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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[ x ] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended December 31, 2004
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission file number 001-31539
ST. MARY LAND & EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 41-0518430
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
1776 Lincoln Street, Suite 700, Denver, Colorado 80203
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(Address of principal executive offices) (Zip Code)
(303) 861-8140
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange
on which registered
Common Stock, $.01 par value New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [ x ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12-b-2 of the Act). Yes [ x ] No [ ]
The aggregate market value of 28,070,421 shares of voting stock held by
non-affiliates of the registrant, based upon the closing sale price of the
common stock on June 30, 2004, the last business day of the registrant's most
recently completed second fiscal quarter, of $35.65 per share as reported on the
New York Stock Exchange was $1,000,710,509. Shares of common stock held by each
director and executive officer and by each person who owns 10 percent or more of
the outstanding common stock or who is otherwise believed by the Company to be
in a control position have been excluded. This determination of affiliate status
is not necessarily a conclusive determination for other purposes.
As of February 15, 2005, the registrant had 28,798,362 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information required by Items 10, 11, 12, 13 and 14 of Part III is
incorporated by reference from portions of the registrant's definitive proxy
statement relating to its 2004 annual meeting of stockholders to be filed within
120 days after December 31, 2004.
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TABLE OF CONTENTS
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ITEM PAGE
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PART I
ITEM 1. BUSINESS..............................................................1
Background........................................................1
Business Strategy.................................................2
Significant Developments since December 31, 2003..................3
Major Customers...................................................5
Employees and Office Space........................................5
Title to Properties...............................................5
Seasonality.......................................................5
Competition.......................................................5
Government Regulations............................................6
Risk Factors......................................................8
Cautionary Statement about Forward-Looking Statements............18
Available Information............................................18
Glossary.........................................................19
ITEM 2. PROPERTIES...........................................................22
Operations.......................................................22
Acquisitions and Divestitures....................................25
Reserves.........................................................26
Production.......................................................27
Productive Wells.................................................27
Drilling Activity................................................28
Acreage..........................................................29
ITEM 3. LEGAL PROCEEDINGS....................................................30
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................30
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT.................................31
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS..................................................32
ITEM 6. SELECTED FINANCIAL DATA..............................................34
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TABLE OF CONTENTS
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(Continued)
ITEM PAGE
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS..................................36
Overview of the Company...........................................36
Overview of Liquidity and Capital Resources.................41
Critical Accounting Policies and Estimates..................48
Additional Comparative Data in Tabular Format...............52
Comparison of Financial Results and Trends
Between 2004 and 2003....................................53
Comparison of Financial Results and Trends
Between 2003 and 2002.....................................54
Other Liquidity and Capital Resource Information............56
Accounting Matters..........................................57
Environmental...............................................57
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK (included with the content of ITEM 7)....................58
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................58
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE..................................58
ITEM 9A. CONTROLS AND PROCEDURES..............................................58
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT...................61
ITEM 11. EXECUTIVE COMPENSATION...............................................61
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.......................61
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................61
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES...............................61
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K..................................................62
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PART I
When we use the terms "St. Mary," "we," "us" or "our," we are referring
to St. Mary Land & Exploration Company and its subsidiaries, unless the
context otherwise requires. We have included technical terms important to an
understanding of our business under "Glossary". Throughout this document we make
statements that are classified as "forward-looking". Please refer to the
"Cautionary Statement about Forward-Looking Statements" section of this document
for an explanation of these types of statements.
ITEM 1. BUSINESS
Background
We are an independent oil and gas company engaged in the exploration,
exploitation, development, acquisition and production of natural gas and crude
oil. We were founded in 1908 and incorporated in Delaware in 1915. Our primary
objective is to invest in oil and gas producing assets that result in a superior
return on equity while preserving underlying capital, resulting in a return on
equity to stockholders that reflects capital appreciation as well as the payment
of cash dividends. Our operations are focused in the following five core
operating areas in the United States:
o the Mid-Continent region in western Arkansas, Oklahoma and
northern Texas, primarily in the Anadarko and Arkoma basins,
with significant activity in the Northeast Mayfield field;
o the Rocky Mountain region consisting of the Williston Basin in
eastern Montana and western North Dakota and the Powder River,
Green River, Wind River and Big Horn basins in Wyoming. The
most recent activity in the Rockies includes drilling in the
Middle Bakken formations, continued exploration in the Red
River formation, and the development of coalbed methane
reserves in the Hanging Woman Basin;
o the ArkLaTex region that spans northern Louisiana and southern
Arkansas, Mississippi and eastern Texas, with the most recent
activity drilling horizontal wells in the James and Pettet
Limestones;
o the Gulf Coast region, including the Judge Digby field and our
fee property in St. Mary Parish, Louisiana;
o the Permian Basin in eastern New Mexico and western Texas;
included in this area is the Parkway Delaware Unit and the
East Shugart Delaware Unit in New Mexico.
As of December 31, 2004, we had estimated proved reserves of
approximately 56.6 MMBbl of oil and 319.2 Bcf of natural gas, or a total of
658.6 BCFE with a PV-10 value of $1.5 billion. Of these reserves, 85 percent
were proved developed and 52 percent were crude oil. This represents an
increase in reserve volumes of 11 percent and a 17 percent increase in PV-10
value from a year earlier. For the year ended December 31, 2004, we produced
75.4 BCFE representing average daily production of 206.0 MMCFE, a two percent
decrease from 2003. Our reserve replacement in 2004 was 190 percent of
production. Included in the proved reserve total at December 31, 2004 is 9.4
BCFE in our coalbed methane projects in the Hanging Woman Basin and the Atlantic
Rim field.
We attempt to focus our resources in selected domestic basins where we
believe our expertise in geology, geophysics and drilling and completion
techniques provides us with competitive advantages. We have assembled a balanced
program of low-to-medium-risk development and exploitation projects to provide
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the foundation for steady growth, including non-conventional gas plays in the
Rocky Mountain region. In 2004 we spent $228.8 million in capital expenditures
related to drilling activities, $76.7 million on acquisition of oil and gas
properties and $7.9 million on leasing activity.
We measure and rank our investment decisions based on their
risk-adjusted estimated internal rate of return and return on investment. In
2004 all acquisitions were funded with available cash and funding from our
revolving credit facility. When we issue stock for the acquisition of properties
or a corporate entity, we base our investment decision primarily on the
transaction's impact on net asset value per share.
We divest selected non-core assets when market conditions and prices
are attractive, and we will continue to evaluate such opportunities in the
future. For example, in 2004 we sold certain oil and gas properties for total
proceeds of approximately $2.8 million, resulting in a gain of $1.8 million.
We seek to develop our existing property base and acquire acreage with
additional potential in our core areas. From January 1, 2002, through December
31, 2004, we participated in the drilling or recompletion of 777 gross wells
with a success rate of 84 percent. During that same period we added estimated
proved reserves of 537.0 BCFE at an average finding cost of $1.38 per MCFE. Our
average annual production replacement was 259 percent during this three-year
period, and our production has grown from an average daily rate of 150.8 MMCFE
per day in 2002 to 206.0 MMCFE per day in 2004. Production in December 2004
averaged 216.7 MMCFE per day.
As of December 31, 2004, we had an acreage position of 1,969,808 gross
(1,037,522 net) acres of which 1,184,086 gross (722,396 net) acres were
undeveloped. Our current leasehold position represents a 2 percent decrease on a
gross acre basis and a 5 percent decrease on a net acre basis from 2003. In
addition to the leased acreage position, we own 24,914 net acres of fee
properties in St. Mary Parish, Louisiana and mineral servitudes representing
14,316 gross (9,514 net) acres in other portions of Louisiana.
For 2005 we have budgeted capital expenditures of $293 million for
ongoing development, exploitation and exploration programs in our core operating
areas and $125 million for the acquisition of oil and gas properties.
Our principal offices are located at 1776 Lincoln Street, Suite 700,
Denver, Colorado 80203, and our telephone number is (303) 861-8140.
Business Strategy
Our objective is to build stockholder value through consistent economic
growth in reserves and production that increase net asset value and earnings per
share. The principal elements of our strategy are as follows:
o Maintain Focused Geographic Operations. We focus on
exploration, development and acquisition activities in five
core operating areas where we have built a balanced portfolio
of proved reserves, development drilling opportunities,
leasehold, and non-conventional gas prospects. We believe that
our significant leasehold position is a strategic asset. Our
senior technical managers, each possessing over 15 years of
industry experience, head up fully-staffed regional technical
offices that are supported by centralized administration from
our Denver office. We believe that our long-standing presence,
our application of technology, our established networks of
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local industry relationships and our acreage holdings in our
core operating areas provide us with a competitive advantage.
o Continue Exploitation and Development of Existing Properties.
We use our comprehensive base of geological, geophysical,
engineering and production experience in each of our core
operating areas to source prospects for our ongoing
low-to-medium-risk development and exploitation programs. We
conduct detailed geologic studies and use an array of
technologies and tools including 2-D and 3-D seismic imaging,
hydraulic fracturing and reservoir stimulation techniques,
horizontal drilling, secondary recovery and specialized
logging tools to enhance the potential of our existing
properties. In 2004 we participated in the drilling or
recompletion of 368 gross wells with an 88 percent success
rate.
o Make Selective Acquisitions. We make selective acquisitions of
oil and gas properties that complement our existing
operations, offer economies of scale and provide further
development, exploitation and exploration opportunities based
on proprietary geologic concepts. We focus on relatively small
transactions where we have specialized geologic knowledge or
operating experience to enable us to acquire attractively
priced properties. In addition, we pursue corporate
acquisitions that we believe are accretive and capable of
being integrated into the Company. In 2004, we acquired the
stock of Goldmark Engineering, Inc., and in early 2005 we
completed the acquisition of Agate Petroleum, Inc. Other
examples of corporate acquisitions include our 1999 Nance
Petroleum Corporation and King Ranch Energy, Inc.
acquisitions, both of which were accomplished with the
issuance of our common stock. The Flying J Oil & Gas Inc.
et al. property acquisition transaction completed in 2003 was
not a corporate acquisition. We used a combination of
restricted stock, a loan to Flying J and options on our common
stock to consummate this transaction. We have budgeted $125
million for acquisitions in 2005.
o Control Operations. We believe it is important to control
geologic and operational decisions as well as the timing of
those decisions. As of December 31, 2004, we operated 69
percent of our properties on a reserve volume basis and 66
percent on a PV-10 value basis. We are the operator of
properties representing approximately 71 percent of our 2005
capital budget.
o Maintain Financial Flexibility. Conservative use of financial
leverage has long been a critical element of our strategy. We
believe that maintaining a strong balance sheet is a
significant competitive advantage that enables us to pursue
acquisition and other opportunities, especially in weaker
price environments. It also provides us with the financial
resources to weather periods of volatile commodity prices or
escalating costs. Our debt to total capitalization ratio was
22 percent at the end of December 2004.
Significant Developments since December 31, 2003
o 2004 Acquisition of Oil and Gas Properties. Our total
acquisitions of proved and unproved oil and gas properties in
2004 were $76.7 million. The two most significant acquisitions
were the Goldmark Engineering, Inc. et al. acquisition that
closed on November 1, 2004 for $23.3 million and the Border
Company et al. acquisition that closed on December 15, 2004
for $37.8 million. The primary asset acquired in the Goldmark
transaction was the operations and majority ownership in the
Fourbear Field, located in the Big Horn Basin of Wyoming. We
anticipate that the development program in this field will be
quite active in 2005 and will include infill drilling,
recompletion of additional pay zones, workovers and the
possible employment of enhanced recovery techniques. The
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Border Company acquisition primarily included a non-operated
interest in the very active Elm Grove Field, located in
Northern Louisiana where we expect to participate in numerous
development locations.
o Coalbed Methane Development. We realized our first commercial
production for the Hanging Woman Basin coalbed methane project
in 2004. Our total proved reserves at Hanging Woman Basin at
the end of 2004 were 8 BCFE. During 2004 we drilled and
completed 57 wells. The non-operated pipeline and compression
station connecting the wells to the main trunk line became
operational in mid-December 2004. The 2005 capital program for
the Hanging Woman Basin development is currently budgeted at
$24 million. We also participated in a coalbed methane
development project at Atlantic Rim in the Green River Basin
of Wyoming.
o Increase in 2004 Year-End Reserves. Proved reserves increased
11 percent to 658.6 BCFE at December 31, 2004, from 593.7 BCFE
at December 31, 2003. We added 52 BCFE through acquisitions,
primarily in the Rocky Mountain and ArkLaTex regions, and 101
BCFE from drilling activities. There were net downward
revisions of previous reserves totaling 10 BCFE. These
downward revisions were the combination of a 16 BCFE increase
resulting from price adjustments and a 26 BCFE decrease due to
performance revisions. The 11 percent increase in reserves
over last year is net of current year sales of oil and gas
properties of 3 BCFE.
o Drilling Results. The majority of the reserve additions
attributed to drilling operations came from our Rocky Mountain
and Mid-Continent regions. The increase in the Rockies can be
attributed primarily to continued development of the Middle
Bakken play. This is one of the most active plays in the
United States. Currently concentrated in Montana, the play is
thought to extend into North Dakota. As of year end, we have
approximately 181,000 net acres leased in Richland County,
Montana, and McKenzie and Billings Counties, North Dakota, of
which we believe approximately 74,000 net acres is in the
primary trend. The Red River formation continues to result in
reserve additions in the Rockies as we take full advantage of
3-D seismic to identify multi-pay structures. Mid-Continent
reserve additions were primarily from the continued
exploitation and development of the Northeast Mayfield area,
although the results were less significant than in the prior
year. The finding costs resulting from the Mid-Continent area
were higher than the Company average as a whole.
o Repurchase of Common Stock. In February 2004, we repurchased
3,380,818 shares of our common stock from Flying J for a total
of $91.0 million. We originally issued these shares to Flying
J on January 29, 2003, in connection with our acquisition of
oil and gas properties. We also loaned Flying J $71.6 million
in connection with the property acquisition. Flying J used the
proceeds from the share repurchase to repay the outstanding
loan balance. The net $19.4 million difference was funded from
our available cash and from borrowings under our credit
facility. The amount funded from borrowings under our credit
facility was repaid during the second quarter of 2004. In the
third quarter of 2004, we re-initiated our stock repurchase
program. Since that time we have repurchased a total of
489,300 shares of our common stock at an average cost of
$33.39 per share. These repurchases were funded from available
cash. As of December 31, 2004, the number of additional shares
that may be repurchased under the program is 2,510,700.
4
Major Customers
During 2004, sales to Tesoro Refining and Marketing accounted for 20
percent of our total oil and gas production revenue. During 2003, sales to BP
America Production Company accounted for 14 percent, sales to Midcoast Energy
accounted for 13 percent and sales to Tesoro Refining and Marketing accounted
for 11 percent of our total oil and gas production revenue. During 2002, there
were no sales to individual customers that accounted for more than 10 percent of
our total oil and gas production revenue.
Employees and Office Space
As of February 15, 2005, we had 256 full-time employees. None of our
employees are subject to a collective bargaining agreement, and we consider our
relations with our employees to be good. We lease approximately 47,400 square
feet of office space in Denver, Colorado, for our executive and administrative
offices, of which 9,500 square feet is subleased. We also lease approximately
18,600 square feet of office space in Tulsa, Oklahoma; approximately 11,700
square feet in Shreveport, Louisiana; approximately 13,700 square feet in
Houston, Texas; and approximately 22,200 square feet in Billings, Montana.
Title to Properties
Substantially all of our working interests are held pursuant to leases
from third parties. A title opinion is usually obtained prior to the
commencement of drilling operations on properties. We have obtained title
opinions or conducted a thorough title review on substantially all of our
producing properties and believe that we have satisfactory title to such
properties in accordance with standards generally accepted in the oil and gas
industry. The majority of the value of our properties is subject to a mortgage
under our credit facility, customary royalty interests, liens for current taxes,
and other burdens that we believe do not materially interfere with the use of or
affect the value of such properties. We perform only a minimal title
investigation before acquiring undeveloped leasehold.
Seasonality
Generally, but not always, the demand and price levels for natural gas
increase during the colder winter months and decrease during the warmer summer
months. In addition, pipelines, utilities, local distribution companies and
industrial users utilize natural gas storage facilities and purchase some of
their anticipated winter requirements during the summer, which can lessen
seasonal demand fluctuations. Crude oil and the demand for heating oil are also
impacted with generally higher prices in the winter. Seasonal anomalies such as
mild winters sometimes lessen these fluctuations.
Competition
The oil and gas industry is intensely competitive. This is particularly
so in the acquisition of prospective oil and natural gas properties and oil and
gas reserves. We believe that our leasehold position provides the foundation for
a strong drilling program. Our competitive position also depends on our
geological, geophysical and engineering expertise, and our financial resources.
We believe that the location of our leasehold acreage, our exploration, drilling
and production expertise and the experience and knowledge of our management and
industry partners enable us to compete effectively in our core operating areas.
Notwithstanding our talents and assets, we still face stiff competition from a
substantial number of major and independent oil and gas companies that have
larger technical staffs and greater financial and operational resources than we
do. Many of these companies not only engage in the acquisition, exploration,
development and production of oil and natural gas reserves, but also have
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refining operations, market refined products and generate electricity. We also
compete with other oil and natural gas companies in attempting to secure
drilling rigs and other equipment necessary for drilling and completion of
wells. Consequently, drilling equipment may be in short supply from time to
time. Currently, access to incremental drilling equipment in certain regions is
difficult.
Government Regulations
Our business is subject to various federal, state and local laws and
governmental regulations that may be changed from time to time in response to
economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling bonds, reports concerning
operations, the spacing of wells, unitization and pooling of properties,
taxation and environmental protection. From time to time, regulatory agencies
have imposed price controls and limitations on production by restricting the
rate of flow of oil and gas wells below actual production capacity in order to
conserve supplies of oil and gas.
Energy Regulations. Our sales of natural gas are affected by the
availability, terms and cost of transportation. The price and terms of access to
pipeline transportation are subject to extensive federal and state regulation.
From 1985 to the present, several major regulatory changes have been implemented
by Congress and the Federal Energy Regulatory Commission that affect the
economics of natural gas production, transportation and sales. In addition, the
FERC is continually proposing and implementing new rules and regulations
affecting those segments of the natural gas industry that remain subject to the
FERC's jurisdiction, most notably interstate natural gas transmission companies.
These initiatives may also affect the intrastate transportation of gas under
certain circumstances. The stated purpose of many of these regulatory changes is
to promote competition among the various sectors of the natural gas industry.
The ultimate impact of the complex rules and regulations issued by the
FERC since 1985 cannot be predicted. In addition, many aspects of these
regulatory developments have not become final but are still pending judicial and
final FERC decisions. Regulations implemented by the FERC in recent years could
result in an increase in the cost of transportation service on certain petroleum
product pipelines. In addition, some of the FERC's more recent proposals may,
however, adversely affect the availability and reliability of interruptible
transportation service on interstate pipelines. Additional proposals and
proceedings that might affect the natural gas industry are pending before
Congress and the courts. The natural gas industry historically has been very
heavily regulated, and there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue. We do not
believe that we will be affected by any action taken that differs materially
from other natural gas producers and marketers with whom we compete.
Certain operations we conduct involve federal minerals that the
Minerals Management Service administers. The MMS issues leases covering such
lands through competitive bidding. These leases contain relatively standardized
terms and require compliance with federal laws and detailed MMS regulations. For
offshore operations, lessees must obtain MMS approval for exploration plans and
development and production plans prior to the commencement of such operations.
In addition to permits required from other agencies such as the Coast Guard, the
Army Corps of Engineers and the Environmental Protection Agency, lessees must
obtain a permit from the MMS prior to the commencement of drilling. Lessees must
also comply with detailed MMS regulations governing, among other things:
o engineering and construction specifications for offshore
production facilities;
o safety procedures;
6
o flaring of production;
o plugging and abandonment of Outer Continental Shelf wells;
o calculation of royalty payments and the valuation of
production for this purpose; and
o removal of facilities.
To cover the various obligations of lessees on the OCS, the MMS
generally requires that lessees post substantial bonds or other acceptable
assurances that such obligations will be met. The cost of such bonds or other
surety can be substantial, and we may not be able to continue to obtain bonds or
other surety in all cases. Under certain circumstances the MMS may require our
operations on federal leases to be suspended or terminated.
Many of the states in which we conduct our oil and gas drilling and
production activities regulate such activities by requiring, among other things,
drilling permits and bonds and reports concerning operations. The laws of these
states also govern a number of environmental and conservation matters, including
the handling and disposing of waste material, plugging and abandonment of wells,
restoration requirements, unitization and pooling of natural gas and oil
properties and establishment of maximum rates of production from natural gas and
oil wells. Some states prorate production to the market demand for oil and
natural gas.
Our anticipated coalbed methane gas production from the Hanging Woman
Basin will be similar to our traditional natural gas production as to the
physical producing facilities and the product produced. However, the subsurface
mechanisms that allow the gas to move to the wellbore and the producing
characteristics of coalbed methane wells are very different from traditional
natural gas production. Unlike conventional gas wells, which require a porous
and permeable reservoir, hydrocarbon migration and a natural structural and/or
stratigraphic trap, the coalbed methane gas is trapped in the molecular
structure of the coal itself until released by pressure changes resulting from
the removal of in situ water. Frequently, coalbeds are partly or completely
saturated with water. As the water is removed, internal pressures on the coal
are decreased, allowing the gas to desorb from the coal and flow to the
wellbore. Unlike traditional gas wells, new coalbed methane wells often produce
water for several months and then, as the water production decreases, natural
gas production increases as the coal seams de-water.
Coalbed methane gas production in the Hanging Woman Basin requires
state permits for the use of well-site pits and evaporation ponds for the
disposal of produced water. Groundwater produced from the coal seams can
generally be discharged into arroyos, surface waters, well-site pits and
evaporation ponds without a permit if it does not exceed surface discharge
permit levels, and meets state and federal primary drinking water standards. All
of these disposal options require an extensive third-party water sampling and
laboratory analysis program to ensure compliance with state permit standards.
