

(cid:2)
(cid:2)
of geologic data as the wells were drilled through the Morrow
section where potential pay zones were logged and mapped.
Consequently, the field has grown from a Crook sand play to a
multi-sand play that has expanded each year since our 1996
acquisition. Our well economics have improved significantly with
new fracture stimulation technology. The advent of multi-zone
fracs and commingling production from multiple zones
significantly improves the initial production rates that return our
investment sooner.

We have now produced from 18 Morrow pay intervals and

have identified five to seven additional potential Morrow pay
zones in Northeast Mayfield. These zones include the Hildebrand
and Keathley sands in which prolific producers were completed
in 1999. Due to the many wells drilled through the multiple
Morrow zones looking for the Crook sand, we have been able
to geologically map the irregular shaped sands, reducing the
geologic risk of drilling for these uphole zones. In addition, in
late 2002 we successfully tested the Atoka formation, which is
a shallower zone than the Morrow sand interval. We have now
identified five separate Atoka pays. Although not yet tested, from
log analysis we believe there may also be Granite Wash potential
in Northeast Mayfield.

What began with the one well we acquired in 1996 has
developed into one of the most active exploration plays in the
Anadarko Basin and possibly the United States. We now have
interests in 67 sections in the Mayfield area and may have the
largest holdings in the play. We have drilled and completed 40
wells in Northeast Mayfield without a dry hole. We completed
16 of the 40 wells in 2003 and were completing six wells and
drilling three more wells at year-end. We have budgeted 23
additional wells to be drilled in Northeast Mayfield in 2004 and
have identified locations for each well.

Our net production from Northeast Mayfield in 2003 increased

to 9.6 BCFE from 3.7 BCFE in 2002. The more significant wells
drilled in 2003 were the Dean 1-19 (53% St. Mary interest) that
produced at an initial rate of 20,000 Mcf per day, the Dykes 1-17
(19% St. Mary interest) that produced at an initial rate of 20,600
Mcf per day, the Bess 1-26 (58% St. Mary interest) that produced
at a rate of 14,300 Mcf per day, and the Heinsohn 4-36 (31%
St. Mary interest) that produced at a rate of 12,500 Mcf per day.

NORTHEAST MAYFIELD

DRILLING PROGRAM

(cid:127) 1997 WELLS (2)
(cid:127) 2001 WELLS (6)

(cid:127) 1998 WELLS (3)
(cid:127) 2002 WELLS (10)

(cid:127) 1999 WELLS (2)
(cid:127) 2003 WELLS (13)

(cid:127) 2000 WELLS (2)

2004 WELLS (23)

As the drilling in Northeast Mayfield expands to the west,
north, and south where we have the majority of our leasehold
interest, and as completions and recompletions are made in new
pay zones in the field, we anticipate being part of an increasing
level of drilling activity in this area for several more years. In
2004, 55% of our Mid-Continent capital expenditures budget or
$32.7 million is allocated to Northeast Mayfield.

We were also active in the Oklahoma portion of the Arkoma

Basin in 2003. During the year we added to our lease position
and completed 11 wells with no dry holes. We have allocated
$4.5 million of our 2004 capital expenditures budget to drill six
wells targeting the Cromwell, Wapanucka, Spiro, and Oil Creek
sands. In addition, 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 $59.5 million Mid-Continent 2004 capital

expenditures budget is being allocated to various prospects in
the Anadarko Basin that we continue to develop and exploit.
We are planning to spend $4.5 million to drill six Granite Wash
wells, $3.7 million to drill two Morrow / Springer wells, $3.5
million for Atoka wells, and $2.4 million for seven Osborne / Red
Fork / Cherokee wells. We plan to operate five to seven drilling
rigs throughout the year and operate 71% of our capital
expenditures budget.