Where water of lesser quality is involved or the wells produce water in excess
of the applicable volumetric permit limits, additional disposal wells would have
to be drilled to re-inject the produced water back into deep underground rock
formations.
Environmental Regulations. Our operations are subject to numerous
existing federal, state and local laws and regulations governing environmental
quality and pollution control. These laws and regulations may require that
permits be obtained before drilling commences, restrict the types, quantities
and concentration of various substances that can be released into the
environment in connection with drilling and production activities, and limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands
and other protected areas, including areas containing endangered animal species.
As a result, these laws and regulations may substantially increase the costs of
7
exploring, developing or producing oil and gas and may prevent or delay the
commencement or continuation of a project. In addition, these laws and
regulations may impose substantial clean-up, remediation and other obligations
in the event of any discharges or emissions in violation of such laws and
regulations.
To date we have not experienced any material adverse effect on our
financial condition or results of operations from obligations under
environmental laws and regulations. We believe that we are in substantial
compliance with currently applicable environmental laws and regulations and that
continued compliance with existing requirements would not have a material
adverse impact on us.
Risk Factors
In addition to the other information set forth elsewhere in this Form
10-K, the following factors should be carefully considered when evaluating St.
Mary.
Risks Related to Our Business
Oil and natural gas prices are volatile, and an extended decline in
prices would hurt our profitability and financial condition.
Our revenues, operating results, profitability, future rate of growth
and the carrying value of our oil and gas properties depend heavily on
prevailing market prices for oil and gas. Any substantial or extended decline in
the price of oil or gas would have a material adverse effect on us. It could
reduce our cash flow and borrowing capacity, as well as the value and the amount
of our oil and gas reserves.
Historically, the markets for oil and gas have been volatile, and they
are likely to continue to be volatile. Wide fluctuations in oil and gas prices
may result from relatively minor changes in the supply of and demand for oil and
gas, market uncertainty and other factors that are beyond our control,
including:
o worldwide and domestic supplies of oil and natural gas;
o the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
o political instability or armed conflict in oil or gas
producing regions;
o worldwide economic conditions;
o the availability of transportation facilities;
o weather conditions; and
o actions of governmental authorities.
Declines in oil and gas prices would reduce our revenue and could also
reduce the amount of oil and gas that we can produce economically and, as a
result, could have a material adverse effect on us.
8
Our future success depends on our ability to replace reserves.
Our future success depends on our ability to find, develop and acquire
oil and gas reserves that are economically recoverable. Our properties produce
at a declining rate over time. In order to maintain current production rates we
must locate and develop or acquire new oil and gas reserves to replace those
being depleted by production. We may do this even during periods of low oil and
gas prices. In addition, competition for producing oil and gas properties is
intense and many of our competitors have financial and other resources
substantially greater than those available to us. Therefore, we may not be able
to acquire oil and gas properties that contain economically recoverable reserves
or we may not be able to acquire such properties at acceptable prices. Without
successful exploration or acquisition activities, our reserves, production and
revenues will decline rapidly.
Our producing property acquisitions carry significant risks.
Successful property acquisitions require an assessment of a number of
factors beyond our control. These factors include recoverable reserves, future
oil and gas prices, operating costs and potential environmental and other
liabilities. These assessments are inexact and their accuracy is inherently
uncertain. A customary review of subject properties will not necessarily reveal
all existing or potential problems.
In connection with our acquisitions, we may not be entitled to
contractual indemnification for pre-closing liabilities, including environmental
liabilities. Normally, we acquire interests in properties on an "as is" basis
with limited remedies for breaches of representations and warranties.
o Additionally, significant acquisitions can change the nature of our operations
and business depending upon the character of the acquired properties if they
have substantially different operating and geological characteristics or are in
different geographic locations than our existing properties. To the extent that
acquired properties are substantially different than our existing properties,
our ability to efficiently realize the expected economic benefits of such
transactions may be limited.
We may not be able to successfully integrate future property or corporate
acquisitions.
Integrating acquired properties and businesses involves a number of
special risks, including the possibility that management may be distracted from
normal business concerns by the need to integrate operations and systems and in
retaining and assimilating additional employees. Therefore, we may not be able
to realize all of the anticipated benefits of the acquisitions.
Substantial capital is required to replace and grow reserves.
We make, and will continue to make, substantial expenditures to find,
acquire, develop and produce oil and natural gas reserves. Our capital
expenditures for oil and gas properties were $313 million for 2004, and we have
budgeted total capital expenditures of $418 million in 2005. If oil and gas
prices decrease or we encounter operating difficulties that result in our cash
flow from operations being less than expected, we may have to reduce the capital
we can spend unless we raise additional funds through debt or equity financing.
Debt or equity financing, cash generated by operations or borrowing capacity may
not be available to us in sufficient amounts or on acceptable terms to meet
these requirements.
9
Future cash flows and the availability of financing will be subject to
a number of variables, such as:
o our success in locating and producing new reserves;
o the level of production from existing wells; and
o prices of oil and natural gas;
Issuing equity securities to satisfy our financing requirements could
cause substantial dilution to existing stockholders. Debt financing could lead
to us being more vulnerable to competitive pressures and economic downturns.
If our revenues were to decrease due to lower oil and natural gas
prices, decreased production or other reasons, and if we could not obtain
capital through our credit facility or otherwise, our ability to execute our
development plans, replace our reserves or maintain production levels could be
greatly limited.
We could incur substantial additional loans, which could negatively impact our
financial condition, results of operations and business prospects.
As of December 31, 2004, we had $137 million in outstanding loans,
including $100 million outstanding under our 5.75% Senior Convertible Notes due
2022. Our level of debt could have important consequences on our operations,
including:
o requiring us to dedicate a substantial portion of our cash
flow from operations to required payments on debt, thereby
reducing the availability of cash flow for working capital,
capital expenditures and other general business activities;
o limiting our ability to obtain additional financing in the
future for working capital, capital expenditures and other
general business activities;
o limiting our flexibility in planning for, or reacting to,
changes in our business and the industry in which we operate;
and
o detracting from our ability to successfully withstand a
downturn in our business or the economy generally.
The occurrence of any one of these events could have a material adverse
effect on our business, financial condition, results of operations and business
prospects.
We may incur additional debt, including secured debt under our credit
facility or otherwise, in order to make future acquisitions or to develop our
properties. We may not be able to generate sufficient cash flow to pay the
interest on additional debt. Future working capital, borrowings or equity
financing may not be available to pay or refinance such debt.
In addition, our credit facility borrowing base is subject to periodic
borrowing base redeterminations. We could be forced to repay a portion of our
bank borrowings due to a downward redetermination of our borrowing base. We may
not have sufficient funds to make such repayment. If we do not have sufficient
funds and are otherwise unable to negotiate renewals of our borrowing or arrange
new financing, we may have to sell significant assets. Any such sale could have
a material adverse effect on our business and financial results.
10
We may not be able to obtain credit facility borrowing base redeterminations
that adequately meet our anticipated financing needs.
Our current long-term credit facility with a group of banks has a
maximum loan amount of $300 million. The amount actually available from time to
time depends on a borrowing base that the lenders periodically redetermine based
on the value of our oil and gas properties and other assets. In October 2004 the
banks conducted their normal semi-annual borrowing base redetermination that
resulted in a borrowing base of $325 million. Since we pay commitment fees based
on the unused portion of the borrowing base, we elected to retain a total loan
commitment amount under the facility of $150 million to correspond with our
projected funding requirements. Our next borrowing base redetermination is
scheduled to occur by the end of April 2005. The banks may not agree to a
borrowing base redetermination that is adequate for our planned financing
requirements.
Our long term credit facility is scheduled to expire in January 2006.
We anticipate renegotiating the terms of our facility in the first quarter of
2005 to ensure that we have a credit facility in place beyond the current
expiry.
If oil and gas prices decrease or exploration efforts are unsuccessful, we may
be required to take additional writedowns.
There is a risk that we will be required to write down the carrying
value of our oil and gas properties. This could occur when oil and gas prices
are low or if we have substantial downward adjustments to our estimated proved
reserves, increases in our estimates of development costs or deterioration in
our exploration results.
We follow the successful efforts accounting method. All property
acquisition costs and costs of exploratory and development wells are capitalized
when incurred, pending the determination of whether proved reserves have been
discovered. If proved reserves are not discovered with an exploratory well, the
costs of drilling the well are expensed. All geological and geophysical costs on
exploratory prospects and the costs of carrying and retaining unproved
properties are expensed as incurred.
The capitalized costs of our oil and gas properties, on a
field-by-field basis, may not exceed the estimated future net cash flows of that
field. If capitalized costs exceed future net revenues, we write down the costs
of each such field to our estimate of fair market value. Unproved properties are
evaluated at the lower of cost or fair market value. This type of charge will
not affect our cash flow from operating activities, but it will reduce the book
value of our stockholders' equity.
We review the carrying value of our properties quarterly based on
prices in effect as of the end of each quarter or as of the time of reporting
our results. Once incurred, a writedown of oil and gas properties is not
reversible at a later date even if oil or gas prices increase. St. Mary incurred
impairment and abandonment charges on proved and unproved properties of $1.9
million, $4.0 million and $2.4 million in 2004, 2003 and 2002, respectively.
Estimates of oil and gas reserves are not precise.
This report and other SEC filings by us contain estimates of our proved
oil and gas reserves and the estimated future net revenues from those reserves.
Actual results will likely vary from amounts estimated, and any significant
negative variance could have a material adverse effect on our future results of
operations.
11
Reserve estimates are based on various assumptions, including
assumptions required by the SEC relating to oil and gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The
process of estimating reserves is complex. This process requires significant
decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. These estimates
are dependent on many variables and therefore changes often occur as these
variables evolve and commodity prices fluctuate. However, the likelihood of
recovery of these reserves is considered more likely than not.
Actual future production, oil and gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and gas reserves will most likely vary from those estimated. Any significant
variance could materially affect the estimated quantities and present value of
reserves disclosed by us. In addition, we may adjust estimates of proved
reserves to reflect production history, results of exploration and development,
prevailing oil and gas prices and other factors, many of which are beyond our
control.
As of December 31, 2004, approximately 15 percent of our estimated
proved reserves were proved undeveloped. Estimation of proved undeveloped
reserves and proved developed non-producing reserves is nearly always based on
volumetric calculations rather than the performance data used to estimate
producing reserves. Recovery of proved undeveloped reserves requires significant
capital expenditures and successful drilling operations. Production revenues
from proved developed non-producing reserves will not be realized until some
time in the future. The reserve data assumes that we will make significant
capital expenditures to develop our reserves. Although we have prepared
estimates of our reserves and the costs associated with these reserves in
accordance with industry standards, these estimated costs may not be accurate,
development may not occur as scheduled and actual results may not occur as
estimated.
You should not construe the present value of future net reserves, or
PV-10, as the current market value of the estimated oil and natural gas reserves
attributable to our properties. Management has based the estimated discounted
future net cash flows from proved reserves on prices and costs as of the date of
the estimate, in accordance with applicable regulations, whereas actual future
prices and costs may be materially higher or lower. For example, values of our
reserves as of December 31, 2004, were estimated using a calculated weighted
average sales price of $43.45 per barrel of oil (NYMEX) and $6.18 per Mcf of gas
(Gulf Coast spot price). During 2004 our monthly average realized gas prices,
excluding the effect of hedging, were as high as $7.27 per Mcf and as low as
$4.90 per Mcf. For the same period our monthly average realized oil prices were
as high as $51.21 per Bbl and as low as $32.26 per Bbl. Many factors will affect
actual future net cash flows, including:
o the amount and timing of actual production,
o supply and demand for oil and natural gas,
o curtailments or increases in consumption by oil and natural
gas purchasers, and
o changes in governmental regulations or taxation.
The timing of the production of oil and natural gas properties and of
the related expenses affects the timing of actual future net cash flows from
proved reserves and thus their actual present value. In addition, the 10 percent
discount factor, which we are required to use to calculate PV-10 for reporting
purposes, is not necessarily the most appropriate discount factor given actual
interest rates and risks to which our business or the oil and natural gas
12
industry in general are subject. As a result, our actual future net cash flows
could be materially different from the estimates included in this report.
Our industry is highly competitive.
Major oil companies, independent producers, and institutional and
individual investors are actively seeking oil and gas properties throughout the
world, along with the equipment, labor and materials required to operate
properties. Shortages for equipment, labor or materials may result in increased
costs or the inability to obtain such resources as needed. Many of our
competitors have financial and technological resources vastly exceeding those
available to us. Many oil and gas properties are sold in a competitive bidding
process in which we may lack technological information or expertise available to
other bidders. We may not be successful in acquiring and developing profitable
properties in the face of this competition.
Exploration and development drilling may not result in commercially productive
reserves.
Oil and gas drilling and production activities are subject to numerous
risks, including the risk that no commercially productive oil or natural gas
will be found. The cost of drilling and completing wells is often uncertain, and
oil and gas drilling and production activities may be shortened, delayed or
canceled as a result of a variety of factors, many of which are beyond our
control. These factors include:
o unexpected drilling conditions;
o pressure or irregularities in formations;
o equipment failures or accidents; and
o shortages or delays in the availability of drilling rigs and
the delivery of equipment.
The prevailing prices of oil and gas also affect the cost of and the
demand for drilling rigs, production equipment and related services. The
availability of drilling rigs can vary significantly from region to region at
any particular time. Although land drilling rigs can be moved from one region to
another in response to changes in levels of demand, an undersupply of rigs in
any region may result in drilling delays and higher drilling costs for the rigs
that are available in that region.
Another significant risk inherent in our drilling plans is the need to
obtain drilling permits from state, local and other governmental authorities.
Delays in obtaining regulatory approvals and drilling permits, including delays
which jeopardize our ability to realize the potential benefits from leased
properties within the applicable lease periods, the failure to obtain a drilling
permit for a well or the receipt of a permit with unreasonable conditions or
costs could have a material adverse effect on our ability to explore on or
develop our properties.
The wells we drill may not be productive and we may not recover all or
any portion of our investment in such wells. The seismic data and other
technologies we use do not allow us to know conclusively prior to drilling a
well that oil or gas is present or may be produced economically. The cost of
drilling, completing and operating a well is often uncertain, and cost factors
can adversely affect the economics of a project. Drilling activities can result
in dry wells or wells that are productive but do not produce sufficient net
revenues after operating and other costs to cover initial drilling costs.
13
Our future drilling activities may not be successful, nor can we be
sure that our overall drilling success rate or our drilling success rate for
activity within a particular area will not decline. Unsuccessful drilling
activities could have a material adverse effect on our results of operations and
financial condition. Also, we may not be able to obtain any options or lease
rights in potential drilling locations that we identify. Although we have
identified numerous potential drilling locations, we may not be able to
economically produce oil or natural gas from all of them.
Our business is subject to operating and environmental risks and hazards that
could result in substantial losses.
Oil and gas operations are subject to many risks, including well
blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
well fluids, fires, formations with abnormal pressures, pipeline ruptures or
spills, pollution, releases of toxic gas and other environmental risks and
hazards. If any of these types of events occurs, we could sustain substantial
losses.
Under certain limited circumstances we may be liable for environmental
damage caused by previous owners or operators of properties that we own, lease
or operate. As a result, we may incur substantial liabilities to third parties
or governmental entities, which could reduce or eliminate funds available for
exploration, development or acquisitions or cause us to incur losses.
We maintain insurance against some, but not all, of these potential
risks and losses. We have limited coverage for sudden environmental damages. We
do not believe that insurance coverage for the full potential liability that
could be caused by sudden environmental damages or insurance coverage for
environmental damage that occurs over time is available at a reasonable cost. In
addition, pollution and environmental risks generally are not fully insurable.
Further, we may elect not to obtain other insurance coverage under circumstances
where we believe that the cost of available insurance is excessive relative to
the risks presented. Accordingly, we may be subject to liability or may lose
substantial portions of certain properties in the event of environmental or
other damages. If a significant accident or other event occurs and is not fully
covered by insurance, it could have a material adverse effect on our financial
condition and results of operations.
Hedging transactions may limit our potential gains and involve other risks.
To manage our exposure to price risks in the marketing of our oil and
natural gas, we enter into commodity price risk management arrangements from
time to time with respect to a portion of our current or future production.
While intended to reduce the effects of volatile oil and natural gas prices,
these transactions may limit our potential gains if oil or natural gas prices
were to rise substantially over the price established by the hedge. In addition,
such transactions may expose us to the risk of financial loss in certain
circumstances, including instances in which:
o our production is less than expected;
o the counterparties to our futures contracts fail to perform
under the contracts; or
o a sudden, unexpected event materially impacts oil or natural
gas prices.
The terms of our hedging agreements may also require that we furnish
cash collateral, letters of credit or other forms of performance assurance in
the event that mark-to-market calculations result in settlement obligations by
us to the counterparties, which would encumber our liquidity and capital
resources.
14
In addition, hedging transactions using derivative instruments involve
basis risk. Basis risk in a hedging contract occurs when the index upon which
the contract is based is more or less variable than the index upon which the
hedged asset is based, thereby making the hedge less effective. For example, a
NYMEX index used for hedging certain volumes of production may have more or less
variability than the regional price index used for the sale of that production.
Our industry is heavily regulated.
Federal, state and local authorities extensively regulate the oil and
gas industry. Legislation and regulations affecting the industry are under
constant review for amendment or expansion, raising the possibility of changes
that may affect, among other things, the pricing or marketing of oil and gas
production. Noncompliance with statutes and regulations may lead to substantial
penalties, and the overall regulatory burden on the industry increases the cost
of doing business and, in turn, decreases profitability. These authorities
regulate various aspects of oil and gas drilling and production activities,
including the drilling of wells (through permit and bonding requirements), the
spacing of wells, the unitization or pooling of oil and gas properties,
environmental matters, safety standards, the sharing of markets, production
limitations, plugging and abandonment, and restoration. To cover the various
obligations of leaseholders in federal waters, federal authorities generally
require that leaseholders have substantial net worth or post bonds or other
acceptable assurances that such obligations will be met. The cost of these bonds
or other surety can be substantial, and we may not be able to obtain bonds or
other surety in all cases. Under limited circumstances, federal authorities may
require any of our operations on federal leases to be suspended or terminated.
Any such suspension or termination could materially adversely affect our
financial condition and results of operations.
We must comply with complex environmental regulations.
Our operations are subject to complex and constantly changing
environmental laws and regulations adopted by federal, state and local
governmental authorities where we are engaged in exploration or production
operations. New laws or regulations, or changes to current requirements, could
have a material adverse effect on our business. We will continue to be subject
to uncertainty associated with new regulatory interpretations and inconsistent
interpretations between state and federal agencies. We could face significant
liabilities to the government and third parties for discharges of oil, natural
gas or other pollutants into the air, soil or water, and we could have to spend
substantial amounts on investigations, litigation and remediation. Existing
environmental laws or regulations, as currently interpreted or enforced, or as
they may be interpreted, enforced or altered in the future, may have a material
adverse effect on our results of operations and financial condition. As a
result, we may face material claims with respect to properties we own or have
owned.
Our business depends on transportation facilities owned by others.
The marketability of our oil and gas production depends in part on the
availability, proximity and capacity of pipeline systems owned by third parties.
The unavailability of or lack of available capacity on these systems and
facilities could result in the shutting-in of producing wells or the delay or
discontinuance of development plans for properties. Although we have some
contractual control over the transportation of our product, material changes in
these business relationships could materially affect our operations. Federal and
state regulation of oil and gas production and transportation, tax and energy
policies, changes in supply and demand, pipeline pressures, damage to or
destruction of pipelines and general economic conditions could adversely affect
our ability to produce, gather and transport oil and natural gas.
15
We depend on key personnel.
Our success will continue to depend on the continued services of our
executive officers and a limited number of other senior management and technical
personnel with extensive experience and expertise in evaluating and analyzing
producing oil and gas properties and drilling prospects, maximizing production
from oil and gas properties and marketing oil and gas production. Loss of the
services of any of these people could have a material adverse effect on our
operations.
Ownership of working interests, royalty interests and other interests by a
director and some of our officers may create conflicts of interest.
As a result of their prior employment with another company with which
St. Mary engaged in a number of transactions, Ronald D. Boone, a director of St.
Mary, and two vice presidents of St. Mary own royalty interests in a number of
St. Mary's properties, which were earned as part of the prior employer's
employee benefit programs. Those persons have no royalty participation in any
St. Mary properties acquired or developed subsequent to the beginning of their
employment with St. Mary.
Mr. Boone also owns 25 percent of Princeton Resources LLC, which owns
the oil and gas working interests that he acquired as a result of his prior
employment. Although Mr. Boone does not manage this entity, he may participate
in any investment decisions made by it.
As a result of these transactions and relationships, conflicts of
interest may exist between these persons and us. Although these persons owe
fiduciary duties to our stockholders and to us, conflicts of interest may not
always be resolved in our favor.
Risks Related to Our Common Stock
The price of our common stock may fluctuate significantly, which may result in
losses for investors.
From January 1, 2003, to February 15, 2005, the last daily sale price
of our common stock reported by the New York Stock Exchange ranged from a low of
$23.83 per share to a high of $49.47 per share. We expect our stock to continue
to be subject to fluctuations as a result of a variety of factors, including
factors beyond our control. These include:
o changes in oil and natural gas prices;
o variations in quarterly drilling, recompletions, acquisitions
and operating results;
o changes in financial estimates by securities analysts;
o changes in market valuations of comparable companies;
o additions or departures of key personnel; and
o future sales of our common stock.
We may fail to meet expectations of our stockholders or of securities
analysts at some time in the future, and our stock price could decline as a
result.
Our certificate of incorporation and bylaws have provisions that discourage
corporate takeovers and could prevent shareholders from realizing a premium on
their investment.
16
Our certificate of incorporation and bylaws contain provisions that may
have the effect of delaying or preventing a change of control. These provisions,
among other things, provide for non-cumulative voting in the election of the
Board of Directors and impose procedural requirements on stockholders who wish
to make nominations for the election of Directors or propose other actions at
stockholders' meetings. These provisions, alone or in combination with each
other and with the rights plan described below, may discourage transactions
involving actual or potential changes of control, including transactions that
otherwise could involve payment of a premium over prevailing market prices to
shareholders for their common stock.
Under our stockholder rights plan, if the Board of Directors determines
that the terms of a potential acquisition do not reflect the long-term value of
St. Mary, the Board of Directors could allow the holder of each outstanding
share of our common stock other than those held by the potential acquirer to
purchase one additional share of our common stock with a market value of twice
the exercise price. This prospective dilution to a potential acquirer would make
the acquisition impracticable unless the terms were improved to the satisfaction
of the Board of Directors. The existence of the plan may impede a takeover not
supported by our board even though such takeover may be desired by a majority of
our stockholders or may involve a premium over the prevailing stock price.
Our shares that are eligible for future sale may have an adverse effect on the
price of our common stock.
At February 15, 2005, we had 28,548,362 shares of common stock
outstanding. Of the shares outstanding, approximately 28,234,000 shares were
freely tradable without substantial restriction or the requirement of future
registration under the Securities Act. Also as of that date, options to purchase
2,756,436 shares of our common stock were outstanding, of which 2,152,871 were
exercisable. These options are exercisable at prices ranging from $9.25 to
$41.74 per share. In addition, restricted stock units providing for the issuance
of up to a total of 227,831 shares of our common stock were outstanding. Sales
of substantial amounts of common stock, or a perception that such sales could
occur, and the existence of options or restricted stock units to issue shares of
common stock at prices that may be below the then-current market price of the
common stock could adversely affect the market price of the common stock and
could impair our ability to raise capital through the sale of our equity
securities.
A director and his extended family may be able to control us.
Thomas E. Congdon, a director and our former Chairman of the Board, and
members of his extended family owned greater than 10 percent of the outstanding
shares of our common stock as of February 15, 2005. While no formal arrangements
exist, these extended family members could be inclined to act in concert with
Mr. Congdon on matters related to control of St. Mary, including for example the
election of Directors or response to an unsolicited bid to acquire St. Mary.
Accordingly, Mr. Congdon and his family may be able to control or influence
matters presented to our Board of Directors and stockholders.
We may not always pay dividends on our common stock.
The payment of future dividends remains in the discretion of the Board
of Directors and will continue to depend on our earnings, capital requirements,
financial condition and other factors. In addition, the payment of dividends is
subject to covenants in our credit facility, including the requirement that we
maintain certain levels of stockholder's equity. The Board of Directors may
determine in the future to reduce the current annual dividend rate of $0.10 per
17
share or discontinue the payment of dividends altogether. Our credit facility
limits the annual dividend rate that we may pay to $0.20 per share.
Cautionary Statement about Forward-Looking Statements
This Annual Report on Form 10-K includes certain statements that may be
deemed to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. All statements, other than statements of historical facts, included in
this Form 10-K that address activities, events or developments that St. Mary's
management expects, believes or anticipates will or may occur in the future are
forward looking statements. Examples of forward-looking statements may include
discussion of such matters as:
o The amount and nature of future capital, development and
exploration expenditures;
o The drilling of wells;
o Reserve estimates and the estimates of both future net
revenues and the present value of future net revenues that are
included in their calculation;
o Future oil and gas production estimates;
o Repayment of debt;
o Business strategies;
o Expansion and growth of operations; and
o Other similar matters such as those discussed in Management's
Discussion and Analysis of Financial Condition and Results of
Operations.
These statements are based on certain assumptions and analyses made by us in
light of our experience and our perception of historical trends, current
conditions, expected future developments and other factors we believe are
appropriate in the circumstances. Such statements are subject to a number of
assumptions, risks and uncertainties, including such factors as the volatility
and level of oil and natural gas prices, uncertainties in cash flow, the
uncertain nature of the expected benefits from the acquisition of oil and gas
properties, production rates and reserve replacement, the imprecise nature of
oil and gas reserve estimates, drilling and operating service availability,
unexpected drilling conditions and results, the risks of various exploration
strategies, competition, the availability of economically attractive exploration
and development and property acquisition opportunities and any necessary
financing, litigation, environmental matters, the potential impact of government
regulations, and other matters discussed under the caption "Risk Factors", many
of which are beyond our control. Readers are cautioned that forward-looking
statements are not guarantees of future performance and that actual results or
developments may differ materially from those expressed or implied in the
forward-looking statements.
Available Information
Our Internet website address is www.stmaryland.com. Through our
------------------
website's financial information section we make available free of charge our
annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K, and amendments to those reports filed with or furnished to the SEC
under applicable securities laws. These materials are made available as soon as
reasonably practical after we electronically file such material with, or furnish
it to, the SEC.
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We also make available through our website's corporate governance
section our corporate governance guidelines, code of business conduct and
ethics, and the charters for our Board of Directors' audit committee,
compensation committee, executive committee and nominating and corporate
governance committee. These documents are also available in print to any
stockholder who requests them. Requests for these documents may be submitted to:
St. Mary Land & Exploration Company
Investor Relations
1776 Lincoln Street, Suite 700
Denver, Colorado 80203
Telephone: (303) 863-4322
Information on our website is not incorporated by reference into this
Annual Report on Form 10-K and should not be considered part of this document.
Glossary
The terms defined in this section are used throughout this Annual
Report on Form 10-K.
2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
two-dimensional cross-section of the subsurface.
3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet, used herein in reference to natural gas.
BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
Behind pipe reserves. Estimated net proved reserves in a formation in which
production casing has already been set in the wellbore but has not been
perforated and production tested.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
of six Mcf of gas (including gas liquids) to one Bbl of oil.
Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.
Dry hole. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
Estimated net proved reserves. The estimated quantities of oil, gas and gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Exploratory well. A well drilled to find and produce oil or gas in an unproved
area, to find a new reservoir in a field previously found to be productive of
oil or gas in another reservoir or to extend a known reservoir beyond its known
horizon.
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Fee land. The most extensive interest that can be owned in land, including
surface and mineral (including oil and gas) rights.
Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated
by dividing the amount of total capital expenditures for oil and gas activities,
including the effect of asset retirement obligations, by the amount of estimated
net proved reserves added through revisions of previous estimates, discoveries
and purchases during the same period. The information for this calculation will
be found in the disclosures about oil and gas producing activities in Item 15 of
Part IV of this report.
Gross acres. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Hydraulic fracturing. A procedure to stimulate production by forcing a mixture
of fluid and proppant (usually sand) into the formation under high pressure.
This creates artificial fractures in the reservoir rock, which increases
permeability and porosity.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
MMBOE. One million barrels of oil equivalent.
Mcf. One thousand cubic feet.
MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined
using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMcf. One million cubic feet.
MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined
using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMBtu. One million British Thermal Units. A British Thermal Unit is the amount
of heat required to raise the temperature of a one-pound mass of water by one
degree Fahrenheit.
Net acres or net wells. The sum of our fractional working interests owned in
gross acres or gross wells.
Net asset value per share. The result of the fair market value of total assets
less total liabilities, divided by the total number of outstanding shares of
common stock.
PV-10 value. The present value of estimated future gross revenue to be generated
from the production of estimated net proved reserves, net of estimated
production and future development costs, using prices and costs in effect as of
the date indicated (unless such prices or costs are subject to change pursuant
to contractual provisions), without giving effect to non-property related
expenses such as general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10 percent.
Productive well. A well that is producing oil or gas or that is capable of
production.
20
Proved developed reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods.
Proved undeveloped reserves. Reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.
Recompletion. The completion for production from an existing wellbore in another
formation other than that in which the well has previously been completed.
Reserve life. Expressed in years, represents the estimated net proved reserves
at a specified date divided by forecasted production for the preceding 12-month
period.
Reserve replacement percentage. The sum of reserve extensions and discoveries,
reserve acquisition, and reserve revisions of previous estimates for a specified
period of time divided by production for that same period of time.
Royalty. The share paid to the owner of mineral rights expressed as a percentage
of gross income from oil and gas produced and sold unencumbered by expenses
relating to the drilling, completing and operating of the affected well.
Royalty interest. An interest in an oil and gas property entitling the owner to
shares of oil and gas production free of costs of exploration, development and
production.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas, regardless of whether such acreage contains estimated net proved
reserves.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and to share in
the production.
21
ITEM 2. PROPERTIES
Operations
St. Mary's exploration, development and acquisition activities are
focused in five core operating areas: the Rocky Mountain region; the
Mid-Continent region; the ArkLaTex region; the Gulf Coast region; and the
Permian Basin region. Information concerning each of our major areas of
operations, and summary of our estimated proved reserves as of December 31,
2004, is shown below.
Estimated Proved Reserves
---------------------------------------------------------
Oil Gas MMCFE PV-10 Value
------------------ ----------------------
(MBbl) (MMcf) Amount Percent (In thousands) Percent
------- ------- --------- -------- -------------- -------
Rocky Mountain 46,762 75,335 355,907 54% $ 748,916 50%
Mid-Continent 1,024 129,536 135,678 21% 335,028 22%
ArkLaTex 1,438 66,931 75,558 12% 173,190 12%
Gulf Coast 388 31,170 33,498 5% 120,591 8%
Permian Basin 6,962 6,754 48,527 7% 109,710 7%
Coalbed Methane - 9,470 9,470 1% 13,688 1%
------- ------- --------- -------- -------------- -------
Total 56,574 319,196 658,638 100% $ 1,501,123 100%
======= ======= ========= ======== ============== =======
Rocky Mountain Region. Nance Petroleum Corporation, a wholly owned
subsidiary of St. Mary, has conducted operations in the Williston Basin in
eastern Montana and western North Dakota since 1991. We have expanded this area
into the Green River, Powder River, Big Horn and Wind River basins over the past
three years. In November 2004, we acquired the stock of Goldmark Engineering,
Inc. along with oil and gas properties from various Goldmark partners for $23.3
million of cash. The allocation of the purchase price for the net assets
acquired was $29.4 million of proved reserves and unproved acreage, $1.2 million
of cash, $753,000 of other assets, $446,000 of payables, a $2.8 million asset
retirement liability, and a $4.8 million deferred tax liability. The Goldmark
acquisition added approximately 31.9 BCFE of proved reserves as of the
acquisition date.
Conventional oil and gas reserves in the Rocky Mountain region
accounted for 54 percent of our estimated proved reserves as of December 31,
2004, or 356 BCFE, 87 percent of which were proved developed and 79 percent of
which were oil.
Our office in Billings, Montana includes a 75-person staff. A
significant portion of the exploration and development in the Rocky Mountain
region is based on the interpretation of 3-D seismic data. We have successfully
used 3-D seismic imaging to delineate structure and porosity development in the
Red River formation as well as the Middle Bakken horizontal dolomite play.
St. Mary spent $108.5 million on exploration, development and
acquisitions in the Rocky Mountain region in 2004.
Our capital budget for the Rocky Mountain region now represents the
largest portion of our drilling budget at approximately $121 million in 2005.
This increase is a result of the increased development of the Middle Bakken
formation, increased drilling associated with the Red River play, and a full
year development plan for our Hanging Woman Basin coalbed methane project. We
have approximately 150 wells planned and a risked budget of $24 million at
Hanging Woman. The Bakken play, which has been primarily in Richland County,
Montana, is now expanding to McKenzie and Billings Counties in North Dakota. We
plan on drilling 30 wells in the Bakken during 2005 for total risked capital of
22
$30 million. The Red River formation continues to be a major portion of the
budget with nine wells planned for $13 million. Our growth in Wyoming has
resulted in an allocated capital budget of $26 million for participation in 69
gross wells in the Fourbear, Monument Lake, Red Lakes and Standard Draw fields.
In the Rocky Mountain region, we have a working interest greater than 90 percent
in 322 wells. Including the development of Hanging Woman Basin, we will be the
operator of properties representing approximately 83 percent of our 2005 Rocky
Mountain region capital budget.
The concentration of our value in the Rockies is at the East Putnam
field in Richland County, Montana, and at the Rough Rider field in McKenzie
County, North Dakota. Each of these fields represents two percent of total
proved reserves and two percent of our PV-10 value. There are nine and 41 gross
wells producing in these two fields, respectively, with our working interest
varying from six to 100 percent. Following these fields, the other most
significant fields are the Brush Lake, South Fork and Ridgelawn areas. Combined,
these three fields represent five percent of our total reserves and PV10 value.
As of the end of 2004, the Hanging Woman Basin coalbed methane project
had 8 BCFE of proved reserves representing one percent of our total proved
reserves. We are in the early development stage. First production from the field
began in mid-December 2004. We do not expect production from Hanging Woman to
account for a material portion of total 2005 production volumes. Because of the
dewatering time and the low production rates per well, it will take two to three
years to develop the field to the point of having production volumes that are
meaningful to our total production.
Mid-Continent Region. St. Mary has been active in the Mid-Continent
region since 1973. Operations for the region are managed by our 42-person office
in Tulsa, Oklahoma. Our long history of operations and proprietary geologic
knowledge enables us to sustain economic development and exploration programs
despite periods of adverse industry conditions. We apply current technology in
hydraulic fracturing and innovative well completion techniques to accelerate
production and associated cash flow from the region's tight gas reservoirs. We
also attempt to benefit from the continuing consolidation of operators in the
basin as we pursue attractive opportunities to acquire properties.
We have ongoing exploration and development programs in the Anadarko
and Arkoma basins of Arkansas, Oklahoma and Texas. The Mid-Continent region
accounts for 21 percent of our estimated proved reserves as of December 31,
2004, or 136 BCFE, 88 percent of which were proved developed and 95 percent of
which were natural gas. In 2004 our capital expenditures in the Mid-Continent
were $104.0 million. We participated in drilling 108 gross wells in this region
in 2004, 91 percent of which were completed as producers. We operated 36 of
these drilling projects.
St. Mary's development and exploration budget in the Mid-Continent
region for 2005 totals $87 million, down from $96 million in 2004. Included in
the 2005 budget is $3 million of drilling associated with the Agate acquisition.
The decrease in the budget is intended to focus investment in drilling with a
higher potential of return. We plan to be the operator of properties
representing approximately 80 percent of our capital budget in this region
during 2005 and to utilize three to five drilling rigs throughout the year.
Approximately 23 percent of our 2005 Mid-Continent capital budget is
allocated to deeper, higher-potential wells in the Morrow/Springer formations,
and 25 percent is allocated to the Atoka formations at the Northeast Mayfield
field in Beckham County, Oklahoma on the southern edge of the Anadarko Basin. We
have allocated 48 percent of the drilling activities budget for
low-to-medium-risk development in the Granite Wash, Osborne, Cottage Grove,
Cromwell / Wapanucka, Woodford and Spiro formations. With our recently completed
23
acquisition of Agate Petroleum, Inc., we have allocated 4 percent of our
drilling budget to development of the Hartshorne formation.
The Northeast Mayfield area is the largest concentration of our
reserves in the Mid-Continent. This field represents approximately 32 BCFE or
five percent of our proved reserves and $82.7 million, or approximately 6
percent of our total PV-10 value. Our average working interest in this field is
24 percent, and we have an interest in approximately 73 gross wells of which we
operate 42 percent.
Other significant fields in the Mid-Continent region are the Centrahoma
field located in Coal County, Oklahoma, in the Arkoma Basin and the Constitution
field in Jefferson County, Texas. Centrahoma represents three percent of total
proved reserves and $37.1 million or two percent of total PV-10 value, and the
Constitution field represents one percent of total proved reserves and $28
million of PV-10 value. We operate 85 percent of the Centrahoma field but none
of the 7 gross wells in Constitution field. The other most significant field in
the Mid-Continent region is the Elk City field in Beckham County, Oklahoma,
representing two percent of proved reserves and two percent of total PV10 value.
We operate 18 percent of the wells in Elk City and have an average working
interest of approximately 13 percent.
ArkLaTex Region. Our 18-person office in Shreveport, Louisiana, manages
St. Mary's operations in the ArkLaTex region. The ArkLaTex region accounts for
12 percent of our estimated proved reserves as of December 31, 2004, or 76 BCFE;
83 percent of which were proved developed and 89 percent were natural gas. We
also own rights to over 6,000 square miles of proprietary 2-D seismic data in
the region. Many of the Shreveport office's successful exploration and
development programs have derived from niche acquisitions. These acquisitions
have provided access to strategic holdings of undeveloped acreage and
proprietary packages of geologic and seismic data resulting in an active program
of additional development and exploration. We believe the recent acquisition of
non-operated producing working interests in the Elm Grove field, consisting of
14.5 BCFE and $34 million of PV-10 value, will provide us a foothold to grow our
interest in this area.
Our holdings in the ArkLaTex region are comprised of interests in
approximately 538 producing gross wells, including 101 wells operated by us;
interests in leases totaling approximately 149,000 gross acres; and mineral
servitudes totaling approximately 14,300 gross acres. Our capital expenditures
in this region in 2004 were $67.3 million, including $37.6 million for
acquisitions. Following our ownership in the Elm Grove field, the next most
significant concentration of properties is the Box Church field, which includes
16 BCFE of proved reserves and working interests in 33 gross wells, all of which
we operate.
In 2005 we will grow our drilling capital budget in the ArkLaTex to $34
million. These capital dollars are budgeted for horizontal wells in the James
and Pettet Limestones and other tight sands plays and development of the Elm
Grove and Travis Peak / Cotton Valley plays in East Texas. The budget reflects
us as operator for 46 percent of estimated expenditures.
Gulf Coast Region. St. Mary's presence in south Louisiana dates to the
early 1900's when our founders acquired a franchise property in St. Mary Parish
on the shoreline of the Gulf of Mexico. These 24,914 acres of fee lands yielded
$5.5 million of gross oil and gas royalty revenue in 2004. Our Gulf Coast region
presence increased significantly in 1999 with the acquisition of King Ranch
Energy, Inc. Including the Louisiana fee lands, the Gulf Coast region accounts
for five percent of our estimated proved reserves as of December 31, 2004, or 33
BCFE, 93 percent of which were proved developed and 31 BCFE were natural gas.
24
Our 18-person team based in Houston, Texas manages St. Mary's diverse
activities in our Gulf Coast and Permian Basin regions. Our exploration and
development budget in the Gulf Coast region for 2005 is $41 million which
consists of activity both onshore and offshore in Texas and Louisiana. We will
operate properties representing approximately 33 percent of this amount.
The most significant field in the Gulf Coast region is the Judge Digby
Field, located outside Baton Rouge, Louisiana, in Point Coupee Parish. As of the
end of December 2004, this field represented slightly less than three percent of
our total PV-10 value with 13.5 BCFE of proved reserves. Production from the
Judge Digby field totaled 3.6 BCFE in 2004.
Permian Basin Region. The Permian Basin area covers a significant
portion of eastern New Mexico and western Texas and is one of the major
producing basins in the United States. The basin includes hundreds of oil fields
undergoing secondary and enhanced oil recovery projects. The use of 3-D seismic
imaging of existing fields and advanced secondary recovery programs are
substantially increasing oil recoveries in this Basin. Our holdings in the
Permian Basin resulted from a series of property acquisitions since 1995. We
believe that our Permian Basin operations provide us with a solid base of
long-lived oil reserves, promising longer-term exploration and development
prospects and the potential for additional secondary recovery projects. The
Permian Basin region accounted for 49 BCFE, or 7 percent of our estimated proved
reserves as of December 31, 2004. The Permian reserves are 63 percent proved
developed and 86 percent are oil.
The Parkway Delaware waterflood project, located in Eddy County, New
Mexico, represents 19 BCFE or three percent of our proved reserves. The East
Shugart Delaware Unit is a pilot waterflood located in Lea and Eddy Counties,
New Mexico that is analogous to the Parkway Delaware Unit and is comprised of 16
BCFE of total proved reserves. Production from the Permian Basin properties
represented 3.1 BCFE or 4 percent of the total production for the Company in
2004.
Our Permian Basin capital budget for 2005 is $10 million of which we
anticipate spending 79 percent on properties we operate. We plan to drill 11
infill wells at Parkway Delaware and eight wells at East Shugart. Our capital
budget also has seven recompletion projects scheduled at Parkway Delaware. East
Shugart is still in a pilot phase and is moving into full development of the
flood in 2005.
Acquisitions and Divestitures
We spent a total of $76.7 million on acquisitions of proved and
unproved oil and gas properties in 2004. The two most significant acquisitions
were the Goldmark and Border Company acquisitions. On November 1, 2004, we
acquired the stock of Goldmark Engineering, Inc. and proved and unproved oil and
gas properties from various Goldmark partners for $23.3 million of cash. The oil
and gas properties in the Goldmark acquisition are located primarily in the
Fourbear field in the Big Horn Basin of Wyoming. On December 15, 2004, we
acquired proved and unproved oil and gas properties from Border Company in and
around the Elm Grove field located in Louisiana for $37.8 million of cash. We
made various other smaller acquisitions in 2004 as well. In the aggregate, we
purchased 52 BCFE of proved reserves in 2004.
Significant acquisitions prior to 2004 include the acquisitions of oil
and gas properties in the Rocky Mountain region from Flying J Oil & Gas Inc.
in January 2003 and from Burlington Resources in December 2002.
25
Reserves
The following table presents summary information with respect to the
estimates of our proved oil and gas reserves for each of the years in the
three-year period ended December 31, 2004, as prepared by both Ryder Scott
Company and Netherland, Sewell & Associates, Inc., both of which are
independent petroleum engineering firms, and us. For the periods presented,
Ryder Scott Company evaluated properties representing a minimum of 80 percent of
the total PV-10 value of our conventional reserves, and we evaluated the
remainder. The proved oil and gas reserves prepared by Netherland Sewell in 2004
consist of the coalbed methane developments at Hanging Woman Basin and Atlantic
Rim. As of December 31, 2004, the PV-10 of proved reserves, prepared by
Netherland Sewell, was less than one percent of our total PV-10 reserve value.
The PV-10 values shown in the following table are not intended to represent the
current market value of the estimated proved oil and gas reserves owned by St.
Mary. Neither prices nor costs have been escalated. You should read the
following table along with the section entitled "Risk Factors - Risks Related to
Our Business - Estimates of oil and gas reserves are not precise."