(cid:1)
Mid-Continent Capital Expenditures
($ millions)

04
(budget)

Exploration & Development (cid:2) Acquisitions

Mid-Continent Proved Reserves (BCFE)

160

120

Mid-Continent Technical Employees

(cid:2)
ArkLaTex Capital Expenditures
($ millions)

04
(budget)

Exploration & Development (cid:2) Acquisitions

ArkLaTex Proved Reserves (BCFE)

ArkLaTex Technical Employees

(cid:2)
ArkLaTex Region

PROVED RESERVES

% OF TOTAL RESERVES

GAS / OIL MIX

PROVED DEVELOPED RESERVES

CAPITAL EXPENDITURES BUDGET

67.8 BCFE

11%

89% / 11%

80%

$21.6 MILLION

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 region has achieved
significant growth and provided excellent economic returns
by developing the untapped potential of Bayou D’Arbonne,
Haynesville, Box Church, and more recently the Southeast
Trinidad and Huxley fields.

The ArkLaTex region had excellent drilling results in 2003.
The region drilled and participated in 31 wells, of which 25 were
successful, for an 81% success rate. At year-end, six wells were
completing and one well was drilling. The region spent $25.1
million, which represents 11% of our total capital expenditures
in 2003. The 7.1 BCFE produced from the region was 9% of our
total production. The ArkLaTex region replaced 150% of its
production in 2003, 139% through drilling.

Our most active drilling in the ArkLaTex region in 2003 was

in the Huxley field in east Texas on acreage acquired in 2002.
The field produces from the fractured James Limestone at a
depth of 6,200 feet. Horizontal drilling techniques have made
this previously uneconomic trend a highly economic objective
that stretches from DeSoto Parish, Louisiana to Nacogdoches
County, Texas. At Huxley we have drilled two to three horizontal
laterals from each surface location with each lateral extending
as far as 8,000 feet. We completed five wells in the Huxley field
in 2003 (St. Mary’s interest in each well is 81%) with an average
initial production rate of 2,300 Mcf per day. At year-end, we
were drilling one well and another well was completing. The wells
provide good economics as the average completed well cost is
approximately $1 million and per well reserves are estimated
at 2.7 BCFE. We will be drilling one additional well in the Huxley
field in 2004, which will complete development of the field.

In 2003 we drilled our first well in the Spider field in Desoto

Parish, Louisiana, which is northeast and across the Toledo
Bend Reservoir from the east Texas Huxley field. This was the
first horizontal James Lime completion in the Spider field, which
is also part of the James Lime horizontal trend. The geology
at Spider is more complex than at Huxley and will require drilling
the horizontal laterals from each well in different configurations

JAMES LIME HORIZONTAL TREND
HUXLEY AND SPIDER FIELDS

to maximize production and reserve potential. We plan to drill
seven wells in the Spider field in 2004, which represents about
31% of our ArkLaTex drilling budget.

The balance of our $21.6 million ArkLaTex 2004 capital

expenditures budget is being allocated to a mix of exploratory
and development projects in our prospect inventory. We plan to
operate 81% of our ArkLaTex capital expenditures budget in 2004.

Gulf Coast Region

PROVED RESERVES

% OF TOTAL RESERVES

GAS / OIL MIX

PROVED DEVELOPED RESERVES

CAPITAL EXPENDITURES BUDGET

33.1 BCFE

94% / 6%

94%

$18.4 MILLION

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. We believe Houston will
be a more central location to our operations and will assist in
the growth of these two core areas.

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 24,900 acres of fee lands
since 1938. The fee lands represent a smaller portion of our
company’s production each year but still yielded $4.6 million of
oil and gas royalty revenue to St. Mary in 2003. The onshore
Gulf Coast and Gulf of Mexico became a core area in 1999 with
the acquisition of King Ranch Energy when we acquired producing
and undeveloped properties along with 260,000 gross

Gulf/Permian Capital Expenditures
($ millions)

04
(budget)

Exploration & Development (cid:2) Acquisitions

Gulf/Permian Proved Reserves (BCFE)

125

100

Gulf/Permian Technical Employees

(cid:2)
undeveloped acres and a large 3-D seismic database. The region
contributed 17% of our production in 2003.