As of December 31,
----------------------------------------------
Proved Reserves Data: 2004 2003 2002
- ----------------------------------------- ------------- --------------- ----------------
Oil (MBbl) 56,574 47,787 36,119
Gas (MMcf) 319,196 307,024 274,172
MMCFE 658,638 593,744 490,887
PV-10 value, without tax effect (in
thousands) (1) $ 1,501,123 $ 1,278,165 $ 824,808
Standardized measure of discounted
future net cash flows (in thousands) $ 1,033,938 $ 859,956 $ 581,862
Proved developed reserves 85% 89% 88%
Reserve replacement 190% 293% 306%
Reserve life (years) (2) 8.7 7.7 8.9
- ----------------
(1) PV-10 value as of December 31, 2004, was calculated using the
weighted-average sales price of $40.06 per barrel of oil and $5.80 per
Mcf of gas. These prices are based on NYMEX prices for oil and a Gulf
Coast spot price for gas in effect on December 31, 2004, and are then
adjusted for transportation, quality and basis differentials.
(2) Reserve life represents the estimated proved reserves at the dates
indicated divided by actual production for the preceding 12-month
period.
26
Production
The following table summarizes the average volumes of oil and gas
produced from properties in which St. Mary held an interest during the periods
indicated:
Years Ended December 31,
-----------------------------------------------------
2004 2003 2002
---------------- ---------------- ----------------
Operating data:
Net production:
Oil (MBbl) 4,799 4,541 2,815
Gas (MMcf) 46,598 49,663 38,164
MMCFE 75,393 76,909 55,055
Average net daily production:
Oil (Bbl) 13,113 12,441 7,713
Gas (Mcf) 127,316 136,062 104,558
MCFE 205,992 210,709 150,836
Average realized sales price (1):
Oil (per Bbl) $ 32.53 $ 26.96 $ 25.34
Gas (per Mcf) $ 5.52 $ 4.89 $ 3.00
Per MCFE $ 5.48 $ 4.75 $ 3.37
Additional per MCFE data:
Lease operating expense $ 0.81 $ 0.77 $ 0.66
Transportation costs $ 0.10 $ 0.09 $ 0.06
Production taxes $ 0.36 $ 0.29 $ 0.20
General and administrative $ 0.29 $ 0.28 $ 0.25
Depreciation, depletion, amortization
and liability accretion $ 1.22 $ 1.07 $ 0.99
- ----------------
(1) Includes the effects of St. Mary's hedging activities. See
"Management's Discussion and Analysis of Financial Condition and
Results of Operations."
Productive Wells
As of December 31, 2004, we had working interests in 1,613 gross (727
net) productive oil wells and 2,068 gross (479 net) productive gas wells.
Productive wells are either producing wells or wells capable of commercial
production although currently shut in. One or more completions in the same
wellbore are counted as one well. A well is categorized under state reporting
regulations as an oil well or a gas well based upon the ratio of gas to oil
produced when it first commenced production, and such designation may not be
indicative of current production.
27
Drilling Activity
All of our drilling activities are conducted on a contract basis with
independent drilling contractors. We do not own any drilling equipment. The
following table sets forth the wells drilled and recompleted in which St. Mary
participated during each of the three years indicated:
Years Ended December 31,
------------------------------------------------------------------------------------
2004 2003 2002
--------------------------- --------------------------- --------------------------
Gross Net Gross Net Gross Net
------------- ------------ ------------ ------------- ----------- -------------
Development:
Oil 50 18.08 36 14.88 26 11.52
Gas 180 53.23 140 43.79 103 38.89
Non-productive 36 14.29 37 15.98 27 14.42
------------- ------------ ------------ ------------- ----------- -------------
266 85.60 213 74.65 156 64.83
------------- ------------ ------------ ------------- ----------- -------------
Exploratory:
Oil 11 9.71 7 3.03 3 1.22
Gas 83 43.65 14 7.20 1 0.10
Non-productive 8 2.84 7 4.40 8 2.64
------------- ------------ ------------ ------------- ----------- -------------
102 56.20 28 14.63 12 3.96
------------- ------------ ------------ ------------- ----------- -------------
Farmout or non-consent 5 - 10 - 8 -
------------- ------------ ------------ ------------- ----------- -------------
Total (1) 373 141.80 251 89.28 176 68.79
============= ============ ============ ============= =========== =============
- ----------------
(1) Does not include seven, 15 and 14 gross wells completed on St. Mary's fee
lands during 2004, 2003 and 2002, respectively, in which we have only a
royalty interest.
28
Acreage
The following table sets forth the gross and net acres of developed and
undeveloped oil and gas leases, fee properties, mineral servitudes and lease
options held by St. Mary as of December 31, 2004. Undeveloped acreage includes
leasehold interests that may already have been classified as containing proved
undeveloped reserves.
Developed Acres (1) Undeveloped Acres (2) Total
------------------------ -------------------------- ----------------------------
Gross Net Gross Net Gross Net
---------- ---------- ------------ ---------- ------------ ------------
Arkansas 3,364 421 207 68 3,571 489
Colorado 2,845 2,206 24,712 13,357 27,557 15,563
Louisiana 132,153 40,675 23,105 8,841 155,258 49,516
Mississippi 2,588 262 4,049 2,077 6,637 2,339
Montana 53,549 33,879 452,638 300,103 506,187 333,982
New Mexico 6,280 2,694 1,320 1,187 7,600 3,881
North Dakota 131,362 86,441 160,753 98,504 292,115 184,945
Oklahoma 245,197 68,602 37,751 23,130 282,948 91,732
Texas 131,150 33,892 39,464 15,400 170,614 49,292
Utah (3) 480 115 13,712 5,866 14,192 5,981
Wyoming 73,993 45,036 422,231 252,694 496,224 297,730
Other (4) 2,761 903 4,144 1,169 6,905 2,072
---------- ---------- ------------ ---------- ------------ ------------
785,722 315,126 1,184,086 722,396 1,969,808 1,037,522
---------- ---------- ------------ ---------- ------------ ------------
Louisiana Fee Properties 9,944 9,944 14,970 14,970 24,914 24,914
Louisiana Mineral Servitudes 9,745 5,306 4,571 4,208 14,316 9,514
---------- ---------- ------------ ---------- ------------ ------------
19,689 15,250 19,541 19,178 39,230 34,428
---------- ---------- ------------ ---------- ------------ ------------
Total 805,411 330,376 1,203,627 741,574 2,009,038 1,071,950
========== ========== ============ ========== ============ ============
- ----------------
(1) Developed acreage is acreage assigned to producing wells for the
spacing unit of the producing formation. Developed acreage in certain of
St. Mary's properties that include multiple formations with different well
spacing requirements may be considered undeveloped for certain formations,
but have only been included as developed acreage in the presentation above.
(2) Undeveloped acreage is lease acreage on which wells have not been
drilled or completed to a point that would permit the production of
commercial quantities of oil and gas regardless of whether such acreage
contains estimated proved reserves.
(3) St. Mary holds an overriding royalty interest in an additional 40,100
gross acres in Utah.
(4) Includes interests in Alabama, Kansas, Nebraska,
Nevada and South Dakota.
29
ITEM 3. LEGAL PROCEEDINGS
From time to time, we may be involved in litigation relating to claims
arising out of our operations in the normal course of business. As of the date
of this report, no legal proceedings are pending against us that we believe
individually or collectively could have a material adverse effect upon our
financial condition or results of operations.
As previously reported, Nance Petroleum Corporation, a wholly owned
subsidiary, is named along with several other leaseholders and interested
parties as an additional co-defendant in a lawsuit that was originally filed in
the U.S. District Court for the District of Montana on June 12, 2001. The
plaintiff, the Northern Plains Resource Council, Inc.("NPRC"), an environmental
public interest group, sued the U.S. Bureau of Land Management, the U.S.
Secretary of the Interior, the Montana BLM State Director and Fidelity
Exploration & Production Company. The lawsuit seeks the cancellation of all
federal leases related to coalbed methane development in Montana issued by the
BLM since January 1, 1997. This cancellation is sought primarily on the grounds
of an alleged failure of the BLM to comply with federal environmental laws. NPRC
alleges that the environmental impacts of coalbed methane development were not
properly analyzed before the challenged leases were issued. The Montana portion
of our Hanging Woman Basin coalbed methane project contains approximately 74,000
total net acres. The lawsuit potentially affects approximately 47,000 net acres
that are subject to federal leases. Based on information presently available, we
believe that the BLM complied with the applicable environmental laws, and the
District Court agreed by granting the defendants' motion for summary judgment in
December 2003. The court held that the issuance process regarding the federal
leases in question complied with the applicable environmental laws. The
plaintiff appealed this decision, and the Ninth Circuit Court of Appeals
affirmed the decision of the trial court on August 26, 2004. Plaintiff has filed
a petition for rehearing that was denied by the reviewing panel by its Order
dated February 10, 2005. The only appeal left for the Plaintiffs is to petition
for certiori to the U.S Supreme Court. Notwithstanding our success in the lower
court and the appellate court, there is no assurance as to the ultimate outcome
of the lawsuit, and therefore, there is no assurance that it will not adversely
affect our coalbed methane project. Even if the federal leases in Montana become
unavailable, we are proceeding with this project on non-federal leases in
Wyoming, and we anticipate acquiring additional non-federal leases in Montana
and Wyoming.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of our security holders
during the fourth quarter of 2004.
30
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth the names, ages and positions held by
St. Mary's executive officers.
Name Age Position
- ---- --- --------
Mark A. Hellerstein 52 Chairman of the Board, President and Chief
Executive Officer
Douglas W. York 43 Executive Vice President and Chief Operating
Officer
Robert L. Nance 68 Senior Vice President, and President and Chief
Executive Officer of Nance Petroleum Corporation,
a wholly-owned subsidiary of St. Mary
Jerry R. Schuyler 49 Senior Vice President and Regional Manager
Kevin E. Willson 48 Senior Vice President - Mid-Continent Drilling and
Production
Robert T. Hanley 58 Vice President - Investor Relations and Management
Reporting
David W. Honeyfield 38 Vice President - Finance, Treasurer and Secretary
Milam Randolph Pharo 52 Vice President - Land and Legal
Garry A. Wilkening 54 Vice President - Administration and Controller
Each executive officer has held his respective position during the past
five years, except as follows:
Mark A. Hellerstein was appointed Chairman of the Board in September
2002.
Douglas W. York was appointed Executive Vice President and Chief
Operating Officer in September 2003. Mr. York served as Vice-President -
Acquisitions and Reservoir Engineering from 1996 to September 2003.
Robert L. Nance was appointed Senior Vice President in March 2001.
Jerry R. Schuyler joined St. Mary in December 2003 as Senior Vice
President and Regional Manager of the Gulf Coast region. From November 2001 to
July 2002, Mr. Schuyler was Senior Vice President and General Manager - Eastern
Onshore Division for Dominion Exploration & Production, Inc., where he
managed all operations and exploration for Dominion's Gulf Coast and eastern
onshore U.S. regions. From March 2000 to November 2001, Mr. Schuyler was Senior
Vice President and General Manager of Dominion's Onshore U.S. Division, where he
managed all operations and exploration for all of Dominion's onshore U.S.
regions. From 1996 to 2000, Mr. Schuyler was President and Managing Director,
ARCO Middle East & Central Asia, where he managed all operations for ARCO
International Oil & Gas Company in the Arabian Peninsula, Turkey and
Pakistan.
Kevin E. Willson was appointed Senior Vice President and Regional
Manager in November 2003. Mr. Willson served as Vice President - Mid-Continent
Exploration/Production from October 1998 to November 2003. Mr. Willson joined
Anderman/Smith, a predecessor to St. Mary's interests in the Mid-Continent
region, in 1990 and was appointed Vice President - Mid-Continent Engineering for
St. Mary in 1996.
Robert T. Hanley was appointed Vice President - Investor Relations and
Management Reporting in April 2003. Mr. Hanley served as Vice President -
Business Development from July 2000 to April 2003. Mr. Hanley was Chief
Financial Officer of Nance Petroleum Corporation from 1999 to 2000 and Chief
Financial Officer of Panterra Petroleum, a partnership between St. Mary and
Nance Petroleum Corporation, from 1992 to 1999.
31
David W. Honeyfield joined St. Mary in May 2003 as Vice President -
Finance, Treasurer and Secretary. Prior to joining St. Mary, Mr. Honeyfield was
Controller and Chief Accounting Officer of Cimarex Energy Co. from September
2002 to May 2003 and Controller and Chief Accounting Officer of Key Production
Company, Inc., which was acquired by Cimarex in September 2002. Prior to joining
Key Production Company in April 2002, Mr. Honeyfield was a senior audit manager
with Arthur Andersen LLP in Denver. Mr. Honeyfield had been with Arthur Andersen
since January 1991.
Garry A. Wilkening was appointed Vice President - Administration in
February 1999.
The executive officers of the Company serve at the pleasure of the
Board of Directors and do not have fixed terms. Executive officers generally are
elected at the regular meeting of the Board immediately following the annual
stockholders meeting. Any officer or agent elected or appointed by the Board may
be removed by the Board whenever in its judgment the best interests of the
Company will be served thereby without prejudice, subject however, to
contractual rights, if any, of the person so removed. Mr. Hellerstein is
chairman of the Board of Directors and has an employment agreement with St.
Mary. The agreement is terminable at any time upon 30 days' notice by either
party. Upon termination of the agreement by St. Mary for any reason other than
death, disability or misconduct by Mr. Hellerstein, St. Mary is obligated to
continue to pay his compensation and insurance benefits, at the level at the
time of termination, for a period of one year.
There are no family relationships, first cousin or closer, between any
executive officer and director. There are no arrangements or understandings
between any officer and any other person pursuant to which that officer was
elected.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITYAND RELATED STOCKHOLDER MATTERS
Market Information. St. Mary's common stock is currently traded on the
New York Stock Exchange under the symbol SM. The range of high and low sales
prices for the quarterly periods in 2004 and 2003, as reported by the New York
Stock Exchange, is set forth below:
Quarter Ended High Low
- ------------------------------- ----------------- -----------------
December 31, 2004 $ 43.00 $ 37.12
September 30, 2004 40.13 31.76
June 30, 2004 37.19 31.80
March 31, 2004 34.14 27.74
December 31, 2003 $ 29.19 $ 24.45
September 30, 2003 28.85 24.45
June 30, 2003 29.75 24.65
March 31, 2003 27.23 23.80
Holders. As of February 15, 2005, the number of record holders of St.
Mary's common stock was 145. Management believes, after inquiry, that the number
of beneficial owners of our common stock is in excess of 3,800.
Dividends. St. Mary has paid cash dividends to stockholders every year
since 1940. Annual dividends of $0.10 per share were paid in each of the years
1998 through 2004. We expect that our practice of paying dividends on our common
stock will continue, although the payment of future dividends on our common
32
stock will continue to depend on our earnings, capital requirements, financial
condition and other factors. In addition, the payment of dividends is subject to
covenants in our credit facility, including the requirement that we maintain
certain levels of stockholders' equity and the limitation of our annual dividend
rate to no more than $0.20 per share. Dividends are currently paid on a
semi-annual basis. Dividends paid totaled $2.8 million in 2004 and $3.1 million
in 2003.
Restricted Shares. Aside from Rule 144 restrictions on shares for
insiders and restricted shares issued under the Employee Stock Purchase Plan and
the Non-Employee Director Stock Compensation Plan, St. Mary has no restricted
shares outstanding as of December 31, 2004.
Issuer Purchases of Equity Securities. St. Mary did not repurchase any
shares of its common stock during the fourth quarter of 2004.
Equity Compensation Plans. St. Mary has a stock option plan, a
restricted stock plan, an incentive stock option plan, an employee stock
purchase plan, a non-employee director stock compensation plan under which
options and shares of St. Mary common stock are authorized for grant or issuance
as compensation to eligible employees, consultants and members of the Board of
Directors. Our stockholders have approved each of these plans. See Note 7 -
Compensation Plans in the Notes to Consolidated Financial Statements included in
Part IV, Item 15 of this report for further information about the material terms
of these plans. The following table is a summary of the shares of common stock
authorized for issuance under our equity compensation plans as of December 31,
2004:
( a ) ( b ) ( c )
Number of securities
Number of securities remaining available for
to be issued upon Weighted-average future issuance under
exercise of exercise price of quity compensation plans
outstanding options, outstanding options, (excluding securities
warrants and rights warrants and rights ereflected in column (a))
Plan Category
- ----------------------------------------------------------- ---------------------- ----------------------------
Equity compensation plans approved
by security holders 3,053,506 $ 22.32 1,471,349 (1)
Equity compensation plans not
approved by security holders - - -
----------------------- ---------------------- ----------------------------
Total 3,053,506 $ 22.32 1,471,349
======================= ====================== ============================
- --------------
(1) Includes shares that are authorized for issuance under our employee
stock purchase plan.
33
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth supplemental selected financial and
operating data for St. Mary as of the dates and for the periods indicated. The
financial data for each of the five years presented were derived from the
consolidated financial statements of St. Mary. The following data should be read
in conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations," which includes a discussion of factors materially
affecting the comparability of the information presented, and in conjunction
with St. Mary's consolidated financial statements included elsewhere in this
report.
Years Ended December 31,
-------------------------------------------------------------------------
2004 2003 2002 2001 2000
--------------- -------------- ------------- -------------- -------------
(In thousands, except per share data)
Total operating revenues $ 433,099 $ 393,708 $ 196,305 $ 207,469 $ 195,666
Income before cumulative effect of
change in accounting principle $ 92,479 $ 90,140 $ 27,560 $ 40,459 $ 55,620
Net income per share:
Basic $ 3.21 $ 3.06 $ 0.99 $ 1.45 $ 2.00
Diluted $ 2.88 $ 2.80 $ 0.97 $ 1.42 $ 1.97
Total Assets $ 945,460 $ 735,854 $ 537,139 $ 436,989 $ 321,895
Long-term obligations:
Line of credit $ 37,000 $ 11,000 $ 14,000 $ 64,000 $ 22,000
Convertible Notes $ 99,791 $ 99,696 $ 99,601 - -
Cash dividends declared per common share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.10
34
Supplemental Selected Financial and Operational Data:
Years Ended December 31,
--------------------------------------------------------------------------
2004 2003 2002 2001 2000
---------------- -------------- ------------- ------------- --------------
(In thousands, except per volume data)
Balance Sheet Data:
Total working capital $ 12,035 $ 3,101 $ 2,050 $ 34,000 $ 40,639
Total stockholders' equity $ 484,455 $ 390,653 $ 299,513 $ 286,117 $ 250,136
Weighted-average shares outstanding:
Basic 28,851 31,233 27,856 27,973 27,781
Diluted 33,447 35,534 28,391 28,555 28,271
Reserves:
Gas (Mcf) 319,196 307,024 274,172 241,231 225,975
Oil (Bbls) 56,574 47,787 36,119 23,669 20,950
MCFE 658,638 593,744 490,887 383,247 351,673
Production and Operational: Data:
Oil and gas production revenues,
including hedging $ 413,318 $ 365,114 $ 185,670 $ 203,973 $ 188,407
LOE and production taxes $ 95,518 $ 88,509 $ 50,839 $ 55,000 $ 38,461
DD&A $ 92,223 $ 81,960 $ 54,432 $ 51,346 $ 40,129
General and administrative $ 22,004 $ 21,197 $ 13,683 $ 11,762 $ 11,166
Production Volumes:
Gas (Mcf) 46,598 49,663 38,164 39,491 38,346
Oil (Bbls) 4,799 4,541 2,815 2,434 2,398
MCFE 75,393 76,909 55,055 54,093 52,731
Realized Price - pre hedging:
Per BBl $ 39.77 $ 29.40 $ 24.67 $ 24.08 $ 29.02
Per Mcf $ 5.85 $ 5.12 $ 3.10 $ 4.22 $ 3.98
Realized Price - net of hedging:
Per Bbls $ 32.53 $ 26.96 $ 25.34 $ 23.29 $ 23.53
Per Mcf $ 5.52 $ 4.89 $ 3.00 $ 3.73 $ 3.44
Expense per MCFE Data:
LOE and production taxes $ 1.27 $ 1.15 $ 0.92 $ 1.02 $ 0.73
DD&A $ 1.22 $ 1.07 $ 0.99 $ 0.95 $ 0.76
General and Administrative $ 0.29 $ 0.28 $ 0.25 $ 0.22 $ 0.21
Cash Flow Data:
From operations $ 237,162 $ 204,319 $ 141,709 $ 127,492 $ 92,267
For investing $ (247,006) $ (196,939) $ (180,931) $ (159,075) $ (112,868)
From (for) financing $ 1,435 $ (3,707) $ 46,260 $ 29,080 $ 13,025
35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
This discussion includes forward-looking statements. Please refer to
the Cautionary Statement about Forward-Looking Statements section in Part I,
Item 1 of this document for an explanation of these types of statements.
Overview of the Company
General Overview
We are an independent energy company focused on the exploration,
exploitation, acquisition and production of natural gas and crude oil in the
United States. We earn our revenues and generate our cash flows from operations
primarily from the sale of produced natural gas and crude oil. Our oil and gas
reserves and operations are concentrated primarily in the Anadarko, Arkoma,
Permian and various Rocky Mountain basins and the onshore Gulf Coast and
offshore Gulf of Mexico. We maintain a balanced portfolio of proved reserves,
development drilling opportunities and non-conventional gas prospects. As of
December 31, 2004, we had estimated proved reserves of 659 BCFE, with a before
income tax PV-10 value of $1.5 billion and an after income tax value of $1.0
billion. Our reserves are 85 percent proved developed and 52 percent oil.
Oil and Gas Prices
Our results of operations and financial condition are significantly
affected by oil and natural gas commodity prices, which can fluctuate
dramatically. In 2004 oil and gas producers benefited from high oil and gas
commodity prices. Increased prices of natural gas are the result of tightening
supply coupled with increasing demand in the United States. Because of finite
storage capacity, changes in domestic demand created by weather have a
significant effect on price volatility. Increases in oil price are more a result
of global events than events in the United States. These include a decrease in
excess worldwide production capacity, a continuing increase in demand from the
global economy, and continued instability in the Middle East.
Reserve Replacement and Growth
Like all oil and gas exploration and production companies, we face the
challenge of natural resource production decline. An oil and gas exploration and
production company depletes part of its asset base with each unit of oil and gas
it produces. Historically we have been able to grow our production despite this
natural decline by adding more reserves through acquisitions and drilling than
we produce. Future growth will depend on our ability to continue to add reserves
in excess of production.
We believe that growth in net asset value per share drives appreciation
in our stock price. Our challenge to grow net asset value per share has always
been a difficult one. To do this we set a goal of economically replacing 200
percent of our annual production and growing production by 15 percent per year.
Please see our additional discussion of oil and gas reserve quantities in our
critical accounting policies and estimates section. In 2004 we replaced 190
percent of our reserves at a finding cost of $2.19 per MCFE. We believe the
increase in finding costs from the $1.05 amount we reported for the year ended
December 31, 2003, is generally reflective of increasing costs industry-wide
together with 2003 being an excellent year for St. Mary. Finding cost and
reserve replacement percentage are defined in the glossary at the end of Part I
Item 1 of this report. They are comparison measures used to evaluate the
effectiveness of an oil and gas company's reserve replacement program and a
36
snapshot in time of its future profitability. You should note that aberrations,
causing both good and bad results, will occur over short intervals of time.
Sustainability in our business is dependent on the ability to create
new ideas and new value year after year. The challenges we face are becoming
increasingly difficult as North American oil and gas production continues to
decline and other exploration and production companies compete for available
reserves. We believe we have a formula for meeting these challenges. We have
placed talented geoscientists, engineers and landmen in each of our regional
offices where their local knowledge and experience can be fully utilized. They
are supported with a strong balance sheet and fiscal and operating discipline.
In 2004 our pre-tax PV-10 value for proved reserves increased 17
percent to $1.5 billion, with a standardized measure value of $1.0 billion.
These amounts reflect an 11 percent increase in reserves, a 29 percent increase
in adjusted oil reserve pricing to $40.06 per barrel, and a two percent increase
in adjusted gas reserve pricing to $5.80 per Mcf.
2004 Highlights
In 2004 we experienced continuing high oil and gas prices, a modest
decrease in production and earnings, an 11 percent increase in proved reserves
obtained at an acceptable 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 production stage with
evaluated proved reserves. Highlights for 2004 also include good drilling
results at the horizontal Middle Bakken play and in the Red River formation in
the Williston Basin; the repurchase of approximately 3.4 million shares of our
common stock from Flying J at a price of $26.92 per share; the repurchase of an
additional 489,300 shares of our common stock under our stock repurchase program
at an average price of $33.39 per share, and we closed on $76.7 million of oil
and gas property acquisitions for a total of $68.8 million in cash. Our cash
outflows were funded by existing cash and short-term investments on hand, from
operating cash flows and from funds available under our existing credit
facility. From December 2003 to December 2004 the outstanding balance on our
credit facility increased by $26.0 million.
In 2004 oil prices soared to record levels as excess OPEC capacity
shrank to an estimated one percent to two percent of total demand. Demand for
oil was impacted by the growing economies of China and India as well as from a
recovering U.S. economy. Spot market prices reflected worldwide concerns about
producer ability to ensure sufficient supply to meet increasing demand amid a
host of uncertainties caused by weather-related destruction, political
instability, a weaker US dollar, oil rig workers strikes and crude oil refining
constraints. Average natural gas prices for the year were at an all-time high
due to supply and transportation constraints, weather-related lost production,
and continuing strong demand for natural gas in domestic markets resulting from
an improving economy and the effect of high oil prices on natural gas demand.
NYMEX prices for the year averaged $6.09 per MMBtu and $41.40 per barrel,
translating into a 15 percent increase to our per MCFE realized price. At
December 31, 2004, the 12-month NYMEX strip was $42.59 per barrel for oil and
$6.27 per MMBtu for gas.
Net income for 2004 was $92.5 million or $2.88 per diluted share
compared to $95.6 million or $2.80 per diluted share for the prior year. Net
cash provided by operating activities was $237.2 million, up 16 percent from
2003. Production decreased two percent to 75.4 BCFE. Our average realized price
increased 15 percent to $5.48 per MCFE. Unit costs increased modestly for the
period as production expenses increased $0.12 to $1.27 per MCFE, DD&A with
impairments increased $0.15 to $1.22 per MCFE and adjusted general and
administrative expense increased $0.01 to $0.29 per MCFE from $0.28 per MCFE in
2003. The $0.28 per MCFE general and administrative amount for 2003 has been
37
adjusted to reflect the separate presentation of the change in net profits plan
liability expense as discussed in detail below in our comparison of financial
results and trends between 2004 and 2003. Other analyses throughout this report
also reflect changes to exploration expense and general and administrative
expenses for this item.
The future outlook for oil and gas prices to remain high is very
positive, and the worldwide economy appears to be recovering. We have attractive
prospects to drill. Rig counts are growing, and we have seen the impact of
escalating rig and other service costs. The country's ability to supply gas
remains challenged as the average decline rate for natural gas has increased
from 16 percent to 30 percent over the past thirteen years. This change is a
result of increased activity in the Gulf of Mexico where reserve lives are very
short, the use of 3D seismic to identify smaller reservoirs, the use of better
completion techniques that allow reserves to be produced faster, and more
efficient high deliverability storage that allows wells to be produced at full
capacity all year long. New sources of gas such as LNG, frontier regions (e.g.
deepwater Gulf of Mexico and Mackenzie Delta, Alaska) and unconventional gas
plays are all more costly and have long lead times, but at some point could have
a positive impact on supply. We believe oil prices are high now due to
perceptions of reduced spare capacity, increasing worldwide demand and an
apparent increased target price range for OPEC due to a decline in the value of
the dollar.
We enter 2005 in good financial condition and with a capital
expenditure budget of $418 million. In an environment with a competitive
acquisition market and increasing drilling and service costs, we plan to add
value in 2005 as follows:
o Of the $418 million capital expenditures budget, 30 percent is
allocated for acquisitions. The remaining 70 percent available
for exploration and development is allocated 23 percent for
conventional projects and 6 percent for coalbed methane
projects in the Rocky Mountain region, 21 percent in the
Mid-Continent region, 10 percent in the Gulf Coast region, 8
percent in the ArkLaTex region, and 2 percent in the Permian
region. The 2005 exploration and development budget is $293
million, which represents a 28 percent increase over 2004
exploration and development expenditures.
o Our Hanging Woman Basin coalbed methane project will move into
full development with the drilling of approximately 150 wells
in Wyoming and the production of more meaningful volumes from
wells drilled last year. Our strong balance sheet would allow
us to pursue other potentially large unconventional
opportunities.
o On January 5, 2005, the Company closed the acquisition of
Agate Petroleum Inc. for $39.6 million in cash. The estimated
preliminary purchase accounting results in the recording of
approximately $42.1 million to oil and gas properties, $3.0
million to working capital, $9.4 million to goodwill, deferred
income tax liability of $13.6 million and a $1.3 million asset
retirement obligation. The goodwill and deferred income tax
liability are a result of acquiring assets with tax basis that
is lower than book basis. Accounting rules are inconsistent
with the economic evaluation criteria we applied in
determining the bid amount for this transaction because
present value considerations cannot be applied to the amounts
recorded for deferred income taxes.
o We anticipate that acquisitions and our drilling programs will
result in increased production.
38
A year-to-year overview of selected reserve, production and financial
information, including trends:
As of and for the Years Ended
------------------------------------------- % of Change Between
2004 2003 2002 2004/2003 2003/2002
------------ ----------- ------------ --------- ---------
Selected Operations Data (In Thousands, Except Price and Per MCFE Amounts):
Total proved reserves (PV-10 basis)
-----------------------------------
Natural gas (Mcf) 319,196 307,024 274,172
Oil (Bbl) 56,574 47,787 36,119
MCFE 658,638 593,744 490,887 11% 21%
Net production volumes
----------------------
Natural gas (Mcf) 46,598 49,663 38,164
Oil (Bbl) 4,799 4,541 2,815
MCFE 75,393 76,909 55,055 (2)% 40%
MCFE per day 206 211 151 (2)% 40%
Average daily production
------------------------
Natural gas (Mcf) 127 136 105
Oil (Bbl) 13 12 8
MCFE 206 211 151 (2)% 40%
Oil & gas production revenues
---------------------------------
Gas production, including hedging $ 257,206 $ 242,670 $ 114,334
Oil production, including hedging 156,112 122,444 71,336
------------ ----------- ------------
Total $ 413,318 $ 365,114 $ 185,670 13% 97%
============ =========== ============
Oil & gas production costs
------------------------------
Lease operating expenses $ 61,269 $ 59,152 $ 36,472
Transportation costs 7,235 7,197 3,184
Production taxes 27,014 22,160 11,183
------------ ----------- ------------
Total $ 95,518 $ 88,509 $ 50,839 8% 74%
============ =========== ============
Average realized sales price (1)
--------------------------------
Natural gas (per Mcf) $ 5.52 $ 4.89 $ 3.00 13% 63%
Oil (per Bbl) $ 32.53 $ 26.96 $ 25.34 21% 6%
Per MCFE data:
--------------
Average net realized price (1) $ 5.48 $ 4.75 $ 3.37 15% 41%
Lease operating expense (0.81) (0.77) (0.66) 5% 17%
Transportation costs (0.10) (0.09) (0.06) 11% 50%
Production taxes (0.36) (0.29) (0.20) 24% 45%
General and administrative (0.29) (0.28) (0.25) 4% 27%
------------ ----------- ------------
Operating profit $ 3.92 $ 3.32 $ 2.20 18% 49%
============ =========== ============
Depletion, depreciation and amortization $ 1.22 $ 1.07 $ 0.99 15% 8%
Financial Information (In Thousands, Except Per Share Amounts):
Working capital $ 12,035 $ 3,101 $ 2,050 358% 51%
Long-term debt $ 136,791 $ 110,696 $ 113,601 24% (3)%
Stockholders' equity $ 484,455 $ 390,653 $ 299,513 26% 30%
Net income $ 92,479 $ 95,575 $ 27,560 (3)% 247%
Basic net income per common share $ 3.21 $ 3.06 $ 0.99 5% 209%
Diluted net income per common share $ 2.88 $ 2.80 $ 0.97 3% 189%
Basic weighted-average shares outstanding 28,851 31,233 27,856 (8)% 12%
Diluted weighted-average shares outstanding 33,447 35,534 28,391 (6)% 25%
Net cash provided by operating activities $ 237,162 $ 204,319 $ 141,709 16% 44%
$ (196,939) 25% 9%
Net cash used in investing activities $ (247,006) ) $(180,931)
Net cash provided by (used in) financing
activities $ 1,435 $ (3,707) $ 46,260 139% (108)%
- --------------------
(1) Includes the effects of our hedging activities.
39
We present this table as a summary of information relating to those key
indicators of financial condition and operating performance that we believe to
be important.
The increase in our reserve volumes reflects our drilling results and
acquisition activity combined with increases in natural gas and crude oil prices
used to evaluate reserves. Please see Note 12 of Part IV, Item 15 for additional
details. Over time these will be the factors that determine if we are successful
in achieving our target of replacing 200 percent of our production each year. We
anticipate that we must continue our successful drilling program and average one
or more relatively significant acquisitions per year in the current price
environment to achieve this level of growth. The measure of our success will
vary from year-to-year due to changes in these factors, some of which we can
control and others which we cannot control. From January 1, 2002, to December
31, 2004, we replaced 259 percent of our production at a finding cost of $1.38
per MCFE.
The changes in production volumes, oil and gas production revenues and
costs reflect the cyclical and highly volatile nature of prices our industry
receives for production and the effect of the timing of acquisitions. Actual
results in 2002 reflected a lower price environment than in either 2003 or 2004.
We closed our acquisition of the Burlington Resources properties in late 2002
and our acquisition of the Flying J properties in early 2003. Production of 13.8
MMCFE from these two acquisitions was realized in 2003. These were the two
largest acquisitions in our history and, combined with our successful drilling
results in 2002 and 2003, resulted in a 40 percent increase in production from
2002 to 2003. The comparison of changes in production from 2003 to 2004 reflects
the mix of results from our drilling programs in 2004 and the timing of our
acquisitions made in the fourth quarter of 2004.
We present per MCFE information since we use this information to
evaluate our performance relative to our peers and to measure trends that we
believe require analysis. Our year-to-year comparison of financial results
presented later provides additional details for the changes between years. We
expect oil and gas production expenses will increase in 2005 as a result of
increased activity in our higher-cost Rocky Mountain region, increased
production taxes, and general inflation due to higher oil and gas pricing.
Depreciation, depletion and amortization will continue to increase due to the
higher costs associated with finding and acquiring crude oil and natural gas
reserves. General and administrative expense is also projected to increase for
expense associated with our net profits plan, expensing of stock-based
compensation and costs we incur to comply with the Sarbanes-Oxley Act of 2002.
We had a modest decrease in net income from 2003 to 2004. However, if
we compare net income before the cumulative effect of change in accounting
principle recorded in 2003, we had a net income increase driven by realized
price increases of 13 percent for natural gas and 21 percent for oil. By
containing our costs, our operating profit as a percentage of net realized price
was 71 percent in 2004 compared to 70 percent in 2003 and 65 percent in 2002.
Net income as a percentage of oil and gas revenue net of hedging loss was 22
percent in 2004, 25 percent in 2003 and 15 percent in 2002.
We have in-the-money stock options, unvested restricted stock units and
convertible notes that are considered dilutive securities. At times these
dilutive securities can affect our earnings per share, and both basic and
diluted earnings per share are presented in the table above. You should review
Note 1 of Part IV, Item 15 of this report for a detailed explanation. Our basic
and diluted weighted-average common shares outstanding used in our 2004 earnings
per share calculations reflects a decrease in shares caused by our repurchase of
our common stock from Flying J and the re-initiation of our stock repurchase
program offset by an increase in outstanding shares related to stock options.
The remaining information in the table relates to information we have
provided in operations update press releases and is intended to supplement the
discussion above.
40
Overview of Liquidity and Capital Resources
We own depleting assets. In order to maintain our current size and to
sustain our projected growth levels, we will have to successfully invest capital
into new projects and acquisitions. The following analysis and discussion
includes our assessments of market risk and possible effects of inflation and
changing prices.
Sources of cash
Our primary sources of liquidity are the cash provided by operating
activities, debt financing, sales of non-strategic properties and access to the
capital markets. All of these sources can be impacted by the general condition
of our industry and significant fluctuations in oil and gas prices, operating
costs and volumes produced. We have virtually no control over the market prices
for oil and gas. A decrease in these market prices would reduce expected cash
flow from operating activities, might reduce the borrowing base on our credit
facility, could reduce the value of non-strategic properties we might consider
selling and historically has limited our industry's access to the capital
markets.
Our current credit facility. On January 29, 2003, we entered into a
$300.0 million credit facility with Wachovia Bank as Administrative Agent and
eight other participating banks. This credit facility has a maturity date of
January 27, 2006. We anticipate renegotiating the terms of our facility in the
first quarter of 2005 to ensure that we have a credit facility in place beyond
the date of current expiration. The calculated borrowing base as of December 31,
2004, is $325.0 million. We have elected a commitment amount of $150.0 million
under this facility, which results in lower commitment fees payable to the bank
syndicate. We believe this commitment level is adequate for our near-term
liquidity requirements. Under our existing credit facility, our next borrowing
base redetermination is scheduled to occur by the end of April 2005. You should
note the possibility that the banks may not agree to a borrowing base
redetermination that is adequate for our planned financing requirements. We must
comply with certain financial and non-financial covenants, and we are currently
in compliance with all of these covenants. Interest and commitment fees are
accrued based on the borrowing base utilization percentage. LIBOR based
borrowings accrue interest at LIBOR plus the applicable margin from the
utilization table located in Note 5 of Part IV, Item 15 of this report, and
Alternate Base Rate borrowings accrue interest at prime plus the applicable
margin from the utilization table. Commitment fees are accrued on the unused
portion of the aggregate commitment amount and are included in interest expense
in the consolidated statements of operations. Our loan balance of $37.0 million
on December 31, 2004, was comprised of $10.0 million in ABR borrowings and $27.0
million in LIBOR based loans.
Our weighted-average interest rate paid in 2004 was 7.1 percent and
included commitment fees paid on the unused portion of the credit facility
borrowing base, amortization of deferred financing costs, and amortization of
the contingent interest embedded derivative associated with the convertible
notes.
Interest Rate Market Risk. Market risk is estimated as the potential
change in fair value resulting from an immediate hypothetical one-percentage
point parallel shift in the yield curve. The sensitivity analysis discussed
below presents the hypothetical change in fair value of those financial
instruments we held at December 31, 2004, that are sensitive to changes in
interest rates. For fixed-rate debt, interest rate changes affect the fair
market value but do not impact results of operations or cash flows. Conversely,
interest rate changes for floating-rate debt generally do not affect the fair
market value but do impact future results of operations and cash flows, assuming
other factors are held constant. The carrying amount of our floating rate debt
approximates its fair value. After consideration of the effect of interest rate
swaps discussed below, we had floating-rate debt of $87 million and fixed-rate
debt of $50 million at December 31, 2004. Assuming constant debt levels, the
41
cash flow impact for the next year resulting from a one-percentage point change
in interest rates would be approximately $870,000 before taxes. The results of
operations impact might be less than this amount as a direct effect of the
capitalization of interest for wells drilled in the next year. Since we cannot
predict the exact amount that would be capitalized, we cannot predict the exact
effect that a one-percentage point shift would have on the results of
operations.
Uses of cash
We use cash for the acquisition, exploration and development of oil and
gas properties and for the payment of debt obligations, trade payables and
stockholder dividends. Exploration and development programs are generally
financed from internally generated cash flow, debt financing and cash and cash
equivalents on hand. Cash used for the acquisition of oil and gas properties and
the payment of stockholder dividends is discretionary and can be reduced or
eliminated in the event of an unexpected decrease in oil and gas prices. At any
given point in time we may be obligated to pay for commitments to explore for or
develop oil and gas properties or incur trade payables. However, future
obligations can be reduced or eliminated when necessary. Over the next year we
are required to only make interest payments on our debt obligations. An
unexpected increase in oil and gas prices would provide flexibility to modify
our uses of cash flow.
Over the course of 2004 we increased our outstanding debt by a net
$26.0 million. Using this amount, cash on hand and cash flows from operations we
paid $68.8 million for property acquisitions, spent $199.4 million on capital
development and used $35.7 million to repurchase our common stock. We also made
$14.8 million of cash payments for income taxes and $2.8 million for dividends.
At February 15, 2005, we had $46.0 million outstanding on our credit facility.
On February 9, 2004, we repurchased for $91.0 million the 3,380,818
restricted shares of common stock that we issued to Flying J on January 29,
2003. Flying J used the proceeds to repay their outstanding loan principal
balance to us of $71.6 million. Accrued interest on the loan, which was not
recorded by us for financial reporting purposes due to the non-recourse nature
of the loan, was forgiven. The $19.4 million net cash outlay was funded from our
existing cash balance and borrowings under our credit facility. See Note 3 of
Part IV, Item 15 of this report.
We re-initiated our stock repurchase program in August 2004. Since that
time we have repurchased a total of 489,300 shares of our common stock for $16.3
million. As of February 15, 2005, there were 2,510,700 shares authorized to be
repurchased under the program.
The following table presents amounts and percentage changes between
years in net cash flows from our operating, investing and financing activities.
The analysis following the table should be read in conjunction with our
consolidated statements of cash flows in Part IV, Item 15 of this report.
Amount of Change Between Percent of Change Between
----------------------------- -----------------------------
2004/2003 2003/2002 2004/2003 2003/2002
------------- ------------ ------------- ------------
Net Cash Provided By Operating Activities $ 32,843 $ 62,610 16% 44%
Net Cash Used In Investing Activities $ (50,067) $ (16,008) 25% 9%
Net Cash Provided By (Used In) Financial Activities $ 5,142 $ (49,967) (139)% (108)%
42
Analysis of cash flow changes between 2004 and 2003
Operating activities. Sources of cash flow from oil and gas sales
increased $40.7 million from the period ended December 31, 2003 to the period
ended December 31, 2004. This was a result of a 15 percent increase in our
realized prices that offset a net production decrease between the comparative
periods. Cash expenditures for operating expenses, exploration expense and
administrative expenses increased by $2.4 million. Other revenue items decreased
by $5.7 million.
Investing Activities. The increase in net cash used resulted from $75.6
million of increased drilling expenditures in 2004 over 2003 and from a 2004
cash payment of $3.8 million held as a deposit for our Agate acquisition. These
increases were offset by a $7.6 million decrease in acquisition activity in
2004. Total capital expenditures increased by 34 percent to $268.2 million from
$200.2 million in 2003. Proceeds from sales of oil and gas properties decreased
by $20.7 million, but expiration of the restriction period for funds held for
deferred tax exchange of oil and gas properties and net receipts from short-term
investments resulted in a net cash provided change between periods of $41.8
million. Volumes, revenue and net operating margin from properties that were
sold in 2003 and 2004 were not a material component in the consolidated
statements of operations or balance sheets for any year presented, nor do they
represent a group of assets that would qualify for discontinued operations
accounting treatment.
Cash expended in 2003 for acquisitions of oil and gas properties
included our utilization of $71.6 million of short-term investments, cash
equivalents and increased borrowings under our credit facility to provide a loan
to Flying J as part of our acquisition of properties. This loan was secured by
the shares of our common stock issued in the transaction.
Financing activities. The $5.1 million increase in cash provided by
financing activities reflects the $26.0 million we borrowed on our credit
facility in 2004 to fund acquisitions and drilling activity and an $11.5 million
increase in proceeds from stock option exercises over the 2003 amounts. We paid
$19.4 million to repurchase our shares from Flying J on February 9, 2004, and we
paid $16.3 million to repurchase shares under our stock repurchase program. In
2003 we borrowed to fund our acquisition of properties from Flying J and used
cash flow from operations to reduce our outstanding debt for the year.
St. Mary had $6.4 million in cash and cash equivalents and had working
capital of $12.0 million as of December 31, 2004, compared to $14.8 million in
cash and cash equivalents and working capital of $3.1 million as of December 31,
2003.