The region is focused on development and exploitation
opportunities. We continue to participate in the successful
development of the Judge Digby field, although the field is nearing
the end of new drilling. Our interest in the outside operated,
ultra-deep field located in Point Coupe Parish outside Baton
Rouge, Louisiana, which has produced more than 485 BCF of
gas and 1.2 million Bbls of oil, ranges from 5% to 20% depending
upon which of the 15 identified pay zones is producing. We
have participated in seven new discoveries since acquiring our
interest in the field in 1999. Approximately 29% of our $18.4
million budget for the Gulf region in 2004 is being allocated to
Judge Digby. We plan to participate in drilling two new wells and
the recompletion of several wells in 2004. As producing zones
deplete, the wells are recompleted to the next uphole pay inter-
val. 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.

In 2003, a seismic company conducted a single cohesive

3-D seismic survey over our 24,900-acre fee property. It was the
first time the entire property had been included in a 3-D seismic
survey. For allowing the survey on our property, we received a
fee of $900,000 and were granted rights to the processed data.
We also granted the seismic company the option to lease 14,900
acres that are currently available. If the option to lease is exercised,
we will receive $250 per acre, a 25% mineral owner’s royalty, and
the right to participate for up to a 25% working interest in any
well drilled on the property. This election is on a spacing unit basis.
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.

Permian Basin Region

PROVED RESERVES

% OF TOTAL RESERVES

GAS / OIL MIX

PROVED DEVELOPED RESERVES

CAPITAL EXPENDITURES

50.6 BCFE

13% / 87%

70%

$10.0 MILLION

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. Production in the Permian region increased 14% in
2003 primarily due to the January 2003 purchase of an additional

BAYOU SALE FIELD

WAX LAKE FIELD

BELLE ISLE FIELD

HORSESHOE BAYOU FIELD

HBP LEASEHOLD

OPTIONED

L OUISIANA

FEE LANDS
3-D SEISMIC SURVEY

50% interest in our Fort Chadbourne Odum Lime Unit and
the improving performance of our two waterflood projects.
Production at the Parkway Delaware Unit waterflood, which we
initiated in 1999 when production was 450 Bbls per day, continues
to increase. Production in 2003 was 1,250 Bbls per day, up 5%
from 2002. Production at the East Shugart Delaware Unit
waterflood, which is an analog to the Parkway Delaware Unit,
increased 4% in 2003 as the formation began to respond to
water injection. 34% of the Permian region’s $10.0 million 2004
capital expenditures budget is being allocated to six infill locations
at Parkway, four injection wells at East Shugart, and various
workover and recompletion efforts in these units.

We will sell non-core assets when we are able to obtain a
premium price in a high commodity price environment. In 2003,
we sold various properties including the Fort Chadbourne Odum
Lime Unit on that basis. Our initial ownership of Fort Chadbourne
came as part of the 1999 King Ranch Energy acquisition. With
its large well count, low production rates, and high operating
costs, the unit becomes uneconomic in a low commodity
price environment. For these reasons, Fort Chadbourne is a
property we didn’t want to own for the long term, but we felt by
obtaining operations, improving field production through drilling
development wells, reworking existing wells, and obtaining
additional interest in the field, we could enhance our value. As
evidenced by our successful sale of this and other properties,
this goal was accomplished.

(cid:2)
(cid:2)
DIRECTORS

OFFICERS

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

George M. Hearne IV
Vice President – General Manager,
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

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

Barbara M. Baumann
Denver, Colorado
President
Cross Creek Energy Corporation

Larry W. Bickle
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 Co.

Thomas E. Congdon
Denver, Colorado
Former Chairman
St. Mary Land & Exploration Co.

William J. Gardiner
Houston, Texas
Chief Financial Officer
King Ranch Inc.

Mark A. Hellerstein
Denver, Colorado
Chairman, President and
Chief Executive Officer
St. Mary Land & Exploration Co.

Arend J. Sandbulte
Duluth, Minnesota
Former Director and Chairman
ALLETE, Inc.

John M. Seidl
San Francisco, California
Chief Program Officer,
Environment
Gordon and Betty Moore
Foundation

SHAREHOLDER INFORMATION

INVESTOR 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 20, 2004 the
Company had 28,339,963 shares of common stock outstanding.

Market Prices

2003— Quarter Ended

2002— Quarter Ended

March 31

June 30

September 30

December 31

high

low

high

low

$27.23

$23.80

$23.25

$18.75

29.75

28.85

29.19

24.65

24.45

25.05

24.71

27.35

21.00

19.00

23.16

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