Analysis of cash flow changes between 2003 and 2002
Operating activities. The differences above reflect increases in
sources of cash flow from oil and gas sales due to a 40 percent increase in
production and a 41 percent increase in price. We did not see the full $99.2
million benefit of the net change between years in our cash flow since $40.8
million of the change in net income, adjusted for non-cash items, related to a
2003 increase in outstanding accounts receivable of $29.7 million and an $11.1
million decrease in outstanding accounts receivable in 2002. The remaining $5.7
million difference relates to proceeds from asset sales, collections of
refundable income tax and increases in prepaid expenses and accounts payable.
Investing Activities. The increase results primarily from additional
capital and exploration costs. Total 2003 capital expenditures for cash,
including acquisitions of oil and gas properties, increased $15.5 million or 8
percent to $200.2 million in 2003 compared to $184.7 million in 2002. Increases
in proceeds from sales were partially offset by amounts deposited in long-term
restricted cash accounts for the tax-deferred exchange of oil and gas
properties. The long-term restricted cash was available to be used for the
43
acquisition of oil and gas properties in 2004. The amount of cash invested in
long-term restricted cash reflects our projection of the likelihood we will be
successful. Our sales of proved oil and gas properties in 2003 resulted in $23.5
million of cash proceeds. Revenue and net operating margin from the properties
that we sold were not a material component of the current year or any prior year
component of the consolidated statements of operations or balance sheets, nor do
they represent a group of assets that would qualify for discontinued operations
accounting treatment.
Cash expended in 2003 for acquisitions of oil and gas properties
includes our utilization of $71.6 million of short-term investments, cash
equivalents and increased borrowings under our credit facility to provide a loan
to Flying J as part of our acquisition of properties. This loan was secured by
the shares of our common stock issued in the transaction.
In December 2002 we purchased oil and gas properties from Burlington
Resources Oil & Gas Company LP for $69.5 million in cash. We financed this
acquisition using cash on hand and a portion of our credit facility.
Financing activities. The $50.0 million decrease from 2002 to 2003
reflects the issuance of our convertible notes and a $3.0 million pay down of
our credit facility in 2003.
In March 2002, we issued a total of $100.0 million of our convertible
notes with a 0.5 percent contingent interest provision in a private placement.
Interest payments are due on March 15 and September 15 of every year. We
received net proceeds of $96.8 million after deducting the initial purchasers'
discount and offering expenses payable by us. The convertible notes are general
unsecured obligations and rank on a parity in right of payment with all our
existing and future senior indebtedness and other general unsecured obligations,
and are senior in right of payment with all our future subordinated
indebtedness. We used a portion of the net proceeds from the convertible notes
to repay our credit facility balance and used the remaining net proceeds to fund
a portion of our 2002 capital expenditures. In October 2004 we entered into
interest rate swap agreements on a total notional amount of $50.0 million of the
convertible notes, which lowered our interest expense in 2004. The convertible
notes can be converted into our common stock at a conversion price of $26.00 per
share, subject to adjustment. See Note 5 of Part IV, Item 15 of this report for
a more detailed discussion of the conversion features. The first date that St.
Mary may redeem the convertible notes is in March 2007. Our current stock price
is in excess of the $26.00 conversion price.
St. Mary had $14.8 million in cash and cash equivalents and had working
capital of $3.1 million as of December 31, 2003, compared to $11.2 million in
cash and cash equivalents and working capital of $2.1 million as of December 31,
2002.
2005 Capital Expenditure Budget
We continuously evaluate opportunities in the marketplace for oil and
gas properties and, accordingly, may be a buyer or a seller of properties at
various times. We will continue to emphasize smaller niche acquisitions
utilizing our technical expertise, financial flexibility and structuring
experience. In addition, we are also actively seeking larger acquisitions of
assets or companies that would afford opportunities to expand our existing core
areas, add additional geoscientists and/or engineers, or gain a significant
acreage and production foothold in a new basin.
44
Expenditures for exploration and development of oil and gas properties
and acquisitions are the primary use of our capital resources. We anticipate
spending approximately $418 million for capital and exploration expenditures in
2005 with $125 million allocated for acquisitions of producing properties.
Anticipated ongoing exploration and development expenditures for each of our
core areas are as follows:
---------------------------------
Gross Well
In Millions Count
--------------- ---------------
Rocky Mountain region $ 95 118
Mid Continent region 87 90
Gulf Coast region 41 27
ArkLaTex region 34 81
Coalbed Methane 26 183
Permian Basin region 10 35
--------------- ---------------
Total $ 293 534
=============== ===============
We regularly review our capital expenditure budget to reflect changes
in current and projected cash flows, acquisition opportunities, debt
requirements and other factors. The above allocations are subject to change
based on various factors and results, including the availability of drilling and
service rigs.
The following table sets forth certain information regarding the costs
incurred by us in our oil and gas activities:
Years Ended December 31,
-----------------------------------------------------
2004 2003 2002
--------------- ---------------- ---------------
(In thousands)
Development costs $ 190,829 $ 111,908 $ 74,376
Exploration costs 37,977 33,296 22,548
Acquisitions:
Proved 69,054 73,989 85,559
Unproved 7,646 8,942 2,147
Leasing activity 7,877 7,480 8,128
--------------- ---------------- ---------------
Total $ 313,383 $ 235,615 $ 192,758
=============== ================ ===============
Our costs incurred for capital and exploration activities in 2004
increased $77.8 million or 33 percent compared to 2003. This increase was a
result of a planned $20.3 million increase in the drilling activity budget, a
$17.1 million increase in the acquisition budget, an $8.6 million increase in
capitalized costs associated with asset retirement obligations, and an
additional $63.0 million spent on opportunities that arose during 2004. We
reallocated $31.2 million from the acquisitions budget for these opportunities.
We continue to move forward with the development of coalbed methane
reserves in our Hanging Woman Basin project. We have 154,000 net lease acres in
the basin and are concentrating our initial development on 80,000 net acres
located in Wyoming. Outstanding legal challenges filed by environmental public
interest groups affect 47,000 net acres in Montana relating to this project. See
Legal Proceedings under Part I, Item 3 of this report.
45
In 2002 we used a portion of the proceeds from our convertible debt
offering to fund our capital expenditures budget, but historically we have used
internally generated cash flow, existing cash and our credit facility. We
believe that internally generated cash flow and our credit facility will be
utilized in 2005. The amount and allocation of future capital and exploration
expenditures will depend upon a number of factors including the number and size
of available acquisition opportunities, whether we can make economic
acquisitions and our ability to assimilate acquisitions we are considering.
Also, the impact of oil and gas prices on investment opportunities, the
availability of capital and borrowing capability and the success of our
development and exploratory activity could lead to funding requirements for
further development.
Financing alternatives
The debt and equity financing capital markets remain very attractive to
energy companies who operate in the exploration and production segment. This is
a result of strong commodity prices and the general strength reflected in the
balance sheets of the companies in this segment. As our cash balance and
availability under our existing credit facility are significant, we are not
currently considering accessing the capital markets in 2005. However, if
additional development or attractive acquisition opportunities arise that exceed
our current available resources, we may consider other forms of financing,
including the public offering or private placement of equity or debt securities
as well as expanding our borrowing availability under traditional secured bank
financing.
Sensitivity analysis
The next table reflects our estimate of the effect on cash flow from
operations for the years presented of a 10 percent change in our average
realized sales price for natural gas, for oil and in total. These amounts have
been reduced by the effective income tax rate applicable to each period since a
reduction in revenue would reduce cash requirements to pay income taxes. General
and administrative expenses have not been adjusted. To fund the capital and
exploration expenditures we incurred in those years we would have been required
to access our credit facility as a source of funds. In each of these years we
had sufficient borrowing base available under our credit facility to meet this
contingency without reducing or eliminating expenditures and affecting our
growth strategy. Taking into account the February 15, 2005, loan balance of our
credit facility we believe we have sufficient borrowing base available to
continue our growth strategy if prices should change.
Pro Forma effect on revenues of a 10
percent change in average sales price:
- ------------------------------------------------
As of and for the Years Ended December 31,
-------------------------------------------------
2004 2003 2002
-------------- ---------------- ---------------
(In thousands)
Natural Gas $ 15,280 $ 13,889 $ 6,944
Oil $ 9,180 $ 6,979 $ 4,350
-------------- ---------------- ---------------
Total $ 24,460 $ 20,868 $ 11,294
============== ================ ===============
Summary of oil and gas production hedges in place
Our net realized oil and gas prices are impacted by hedges we have
placed on future forecasted transactions. We have historically entered into
hedges of existing production around the time we make acquisitions of producing
oil and gas properties. Our intent is to lock-in a significant portion of an
equivalent amount of our existing production to the prices we used to evaluate
the economics of our acquisition. We are also hedging a small percentage of our
forecasted production on a discretionary basis.
46
Note 10 of Part IV, Item 15 of this report contains important
information about our oil and gas derivative contracts including the volumes and
average contract prices of hedges we currently have in place as of December 31,
2004. We have not entered into any additional hedges as of February 15, 2005. We
anticipate that all hedge transactions will occur as expected.
For swap contracts in place on December 31, 2004, a hypothetical
increase of 10 percent in future gas strip prices representing a $0.58
weighted-average increase per MMBtu applied to a notional amount of 9.9 million
MMBtu covered by natural gas swaps would cause a decrease in the value of
derivative instruments of $5.7 million. A hypothetical increase of 10 percent in
the future NYMEX strip oil prices representing a $4.12 increase per Bbl applied
to a notional amount of 1.4 MMBbl covered by crude oil swaps would cause a
decrease in the value of derivative instruments of $5.7 million.
For collar contracts in place on December 31, 2004, a hypothetical
increase of 10 percent in future gas strip prices representing a $0.57
weighted-average increase per MMBtu applied to a notional amount of 1.9 million
MMBtu covered by natural gas collars would cause a decrease in the value of
derivative instruments of $729,000.
The effect of price increases would impact our hedge gain or loss
amounts. However, these are cash flow hedges with high correlation, and the
price we receive on the underlying production would be higher by approximately
the same amount. The effect on our results of operations would be minimal.
Summary of interest rate hedges in place
We entered into fixed-rate to floating-rate interest rate swaps on
$50.0 million of convertible notes on October 3, 2003. We attempt to maintain a
balanced allocation between fixed and floating rate debt. As our usage of the
credit facility at that time was nearing zero, we elected to exchange fixed rate
payments for floating rate payments on a portion of the interest on our
convertible notes. This hedge does not qualify for fair value hedge treatment
under SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities. Excluding accrued payments due to us at December 31, 2004, the
interest rate swaps had a fair value liability of $432,000. Derivative loss in
the consolidated statements of operations for the years ended December 31, 2004,
and 2003, includes $328,000 and $104,000, respectively, of loss related to the
fair value liability increase.
Schedule of contractual obligations
The following table summarizes our future estimated principal payments
and minimum lease payments for the periods specified (in millions):
Less than More than 5
Contractual Obligations Total 1 year 1-3 years 3-5 years years
- --------------------------- ----------- ----------- ----------- ----------- -------------
Long-Term Debt $ 137.0 $ - $ 137.0 $ - $ -
Operating Leases 10.7 2.4 3.1 2.3 2.9
Other Long-Term Liabilities 10.6 1.8 4.7 1.7 2.4
----------- ----------- ----------- ----------- -------------
Total $ 158.3 $ 4.2 $ 144.8 $ 4.0 $ 5.3
=========== =========== =========== =========== =============
This table excludes the unfunded portion of our estimated pension
liability of $1.4 million, as we cannot determine with accuracy the timing of
future payments. The table also excludes estimated payments associated with our
47
net profits plan. We record a liability for the estimated future payments.
However, predicting the precise timing the liability will be paid is contingent
upon estimates of appropriate discount factors adjusting for risk and time-value
and upon a number of factors that we cannot control. We have excluded asset
retirement obligations because we are not able to precisely predict the timing
for these amounts. Pension liabilities and asset retirement obligations are
discussed in Note 8 and Note 9, respectively, and the net profits plan is
discussed in Note 7 of Part IV, Item 15 of this report.
Three leases for office space will expire in year 3, and a fourth
office space lease will expire in year 4. Estimated costs to replace these
leases are not included in the table above. For purposes of the table we assume
that the holders of our convertible notes will not exercise the conversion
feature. If the holders do exercise their conversion feature, we will not have
to repay the $100.0 million upon conversion. Our common shares outstanding would
increase by 3,846,150 shares.
We believe that we will continue to pay annual dividends of at least
$0.10 per share. We anticipate making cash payments for income taxes, dependent
on net income and capital spending.
Off-Balance Sheet Arrangements
Aside from operating leases we do not have any off-balance sheet
financing nor do we have any unconsolidated subsidiaries.
Critical Accounting Policies and Estimates
We are engaged in the exploration, development, acquisition and
production of natural gas and crude oil. Our discussion of financial condition
and results of operation is based upon the information reported in our
consolidated financial statements. The preparation of these consolidated
financial statements requires us to make assumptions and estimates that affect
the reported amounts of assets, liabilities, revenues and expenses as well as
the disclosure of contingent assets and liabilities at the date of our financial
statements. We base our decisions affecting the estimates we use on historical
experience and various other sources that are believed to be reasonable under
the circumstances. Actual results may differ from the estimates we calculate due
to changing business conditions or unexpected circumstances. Policies we believe
are critical to understanding our business operations and results of operations
are detailed below. For additional information on our significant accounting
policies you should see Note 1 - Summary of Significant Accounting Policies,
Note 9 - Asset Retirement Obligations, and Note 12 - Disclosures About Oil and
Gas Producing Activities in Part IV, Item 15 of this report.
Oil and gas reserve quantities. Estimated reserve quantities and the
related estimates of future net cash flows are the most important estimates for
an exploration and production company because they affect the perceived value of
our company, are used in comparative financial analysis ratios, and are used in
significant accounting estimates including the periodic calculations of
depletion, depreciation and impairment for our proved oil and gas properties.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future periods from known
reservoirs under existing economic and operating conditions. Future cash inflows
and future production and development costs are determined by applying benchmark
prices and costs, including transportation, quality and basis differentials, in
effect at the end of each period to the estimated quantities of oil and gas
remaining to be produced at the end of that period. Expected cash flows are
reduced to present value using a discount rate that depends upon the purpose for
which the reserve estimates will be used. For example, the standardized measure
calculation required by SFAS No. 69, Disclosures about Oil and Gas Producing
48
Activities, requires a 10 percent discount to be applied. Although reserve
estimates are inherently imprecise, and estimates of new discoveries and
undeveloped locations are more imprecise than those of established proved
producing oil and gas properties, we make considerable effort to estimate our
reserves. We expect that periodic reserve estimates will change in the future as
additional information becomes available or as oil and gas prices and operating
and capital costs change. We evaluate and estimate our oil and gas reserves at
December 31 and June 30 of each year. For purposes of depletion, depreciation,
and impairment, reserve quantities are adjusted at all interim periods for the
estimated impact of additions and dispositions. Changes in depletion,
depreciation or impairment calculations caused by changes in reserve quantities
or net cash flows are recorded in the period that the reserve estimates changed.
The following table presents information regarding reserve changes from
period to period that reflect changes from items we do not control, such as
price, and from changes resulting from better information due to production
history and well performance. These changes do not require a capital expenditure
on our part, but may have resulted from capital expenditures we incurred to
develop other estimated proved reserves.
Years Ended December 31,
----------------------------------------------------------------------------
2004 2003 2002
----------------------- ------------------------ -------------------------
MMCFE Percent MMCFE Percent MMCFE Percent
of total of total of total
Change Additons Change Additons Change Additons
---------- ----------- ----------- ----------- ----------- ------------
Revisions resulting
from price changes 16,206 11% 6,750 3% 33,931 20%
Revisions resulting
From performance (26,127) (18)% 14,290 6% (7,569) (4)%
---------- ----------- ----------- ----------- ----------- ------------
Total (9,921) (7)% 21,040 9% 26,362 16%
========== =========== =========== =========== =========== ============
Over the three-year period, we added 537.0 million MCFE of reserves,
and 56.9 million MCFE, or 11 percent, were a result of price changes. A 19.4
million MCFE, or four percent, reduction in reserves was a result of changes in
estimates based on the performance of our oil and gas properties. As previously
noted, oil and gas prices are volatile and estimates of reserves are inherently
imprecise. Consequently, we anticipate we will continue to experience these
types of changes.
The following table reflects the estimated MMCFE change and percentage
change to our reported reserve volumes from the described hypothetical changes:
Years Ended December 31,
----------------------------------------------------------------------
2004 2003 2002
---------------------- --------------------- -----------------------
MMCFE Percent MMCFE Percent MMCFE Percent
Change Change Change Change Change Change
----------- --------- ---------- --------- ----------- ----------
A 10% decrease in pricing 16,672 3% 9,479 2% 8,700 2%
A 10% decrease in proved
undeveloped reserves 9,839 1% 6,744 1% 6,043 1%
Additional reserve information can be found in the reserve table and
discussion included in Item 1 of Part I of this report.
49
Successful efforts method of accounting. Generally accepted accounting
principles provide for two alternative methods for the oil and gas industry to
use in accounting for oil and gas producing activities. These two methods are
generally known in our industry as the full cost method and the successful
efforts method. Both methods are widely used. The methods are different enough
that in many circumstances the same set of facts will provide materially
different financial statement results within a given year. We have chosen the
successful efforts method of accounting for our oil and gas producing
activities, and a detailed description is included in Note 1 of Part IV, Item 15
of this report.
Revenue recognition. Our revenue recognition policy is significant
because revenue is a key component of our results of operations and our
forward-looking statements contained in our analyses of liquidity and capital
resources. We derive our revenue primarily from the sale of produced natural gas
and crude oil. We report revenue gross for the amounts we receive before taking
into account production taxes and transportation costs which are reported as
separate expenses. Revenue is recorded in the month our production is delivered
to the purchaser, but payment is generally received between 30 and 90 days after
the date of production. At the end of each month we make estimates of the amount
of production delivered to the purchaser and the price we will receive. We use
our knowledge of our properties; their historical performance; the anticipated
effect of weather conditions during the month of production; NYMEX and local
spot market prices; and other factors as the basis for these estimates.
Variances between our estimates and the actual amounts received are recorded in
the month payment is received. A 10 percent change in our year-end revenue
accrual would have impacted net income before tax by $7.9 million in 2004.
Crude oil and natural gas hedging. Our crude oil and natural gas
hedging contracts will usually qualify for cash flow deferral hedge accounting
under SFAS No. 133. This policy is significant because it affects the timing of
revenue recognition in our statements of operations and is discussed prominently
in our forward-looking statements contained in our discussions of liquidity and
capital resources. Under this accounting pronouncement a majority of the gain or
loss from a contract qualifying as a cash flow hedge is deferred as to statement
of operations recognition. The position reflected in the statement of operations
is based on the actual settlements with the counterparty. If our natural gas and
crude oil hedge contracts did not qualify for hedge accounting treatment or we
chose not to use this hedge accounting methodology, our periodic statements of
operations could include significant changes in the estimate of non-cash
derivative gain or loss due to swings in the value of these contracts.
Consequently we would report a different amount for oil and gas hedge loss in
our statements of operations. These fluctuations could be especially significant
in a volatile pricing environment such as we have encountered over the last
three years. Net income after tax would have increased or (decreased) for 2004,
2003 and 2002 by the following amounts: $2.6 million, $(14.3 million), and $(6.3
million), respectively.
Asset retirement obligations. Under SFAS No. 143, Accounting for Asset
Retirement Obligations, we are required to recognize an estimated liability for
future costs associated with the abandonment of our oil and gas properties. We
base our estimate of the liability on our historical experience in abandoning
oil and gas wells projected into the future based on our current understanding
of federal and state regulatory requirements. Our projections require us to
estimate economic lives of our properties, future inflation rates applied to
external estimates as well as a credit adjusted risk-free rate to use in present
value calculations. The statement of operations impact of this calculation is
reflected in our depreciation, depletion and amortization calculations and
occurs over the remaining life of our oil and gas properties.
Valuation of long-lived and intangible assets. Our property and
equipment is recorded at cost. An impairment allowance is provided on unproved
property when we determine that the property will not be developed or the
carrying value will not be realized. We evaluate the realizability of our proved
properties and other long-lived assets whenever events or changes in
circumstances indicate that impairment may be appropriate. Our impairment test
50
compares the expected undiscounted future net revenues from a property, using
escalated pricing, with the related net capitalized costs of the property at the
end of each period. When the net capitalized costs exceed the undiscounted
future net revenue of a property, the cost of the property is written down to
our estimate of fair value, which is determined by applying a discount rate that
we believe is indicative of the current market. Our criteria for an acceptable
internal rate of return are subject to change over time. Different pricing
assumptions or discount rates could result in a different calculated impairment.
Change in Net Profits Plan liability. We record the estimated liability
of future payments under our net profits plan because it is a vested employee
benefit. The estimated liability is calculated based on a number of interrelated
assumptions we control, including estimates of oil and gas reserves, recurring
and workover lease operating expense, tax rates, present value discount factors
and certain pricing assumptions. The estimates we use in calculating the
liability are modified by us from reporting period to reporting period based on
new information attributable to the underlying assumptions. Changes in the
estimated liability of future payments associated with this plan are recorded as
increases or decreases to expense in the current period. Changes in estimated
future pricing, the costs of operating properties, tax rates, reserve
quantities, production rates, or discount factors could have a material impact
on the calculated liability and our consolidated statements of operations.
Changes in the expense caused by changes in the underlying estimates are
recorded in the period that the estimates change. A significant component of the
estimated future liability is based on oil and gas pricing. A 10 percent
increase to the pricing assumptions used in the measurement of this liability at
December 31, 2004 would have decreased net income before taxes by $8.1 million
in 2004.
Income taxes. We provide for deferred income taxes on the difference
between the tax basis of an asset or liability and its carrying amount in our
financial statements in accordance with SFAS No. 109, Accounting for Income
Taxes. This difference will result in taxable income or deductions in future
years when the reported amount of the asset or liability is recovered or
settled, respectively. Considerable judgment is required in determining when
these events may occur and whether recovery of an asset is more likely than not.
Additionally, our federal and state income tax returns are generally not filed
before the consolidated financial statements are prepared, therefore we estimate
the tax basis of our assets and liabilities at the end of each period as well as
the effects of tax rate changes, tax credits and net operating and capital loss
carryforwards and carrybacks. Adjustments related to differences between the
estimates we used and actual amounts we reported are recorded in the period in
which we file our income tax returns. These adjustments and changes in our
estimates of asset recovery could have an impact on our results of operations. A
one percent change in our effective tax rate would have affected our calculated
income tax expense by $1.5 million for the year ended December 31, 2004.
Stock based compensation. We account for stock-based compensation using
the intrinsic value recognition and measurement principles detailed in
Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
Employees. No stock-based employee compensation expense relating to stock
options has been reflected in our general and administrative expense as all
options granted under our plans had an exercise price equal to the market value
of the underlying common stock on the date of grant. We currently use the
Black-Scholes option valuation model to calculate required disclosures under
SFAS No. 123. In December 2004 the FASB issued SFAS No. 123(R), Shared-Based
Payment. This statement provides for the accounting for transactions in which an
entity exchanges equity instruments or incurs liabilities in exchange for goods
or services. The statement is effective for us as of July 1, 2005. Following
implementation, we anticipate that we will have expense associated with unvested
options totaling $5.7 million that must be recorded in future periods under the
modified-prospective method.
51
Additional Comparative Data in Tabular Format:
Change Between Years
----------------------------------------
Oil and Gas Production Revenues: 2004 and 2003 2003 and 2002
------------------ ------------------
Increase in oil and gas production $ 48,204 $ 179,444
revenues (in thousands)
Components of Revenue Increases (Decreases):
Natural Gas
- -----------
Price change per Mcf $ 0.63 $ 1.89
Price percentage change 13% 63%
Production change (MMcf) (3,065) 11,499
Production percentage change (6)% 30%
Oil
- ---
Price change per Bbl $ 5.57 $ 1.62
Price percentage change 21% 6%
Production change (MBbl) 258 1,726
Production percentage change 6% 61%
Our product mix as a percentage of total oil and gas revenue and production:
Years Ended December 31,
-------------------------------------------------
2004 2003 2002
-------------- -------------- -------------
Revenue
- -------
Natural Gas 59% 66% 63%
Oil 41% 34% 37%
Production
Natural Gas 62% 65% 69%
Oil 38% 35% 31%
Information regarding the effects of oil and gas hedging activity:
Years Ended December, 31
---------------------------------------------------------------
2004 2003 2002
------------------ ------------------- ------------------
Natural Gas Hedging
- -------------------
Percentage of gas production hedged 25% 40% 45%
Natural gas MMBtu hedged 12.9 million 21.7 million 18.9 million
(Decrease) in gas revenue ($15.5 million) ($11.4 million) ($4.1 million)
Average realized gas price per Mcf before hedging $ 5.85 $ 5.12 $ 3.10
Oil Hedging
- -----------
Percentage of oil production hedged 45% 54% 54%
Oil volumes hedged (MBbl) 2,156 2,474 1,518
Increase (decrease) in oil revenue ($34.8 million) ($11.1 million) $1.9 million
Average realized oil price per Bbl before hedging $ 39.77 $ 29.40 $ 24.69
52
Information regarding the components of exploration expense:
Years Ended December 31,
---------------------------------------------------
2004 2003 2002
-------------- --------------- --------------
Summary of Exploration Expense (In millions)
- --------------------------------------------
Geological and geophysical expenses $ 7.3 $ 5.1 $ 3.5
Exploratory dry holes 4.2 8.5 7.7
Overhead and other expenses 17.1 11.7 8.1
-------------- --------------- --------------
$ 28.6 $ 25.3 $ 19.3
============== =============== ==============
Comparison of Financial Results and Trends between 2004 and 2003
Oil and gas production revenues. Average net daily production decreased
two percent to 206.0 MMCFE for 2004 compared with 210.7 MMCFE in 2003. Wells
completed and properties acquired in 2003 and during 2004 have added revenue of
$102.8 million and average net daily production of 38.2 MMCFE in 2004 compared
to 2003. These increases are offset by natural declines in production from older
properties and 3.9 MMCFE per day of 2003 production from properties that were
sold in 2003.
Oil and gas hedge loss. As noted in the table above, the 124 percent
increase in total oil and gas hedge loss to $50.3 million was caused by a 35
percent increase in the average pre-hedge oil price and a 14 percent increase in
the pre-hedge gas price.
Oil and gas production expenses. Total production costs increased $7.0
million or eight percent to $95.5 million for 2004, from $88.5 million in 2003.
Our acquisition of properties added $2.8 million of incremental production
costs, and wells completed in 2003 and 2004 added $7.7 million of incremental
production costs in 2004 that were not reflected in 2003. We experienced an
increase in production taxes consistent with the increase in revenue from higher
realized prices.
Total oil and gas production costs per MCFE increased $0.12 to $1.27
for 2004, compared with $1.15 for 2003. This increase is comprised of the
following:
o A $0.07 increase in production taxes due to higher realized
per MCFE prices;
o A $0.01 increase in transportation costs;
o A $0.01 decrease in LOE relating to workover charges;
o A $0.04 increase in LOE that reflects increasing costs in our
Rocky Mountain region; and
o A $0.01 increase reflecting a general increases in LOE per
MCFE in our other core areas.
Exploration expense. Exploration expense increased 13 percent in 2004.
The most significant component of our increase to exploration expense was $5.5
million for exploration overhead we are incurring as we increase the size of our
geologic and exploration staff.
General and administrative expense. General and administrative expenses
increased $807,000 or four percent to $22.0 million for 2004, compared with
$21.2 million in 2003. The increase in cost on a per MCFE basis of $0.01
reflects the effect of the four percent increase in G&A and a two percent
decrease in production between the respective periods.
An increase in our employee count from 226 to 249 has resulted in a
general increase in G&A of $4.2 million between 2004 and 2003. That increase
plus a $913,000 increase in fees that are directly related to Sarbanes-Oxley
compliance, and a $959,000 increase in other professional fees were offset by an
53
increase of $5.5 million of general and administrative expense we allocated to
exploration expense.
Change in Net Profits Plan liability. This expense is the change in the
net present value of estimated future incentive compensation payments to be made
to plan participants under the computational provisions of the plan. During 2004
we determined that the expense adjustment related to the estimated future net
profits plan liability should be presented separately from general and
administrative and exploration expense because this liability is calculated
based on the estimated net cash flows not yet realized from the future
production of oil and gas and as such are not current expenses like general and
administrative or exploration expense. This reclassification has the effect of
reducing previously reported general and administrative expense and exploration
expense to include only those amounts paid or accrued under the net profits plan
that relate to current period oil and gas operations. For the year ended
December 31, 2004, the expense related to the change in the estimated liability
for this plan increased to $24.4 million from $5.3 million for 2003. This
increase is due to the performance of individual pools, the effect of a higher
price environment, and the application of lower discount rates to reflect the
current economics of the market. Adjustments to the liability are subject to
estimation and may change dramatically from year-to-year based on assumptions
used for production rates, reserve quantities, commodity pricing, discount
rates, tax rates, and production costs.
Interest expense. Interest expense decreased by $1.7 million to $6.2
million for 2004 compared to $8.0 million for 2003. The decrease reflects the
benefit of interest rate swaps we entered into on October 3, 2003, and decreased
average borrowings under our credit facility in 2004 relative to the prior year.
Income tax expense. Income tax expense totaled $53.7 million for 2004
and $55.9 million in 2003, resulting in effective tax rates of 36.8 percent and
38.3 percent, respectively. The effective rate change from 2003 reflects
percentage depletion and other permanent differences as well as changes in the
composition of the highest marginal state tax rates as a result of acquisition
and drilling activity. The cumulative effect of the change in marginal state tax
rates that we recorded in 2004 was a result of filing our 2003 income tax
returns and completing the evaluation of the impact on future temporary
difference reversals.
The current portion of the income tax expense in 2004 is $22.5 million
compared to $32.2 million in 2003. These amounts are 42 percent and 58 percent
of the total tax for the respective periods. The difference results from
decreased estimated taxable income caused by an increase in the estimated
percentage of deductible intangible drilling costs relative to total income and
the effect of an increase in stock option exercises. Unless the prices we
receive for oil and gas change radically from our projections or we adjust the
drilling portion of our budget, we estimate that the proportion of taxable
income to book income will remain somewhat the same in 2005. Therefore, we
believe that current taxable income will be lower and that the current portion
of income tax as a percentage of total income tax will also remain somewhat the
same.
Cumulative effect of change in accounting principal, net of income tax.
On January 1, 2003 we adopted SFAS No. 143. The impact of adoption resulted in
income to us of $8.8 million offset by the deferred income tax effect of $3.4
million. See Note 9 in Part IV, Item 15 of this report.
Comparison of Financial Results and Trends between 2003 and 2002
Oil and gas production revenues. Average net daily production increased
40 percent to 210.7 MMCFE for 2003 compared with 150.8 MMCFE in 2002. Included
in our 2003 production volumes are 13.8 MMCFE from the Burlington and Flying J
54
acquisitions. Wells completed and acquired in 2002 and 2003 have added revenue
of $135.3 million and average net daily production of 71.0 MMCFE in 2003
compared to 2002.
Oil and gas hedge loss. The $20.2 million increase in loss between 2003
and 2002 results from a combination of increased prices for oil and gas and an
increase in the volumes we hedged as a result of our Burlington and Flying J
property acquisitions.
Oil and gas production expenses. Total production costs increased $37.7
million to $88.5 million for 2003, from $50.8 million in 2002. Our acquisition
of properties from Burlington and Flying J added $24.9 million of incremental
production costs, and wells completed in 2002 and 2003 added $7.9 million of
incremental production costs in 2003 that were not reflected in 2002.
Additionally, we experienced an increase in production taxes consistent with the
increase in revenue from higher realized prices.
Total oil and gas production costs per MCFE increased $0.23 to $1.15
for 2003, compared with $0.92 for 2002. This increase is comprised of the
following:
o A $0.09 increase in production taxes due to higher realized
per MCFE prices;
o A $0.03 increase due to rising transportation costs in our
Rockies and Mid-Continent regions;
o A $0.03 increase in LOE relating to workover charges for
projects in our Gulf Coast, Rocky Mountain and ArkLaTex
regions;
o A $0.14 increase in LOE that reflects our addition of
higher-cost oil properties in our Rocky Mountain region
through acquisitions from Burlington and Flying J; and
o A $0.06 decrease reflecting general decreases in LOE per MCFE
in our other core areas.
Exploration expense. Exploration expense increased 31 percent in 2003.
The most significant component of our increase to exploration expense was $3.6
million for increased exploration overhead due to increases in our geologic and
exploration staff as a result of the acreage we have acquired in the Williston,
Green River, Wind River and Powder River basins and due to increases in our
exploration-related incentive compensation.
General and administrative expense. General and administrative expenses
increased $7.5 million or 55 percent to $21.2 million for 2003, compared with
$13.7 million in 2002. The increase in cost on a per MCFE basis reflects a
higher percentage increase in G&A than the proportionate increase in
production of 40 percent for the period.
An increase in our employee count from 185 to 226 resulted in a general
increase in G&A of $5.4 million between 2003 and 2002. That increase plus a
$6.8 million increase in expense associated with our incentive compensation
plans, a $1.0 million increase in accrued charitable contributions expense and a
$539,000 increase in insurance and corporate governance costs were offset by a
$6.9 million increase in COPAS overhead reimbursement from operations and
G&A we allocated to exploration expense. COPAS overhead reimbursement from
operations increased by $3.5 million due to 413 additional properties we operate
in our Rocky Mountain region as a result of our Burlington and Flying J
acquisitions. During 2003 we sold 74 of these properties. The increase in
expense associated with our incentive compensation plans reflects both the
benefit we received from the current price environment for past employee
performance and the performance of our employees during that year.
55
Change in Net Profits Plan liability. The increase in the estimated
liability resulted in expense of $5.3 million for the year ended December 31,
2003 compared to $846,000 for 2002.
Interest expense. Interest expense increased by $4.1 million to $8.0
million for 2003 compared to $3.9 million for 2002. The increase reflects a full
year of accrued interest in 2003 on our convertible notes that were issued in
March 2002, the benefit of an interest rate swap that reduced interest expense
in 2002 by $839,000, the 0.5 percent contingent interest provision which applied
in all of 2003 but for only 15 days during the comparable period in 2002, and
increased borrowings under our credit facility in 2003 relative to the prior
year.
Income tax expense. Income tax expense totaled $55.9 million for 2003
and $15.0 million in 2002, resulting in effective tax rates of 38.3 percent and
35.3 percent, respectively. The effective rate change from 2002 reflected an
increase in our highest marginal federal tax rate, the expiration of the Section
29 tax credit, adjustments to valuation allowances to reflect the likelihood
that prior Alternative Minimum Tax credits created by Section 29 credits will
not be used, changes in the composition of the highest marginal state tax rates
as a result of our recent acquisitions and the 2002 adjustment to valuation
allowances against state income taxes from net operating loss carryovers.
The current portion of the income tax expense in 2003 was $32.2 million
compared to $569,000 in 2002. These amounts are 58 percent and 4 percent of the
total tax for the respective periods. The difference resulted from increased
taxable income caused by significantly higher oil and gas prices and production,
and a reduction in the percentage of deductible intangible drilling costs
relative to total income.
Cumulative effect of change in accounting principal, net of income tax.
On January 1, 2003 we adopted SFAS No. 143. The impact of adoption resulted in
income to us of $8.8 million offset by the deferred income tax effect of $3.4
million. See Note 9 of the Notes to Consolidated Financial Statements under Part
IV, Item 15 of this report.
Other Liquidity and Capital Resource Information
Common Stock Activity
On January 29, 2003, we financed the acquisition of oil and gas
properties by issuing a total of 3,380,818 restricted shares of our common stock
to Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. In addition, we
made a non-recourse loan to Flying J and Big West in the amount of $71.6 million
at LIBOR plus 2 percent for up to a 39-month period. We also entered into a put
and call option agreement with Flying J whereby during the 39-month loan period
Flying J could elect to put these shares to us for $71.6 million plus accrued
interest on the loan during the first thirty months of the loan period, and we
could elect to call the shares for $97.4 million, with the proceeds from the
exercise of either the put option or the call option to be applied to the
repayment of the loan. For financial reporting purposes the above arrangements
were treated as an acquisition of properties in exchange for $71.6 million of
cash plus the net option to Flying J valued at $1.0 million, resulting in a
total valuation of $72.6 million. See Note 3 of Part IV, Item 15 of this report.
On February 9, 2004, we repurchased for $91.0 million the 3.4 million
restricted shares of common stock. Flying J used the proceeds to repay their
outstanding loan principal balance to us. Accrued interest on the loan, which
was not recorded by us for financial reporting purposes due to the non-recourse
nature of the loan, was forgiven. The $19.4 million net cash outlay was funded
from our existing cash balance and borrowings under our credit facility. See
Note 3 of Part IV, Item 15 of this report.
56
We reinitiated our stock repurchase program in August 2004. In the
third quarter of 2004 we repurchased a total of 489,300 shares of our common
stock for $16.3 million.
During 2004 we received net proceeds of $14.0 million from employee's
and director's options exercises on 699,526 shares of common stock.
Pension Benefits
Substantially all of our employees who meet age and service
requirements participate in a non-contributory defined benefit pension plan. At
December 31, 2004, we have recorded a $746,000 pre-tax loss in accumulated other
comprehensive income related to this plan. We believe this obligation will be
funded from future cash flow from operating activities. For purposes of
calculating our obligation under the plan, we have used an expected return on
plan assets of eight percent. We think this rate of return is appropriate over
the long-term given the 60 percent equity and 40 percent debt securities mix of
investment for plan assets and the historical rate of return provided by equity
and debt securities since the 1920s. Our estimated rate of return was 11.7
percent for 2004 and was 24.6 percent for 2003. The difference in investment
income using our projected rate of return compared to our actual rates of return
for the past two years was not material and will not have a material effect on
statements of operation or cash flow from operating activities in future years.
For the 2004 plan year, a 0.50 percentage point decrease in the
discount rate combined with a 0.50 percentage point increase in the rate of
future compensation increases caused a $971,000 increase in the projected
benefit obligation of the plan. We do not believe this change was material and
project that it will not have a material effect on the results of operations or
on cash flow from operating activities in future periods.
We also have a supplemental non-contributory defined benefit pension
plan that covers certain management employees. There are no plan assets for this
plan. For the 2004 plan year, a 0.50 percentage point decrease in the discount
rate combined with a 0.50 percentage point increase in the rate of future
compensation increases caused a $126,000 increase in the projected benefit
obligation for this plan. This plan's accumulated benefit obligation was $1.2
million at December 31, 2004, and 2003. We believe this obligation will be
funded from future cash flow from operating activities.
Accounting Matters
We recognized a $5.4 million gain net of income tax in 2003 from the
adoption of SFAS No. 143 effective January 1, 2003.
In December 2004 the FASB issued a revision to SFAS No. 123. See Note 7
of Part IV, Item 15 of this report for more detailed discussion regarding the
impact of adoption.
Environmental
St. Mary's compliance with applicable environmental regulations has not
resulted in any significant capital expenditures or materially adverse effects
to our liquidity or results of operations. We believe we are in substantial
compliance with environmental regulations and foresee that no material
expenditures will be incurred in the future. However, we are unable to predict
the impact that future compliance with regulations may have on future capital
expenditures, liquidity and results of operations.
57
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is provided under the captions
"Interest Rate Market Risk" and "Sensitivity Analysis" in Item 7 above and is
incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements that constitute Item 8 follow the
text of this report. An index to the Consolidated Financial Statements and
Schedules appears in Item 15(a) of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
We maintain a system of disclosure controls and procedures that are
designed to ensure that information required to be disclosed in our SEC reports
is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms, and to ensure that such information is
accumulated and communicated to our management, including the Chief Executive
Officer and the Vice-President - Finance, as appropriate to allow timely
decisions regarding required disclosure.
We carried out an evaluation, under the supervision and with the
participation of our management, including the Chief Executive Officer and the
Vice-President - Finance, of the effectiveness of the design and operation of
our disclosure controls and procedures as of the end of the period covered by
this Annual Report on Form 10-K. Based upon that evaluation, the Chief Executive
Officer and the Vice-President - Finance concluded that our disclosure controls
and procedures are effective for the purposes discussed above as of the end of
the period covered by this Annual Report on Form 10-K. There was no significant
change in our internal control over financial reporting that occurred during our
most recent fiscal quarter that has materially affected, or is reasonably likely
to materially affect, our internal control over financial reporting.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Stockholders' of St. Mary Land & Exploration Company
Management of the Company is responsible for establishing and maintaining
adequate internal control over financial reporting as defined in Rules 13a-15(f)
and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The
Company's internal control over financial reporting is designed to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. The Company's internal control over
financial reporting includes those policies and procedures that:
(i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the
assets of the Company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and
58
expenditures of the Company are being made only in accordance with
authorizations of management and directors of the Company; and
(iii) provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use or disposition of the Company's
assets that could have a material effect on the financial statements.
Because of the inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company's internal control
over financial reporting as of December 31, 2004. In making this assessment,
management used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in Internal Control-Integrated
Framework.
Based on our assessment and those criteria, management believes that the
Company maintained effective internal control over financial reporting as of
December 31, 2004.
The Company's independent auditors have issued an attestation report on
management's assessment of the Company's internal controls over financial
reporting. That report immediately follows this report.
/S/ MARK A. HELLERSTEIN /S/ DAVID W. HONEYFIELD
- ----------------------- -----------------------
Mark A. Hellerstein David W. Honeyfield
Chairman, CEO and President Vice President-Finance, Secretary &
February 23, 2005 Treasurer
February 23, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
St. Mary Land & Exploration Company and Subsidiaries
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting, that St. Mary
Land & Exploration Company and subsidiaries (the "Company") maintained
effective internal control over financial reporting as of December 31, 2004,
based on criteria established in Internal Control--Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission. The
Company's management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the Company's
internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
59
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by,
or under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper management
override of controls, material misstatements due to error or fraud may not be
prevented or detected on a timely basis. Also, projections of any evaluation of
the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that the controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, management's assessment that the Company maintained effective
internal control over financial reporting as of December 31, 2004, is fairly
stated, in all material respects, based on the criteria established in Internal
Control--Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Also in our opinion, the Company
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2004, based on the criteria established in Internal
Control--Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements as of and for the year ended December 31, 2004, of the Company, and
our report dated February 23, 2005, expressed an unqualified opinion on those
financial statements.
/S/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 23, 2005
60
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item concerning St. Mary's Directors
is incorporated by reference to the information provided under the captions
"Election of Directors" and "Nominees for Election of Directors" in St. Mary's
definitive proxy statement for the 2005 annual meeting of stockholders to be
filed within 120 days from December 31, 2004. The information required by this
Item concerning St. Mary's executive officers is incorporated by reference to
the information provided in Part I--Item 4A--EXECUTIVE OFFICERS OF THE
REGISTRANT, included in this Form 10-K.
The information required by this Item concerning compliance with
Section 16(a) of the Securities Exchange Act of 1934 is incorporated by
reference to the information provided under the caption "Section 16(a)
Beneficial Ownership Reporting Compliance" in St. Mary's definitive proxy
statement for the 2005 annual meeting of stockholders to be filed within 120
days from December 31, 2004.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to
the information provided under the captions, "Director Compensation," "Executive
Compensation," "Report of the Compensation Committee on Executive Compensation,"
"Retirement Plans," "Performance Graph," and "Employee Agreements and
Termination of Employment and Change-in-Control Arrangements" in St. Mary's
definitive proxy statement for the 2005 annual meeting of stockholders to be
filed within 120 days from December 31, 2004.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required by this Item concerning security ownership of
certain beneficial owners and management is incorporated by reference to the
information provided under the caption "Security Ownership of Certain Beneficial
Owners and Management" in St. Mary's definitive proxy statement for the 2005
annual meeting of stockholders to be filed within 120 days from December 31,
2004.
The information required by this Item concerning securities authorized
for issuance under equity compensation plans is incorporated by reference to the
information provided under the caption "Equity Compensation Plans" in Part II -
Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters,
included in this Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference to
the information provided under the caption "Certain Relationships and Related
Transactions" in St. Mary's definitive proxy statement for the 2005 annual
meeting of stockholders to be filed within 120 days from December 31, 2004.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated by reference to
the information provided under the caption "Independent Accountants" in St.
Mary's definitive proxy statement for the 2005 annual meeting of stockholders to
be filed within 120 days from December 31, 2004.
61
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
Audit Report of Independent Registered
Public Accounting Firm.................................... F-1
Consolidated Balance Sheets...................................... F-2
Consolidated Statements of Operations............................ F-3
Consolidated Statements of Stockholders'
Equity and Comprehensive Income........................... F-4
Consolidated Statements of Cash Flows............................ F-5
Notes to Consolidated Financial Statements....................... F-7
All other schedules are omitted because the required information is not
applicable or is not present in amounts sufficient to require submission of the
schedule or because the information required is included in the Consolidated
Financial Statements and Notes thereto.
(b) Exhibits. The following exhibits are filed with or incorporated by
reference into this report on Form 10-K:
Exhibit
Number Description
------ -----------
3.1 Restated Certificate of Incorporation of St. Mary Land &
Exploration Company as amended in May 2001 (filed as Exhibit
3.1 to the registrant's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001 and incorporated herein by
reference)
3.2 Restated By-Laws of St. Mary Land & Exploration Company as
amended on March 27, 2003 (filed as Exhibit 3.2 to the
registrant's Quarterly Report on Form 10-Q for the quarter
ended March 31, 2003 and incorporated herein by reference)
4.1 St. Mary Land & Exploration Company Shareholder Rights
Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the
registrant's Quarterly Report on Form 10-Q/A for the quarter
ended June 30, 1999 and incorporated herein by reference)
4.2 First Amendment to Shareholders Rights Plan dated March 15,
2002 as adopted by the Board of Directors on July 19, 2001
(filed as Exhibit 4.2 to the registrant's Annual Report on
Form 10-K for the year ended December 31, 2001 and
incorporated herein by reference)
10.1 St. Mary Land & Exploration Company Stock Option Plan, As
Amended on May 22, 2003 (filed as Exhibit 99.1 to the
registrant's Registration Statement on Form S-8 (Registration
No. 333-106438) and incorporated herein by reference)
10.2 St. Mary Land & Exploration Company Incentive Stock Option
Plan, As Amended on March 25, 1999, January 27, 2000, March
29, 2001, March 27, 2003 and May 22, 2003 (filed as Exhibit
99.2 to registrant's Registration Statement on Form S-8
(Registration No. 333-106438) and incorporated herein by
reference)
10.3 Cash Bonus Plan (filed as Exhibit 10.5 to the registrant's
Registration Statement on Form S-1 (Registration No.
33-53512) and incorporated herein by reference)
10.4 Summary Plan Description/Pension Plan dated December 30, 1994
(filed as Exhibit 10.35 to the registrant's Annual Report on
Form 10-K for the year ended December 31, 1994 and
incorporated herein by reference)
10.5 Non-qualified Unfunded Supplemental Retirement Plan, as
amended (filed as Exhibit 10.8 to the registrant's
Registration Statement on Form S-1 (Registration No. 33-53512)
and incorporated herein by reference)
62
Exhibit
Number Description
------ -----------
10.6 St. Mary Land & Exploration Company Employee Stock
Purchase Plan (filed as Exhibit 10.48 filed to the
registrant's Annual Report on Form 10-K (for the year ended
December 31, 1997 and incorporated herein by reference)
10.7 First Amendment to St. Mary Land & Exploration Company
Employee Stock Purchase Plan dated February 27, 2001 (filed
as Exhibit 10.1 to the registrant's Quarterly Report on Form
10-Q for the quarter ended June 30, 2001 and
incorporated herein by reference)
10.8 Form of Change of Control Severance Agreements (filed as
Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
for the quarter ended September 30, 2001 and incorporated
herein by reference)
10.9 Employment Agreement between Registrant and Mark A.
Hellerstein (filed as Exhibit 10.15 to the registrant's
Registration Statement on Form S-1 (Registration No. 33-53512)
and incorporated herein by reference)
10.10 Registration Rights Agreement between St. Mary Land &
Exploration Company and Bear, Stearns & Co. Inc., et al
dated March 13, 2002 (filed as Exhibit 10.25 to the
registrant's Annual Report on Form 10-K for the year ended
December 31, 2001 and incorporated herein by reference)
10.11 St. Mary Land & Exploration Company 5.75% Senior
Convertible Notes Due 2002 Indenture dated March 13, 2002
(filed as Exhibit 10.26 to the registrant's Annual Report on
Form 10-K for the year ended December 31, 2001 and
incorporated herein by reference)
10.12 Purchase and Sale Agreement dated October 1, 2002, effective
as of July 1, 2002, between Burlington Resources Oil & Gas
Company LP and The Louisiana Land and Exploration Company and
Nance Petroleum Corporation (filed as Exhibit to the
registrant's Current Report on Form 8-K filed on December 12,
2002 and incorporated herein by reference)
10.13 Purchase and Sale Agreement dated as of December 13, 2002
among Flying J Oil & Gas Inc., Big West Oil & Gas
Inc., NPC Inc. and St. Mary Land & Exploration Company
(filed as Exhibit 10.1 to the registrant's Current Report on
Form 8-K filed on February 13, 2003 and incorporated herein by
reference)
10.14 Addendum dated January 29, 2003 to Purchase and Sale Agreement
dated December 13, 2002 (filed as Exhibit 10.2 to the
registrant's Current Report on Form 8-K filed on February 13,
2003 and incorporated herein by reference)
10.15 Nonrecourse Secured Promissory Note dated January 29, 2003 by
Flying J Oil & Gas Inc. and Big West Oil & Gas Inc.
(filed as Exhibit 10.3 to the registrant's Current Report on
Form 8-K filed on February 13, 2003 and incorporated
herein by reference)
10.16 Stock Pledge Agreement from Flying J Oil & Gas Inc. and
Big West Oil & Gas Inc. to St. Mary Land & Exploration
Company executed as of January 29, 2003 (filed as Exhibit
10.4 to the registrant's Current Report on Form 8-K filed
on February 13, 2003 and incorporated herein by reference)
10.17 Registration Rights Agreement dated as of January 29, 2003
among St. Mary Land & Exploration Company, Flying J Oil
& Gas Inc. and Big West Oil & Gas Inc. (filed as
Exhibit 10.5 to the registrant's Current Report on Form 8-K
filed on February 13, 2003 and incorporated herein by
reference)
10.18 Put and Call Option Agreement dated as of January 29, 2003
among St. Mary Land & Exploration Company, Flying J Oil
& Gas Inc. and Big West Oil & Gas Inc. (filed as
Exhibit 10.6 to the registrant's Current Report on Form 8-K
filed on February 13, 2003 and incorporated herein by
reference)
63
Exhibit
Number Description
------ -----------
10.19 Standstill Agreement dated as of January 29, 2003 among St.
Mary Land & Exploration Company, Flying J Oil & Gas
Inc. and Big West Oil & Gas Inc. (filed as Exhibit 10.7 to
the registrant's Current Report on Form 8-K filed on
February 13, 2003 and incorporated herein by reference)
10.20 Share Transfer Restriction Agreement dated as of January 29,
2003 among St. Mary Land & Exploration Company, Flying
J Oil & Gas Inc. and Big West Oil & Gas Inc. (filed as
Exhibit 10.8 to the registrant's Current Report on Form 8-K
filed on February 13, 2003 and incorporated herein by
reference)
10.21 Indemnity Guarantee Agreement dated January 29, 2003 between
NPC Inc. and Flying J Inc. (filed as Exhibit 10.9 to
the registrant's Current Report on Form 8-K filed on February
13, 2003 and incorporated herein by reference)
10.22 Security Agreement made as of May 1, 2002 by St. Mary Land
& Exploration Company, St. Mary Operating Company, St.
Mary Energy Company, Nance Petroleum Corporation, St. Mary
Minerals Inc., Parish Corporation, Four Winds Marketing LLC,
and Roswell LLC, in favor of Bank of America, N.A. (filed as
Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
for the quarter ended June 30, 2002 and incorporated
herein by reference)
10.23 Stock Pledge Agreement made as of May 1, 2002 by St. Mary Land
& Exploration Company in favor of Bank of America, N.A.
(filed as Exhibit 10.2 to the registrant's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2002 and incorporated
herein by reference)
10.24 LLC Pledge Agreement made as of May 1, 2002 by St. Mary Land
& Exploration Company in favor of Bank of America, N.A.
(filed as Exhibit 10.3 to the registrant's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2002 and incorporated
herein by reference)
10.25 Guaranty made as of May 1, 2002 by St. Mary Operating Company,
St. Mary Energy Company, Nance Petroleum Corporation, St. Mary
Minerals, Inc., Parish Corporation, Four Winds Marketing LLC
and Roswell LLC in favor of Bank of America, N.A. (filed as
Exhibit 10.4 to the registrant's Quarterly Report on Form 10-Q
for the quarter ended June 30, 2002 and incorporated herein by
reference)
10.26 Credit Agreement dated as of January 27, 2003 among St. Mary
Land & Exploration Company, Wachovia Bank, National
Association of Administrative Agent, and the Lenders party
thereto (filed as Exhibit 10.44 to the registrant's Annual
Report on Form 10-K for the year ended December 31, 2003 and
incorporated herein by reference)
10.27 Amendment to and Extension of Office Lease dated as of
December 14, 2001 (filed as Exhibit 10.45 to the registrant's
Annual Report on Form 10-K for the year ended December 31,
2003 and incorporated herein by reference)
10.28 St. Mary Land & Exploration Company Non-Employee Director
Stock Compensation Plan as adopted on March 27, 2003 (filed as
Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
for the quarter ended June 30, 2003 and incorporated herein by
reference)
10.29 Guaranty Agreement by St. Mary Energy Company in favor of
Wachovia Bank, National Association, as Administrative Agent,
dated January 27, 2003 (filed as Exhibit 10.4 to the
registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2003 and incorporated herein by reference)
10.30 Guaranty Agreement by St. Mary Operating Company in favor of
Wachovia Bank, National Association, as Administrative Agent,
dated January 27, 2003 (filed as Exhibit 10.5 to the
registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2003 and incorporated herein by reference)
64
Exhibit
Number Description
------ -----------
10.31 Guaranty Agreement by Nance Petroleum Corporation in favor of
Wachovia Bank, National Association, as Administrative Agent,
dated January 27, 2003 (filed as Exhibit 10.6 to the
registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2003 and incorporated herein by reference)
10.32 Guaranty Agreement by NPC Inc. in favor of Wachovia Bank,
National Association, as Administrative Agent, dated January
27, 2003 (filed as Exhibit 10.7 to the registrant's Quarterly
Report on Form 10-Q for the quarter ended June 30, 2003 and
incorporated herein by reference)
10.33 Pledge and Security Agreement between St. Mary Land &
Exploration Company and Wachovia Bank, National Association,
as Administrative Agent, dated January 27, 2003 (filed as
Exhibit 10.8 to the registrant's Quarterly Report on Form 10-Q
for the quarter ended June 30, 2003 and incorporated herein by
reference)
10.34 Pledge and Security Agreement between Nance Petroleum
Corporation and Wachovia Bank, National Association, as
Administrative Agent, dated January 27, 2003 (filed as Exhibit
10.9 to the registrant's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2003 and incorporated herein by
reference)
10.35 First Supplement and Amendment to Deed of Trust, Mortgage,
Line of Credit Mortgage, Assignment, Security Agreement,
Fixture Filing and Financing Statement for the benefit of
Wachovia Bank, National Association, as Administrative Agent,
dated effective as of January 27, 2003 (filed as Exhibit 10.10
to the registrant's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2003 and incorporated herein by
reference)
10.36 Deed of Trust - St. Mary Land & Exploration to Wachovia
Bank, National Association, as Administrative Agent, dated
effective as of January 27, 2003 (filed as Exhibit 10.11 to
the registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2003 and incorporated herein by reference)
10.37 Deed of Trust (CO, NV, SD) to Wachovia Bank, National
Association, as Administrative Agent, dated effective as of
April 2003 (filed as Exhibit 10.12 to the registrant's
Quarterly Report on Form 10-Q for the quarter ended June 30,
2003 and incorporated herein by reference)
10.38 Deed of Trust (LA, MT, ND, NM, OK, TX, UT, WY) to Wachovia
Bank, National Association, as Administrative Agent, dated
effective as of April 2003 (filed as Exhibit 10.13 to the
registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2003 and incorporated herein by reference)
10.39 First Supplement and Amendment to Deed of Trust, Mortgage,
Line of Credit Mortgage, Assignment, Security Agreement,
Fixture Filing and Financing Statement for the benefit of
Wachovia Bank, National Association, as Administrative Agent,
dated effective as of April 2003 (filed as Exhibit 10.14 to
the registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2003 and incorporated herein by reference)
10.40 Second Supplement and Amendment to Deed of Trust, Mortgage,
Line of Credit Mortgage, Assignment, Security Agreement,
Fixture Filing and Financing Statement for the benefit of
Wachovia Bank, National Association, as Administrative Agent,
dated effective as of April 2003 (filed as Exhibit 10.15 to
the registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2003 and incorporated herein by reference)
65
Exhibit
Number Description
------ -----------
10.41 First Amendment to Credit Agreement dated January 27, 2003
among St. Mary Land & Exploration Company, Wachovia Bank,
National Association as Issuing Bank and Administrative Agent,
and the Lenders party thereto (filed as Exhibit 10.41 to the
registrant's Annual Report on Form 10-K for the year ended
December 31, 2003 and incorporated herein by reference)
10.42 Net Profits Interest Bonus Plan, As Amended on February 3,
2004 (filed as Exhibit 10.42 to the registrant's Annual Report
on Form 10-K for the year ended December 31, 2003 and
incorporated herein by reference)
10.43 St. Mary Land & Exploration Company Restricted Stock Plan
as adopted on April 18, 2004 (filed as Exhibit 10.1 to the
registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2004 and incorporated herein by reference)
10.44 Second Amendment to Credit Agreement dated September 20, 2004
among St. Mary Land & Exploration Company, Wachovia Bank,
National Association as Issuing Bank and Administrative Agent,
and the Lenders party thereto (filed as Exhibit 10.1 to the
registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2004 and incorporated herein by reference)
10.45 Third Amendment to Credit Agreement dated October 20, 2004
among St. Mary Land & Exploration Company, Wachovia Bank,
National Association as Issuing Bank and Administrative Agent,
and the Lenders party thereto (filed as Exhibit 10.2 to the
registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2004 and incorporated herein by reference)
10.46 Form of Restricted Stock Unit Award Memorandum under the St.
Mary Land & Exploration Company Restricted Stock Plan
(filed as Exhibit 10.3 to the registrant's Quarterly Report on
Form 10-Q for the quarter ended September 30, 2004 and
incorporated herein by reference)
10.47* Attachment A to Form of Change of Control Severance Agreement
10.48* Second Amendment to the St. Mary Land & Exploration
Employee Stock Puchase Plan dated February 18, 2005
12.1* Computation of Ratio of Earnings to Fixed Charges
14.1 Code of Business Conduct and Ethics
21.1* Subsidiaries of Registrant
23.1* Consent of Deloitte & Touche LLP
23.2* Consent of Ryder Scott Company, L.P.
23.3* Consent of Netherland, Sewell & Associates, Inc.
24.1* Power of Attorney (included in signature page hereof)
31.1* Certification of Chief Executive Officer pursuant to Section
302 of the Sarbanes - Oxley Act of 2002
31.2* Certification of Vice President - Finance pursuant to Section
302 of the Sarbanes - Oxley Act of 2002
32.1* Certification pursuant to U.S.C. Section 1350 as adopted
pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
- ----------------------------
* Filed with this Form 10-K.
(c) Financial Statement Schedules. See Item 15(a) above.
66
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
St. Mary Land & Exploration Company and Subsidiaries
We have audited the accompanying consolidated balance sheets of St. Mary Land
& Exploration Company and subsidiaries (the "Company") as of December 31,
2004 and 2003, and the related consolidated statements of operations,
stockholders' equity and comprehensive income, and cash flows for each of the
three years in the period ended December 31, 2004. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of St. Mary Land & Exploration
Company and subsidiaries as of December 31, 2004 and 2003, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2004, in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note 9 to the consolidated financial statements, the Company
changed its method of accounting for asset retirement obligations in 2003 with
the implementation of Statement of Financial Accounting Standards No. 143
"Accounting for Asset Retirement Obligations".
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of the Company's
internal control over financial reporting as of December 31, 2004, based on the
criteria established in Internal Control--Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission, and our report
dated February 23, 2005, expressed an unqualified opinion on management's
assessment of the effectiveness of the Company's internal control over financial
reporting and an unqualified opinion on the effectiveness of the Company's
internal control over financial reporting.
/S/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 23, 2005
F-1
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
December 31,
------------------------------
ASSETS 2004 2003
------------ ------------
Current assets:
Cash and cash equivalents $ 6,418 $ 14,827
Short-term investments 1,412 12,509
Accounts receivable 104,964 64,540
Prepaid expenses and other 5,863 6,564
Deferred income taxes - 8,872
Accrued derivative asset 8,270 157
Other - 454
------------ ------------
Total current assets 126,927 107,923
------------ ------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 1,124,810 858,246
Less - accumulated depletion, depreciation and amortization (399,013) (312,719)
Unproved oil and gas properties, net of impairment allowance
of $9,867 in 2004 and $10,776 in 2003 41,969 36,793
Wells in progress 35,515 24,691
Other property and equipment, net of accumulated depreciation
of $6,459 in 2004 and $4,656 in 2003 5,244 4,276
------------ ------------
808,525 611,287
------------ ------------
------------ ------------
Other noncurrent assets 10,008 16,644
------------ ------------
------------ ------------
Total Assets $ 945,460 $ 735,854
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 110,117 $ 81,217
Accrued derivative liability 2,502 23,605
Deferred income taxes 2,273 -
------------ ------------
Total current liabilities 114,892 104,822
------------ ------------
Noncurrent liabilities:
Long-term credit facility 37,000 11,000
Convertible notes 99,791 99,696
Asset retirement obligation 40,911 25,485
Net Profits Plan liability 30,561 6,163
Deferred income taxes 129,830 90,947
Other noncurrent liabilities 8,020 7,088
------------ ------------
Total noncurrent liabilities 346,113 240,379
------------ ------------
Commitments and contingencies (Note 6):
Temporary equity (Note 3):
Common stock subject to put and call options, $0.01 par value;
issued and outstanding: -0- shares in 2004 and 3,380,818 shares
in 2003 - 71,594
Note receivable from Flying J - (71,594)
------------ ------------
Total temporary equity - -
------------ ------------
Stockholders' equity:
Common stock, $0.01 par value: authorized - 100,000,000 shares;
issued: 28,729,123 shares in 2004 and 29,245,123 shares in 2003;
outstanding, net of treasury shares: 28,479,123 shares in 2004
and 28,242,423 shares in 2003 287 292
Additional paid-in capital 127,661 146,362
Treasury stock, at cost: 250,000 shares in 2004 and 1,002,700
shares in 2003 (5,295) (16,057)
Deferred stock-based compensation (5,039) -
Retained earnings 364,567 274,937
Accumulated other comprehensive income (loss) 2,274 (14,881)
------------ ------------
Total stockholders' equity 484,455 390,653
------------ ------------
------------ ------------
Total Liabilities and Stockholders' Equity $ 945,460 $ 735,854
============ ============
The accompanying notes are an integral part to these
consolidated financial statements.
F-2
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share amounts)
For the Years Ended December 31,
--------------------------------------------------
2004 2003 2002
-------------- -------------- --------------
Operating revenues:
Oil and gas production $ 463,617 $ 387,553 $ 187,905
Oil and gas hedge loss (50,299) (22,439) (2,235)
Gain(loss) on sale of proved properties 1,803 7,278 (2,633)
Marketed gas revenue 15,551 13,438 8,399
Other oil and gas revenue 2,342 3,538 682
Derivative gain - - 3,188
Other revenue 85 4,340 999
-------------- -------------- --------------
Total operating revenues 433,099 393,708 196,305
-------------- -------------- --------------
Operating expenses:
Oil and gas production 95,518 88,509 50,839
Depletion, depreciation, amortization
and abandonment liability accretion 92,223 81,960 54,432
Exploration 28,560 25,318 19,271
Impairment of proved properties 494 185 -
Abandonment and impairment of unproved properties 1,420 3,796 2,446
General and administrative 22,004 21,197 13,683
Change in Net Profits Plan liability 24,398 5,317 846
Marketed gas system operating expense 14,230 12,229 7,982
Derivative loss 260 310 -
Other 2,077 1,576 1,117
-------------- -------------- --------------
Total operating expenses 281,184 240,397 150,616
-------------- -------------- --------------
Income from operations 151,915 153,311 45,689
Nonoperating income(expense):
Interest income 557 717 758
Interest expense (6,244) (7,958) (3,868)
Income before income taxes and cumulative effect
of change in accounting principle 146,228 146,070 42,579
Income tax expense (53,749) (55,930) (15,019)
-------------- -------------- --------------
Income before cumulative effect of change in accounting principle 92,479 90,140 27,560
Cumulative effect of change in accounting principle,
net of income tax - 5,435 -
-------------- -------------- --------------
Net income $ 92,479 $ 95,575 $ 27,560
============== ============== ==============
Basic weighted-average common shares outstanding 28,851 31,233 27,856
Diluted weighted-average common shares outstanding 33,447 35,534 28,391
Basic earnings per common share:
Income before cumulative effect of change in accounting principle $ 3.21 $ 2.89 $ 0.99
Cumulative effect of change in accounting
principle, net of income tax - 0.17 -
-------------- ------------- --------------
Basic net income per common share $ 3.21 $ 3.06 $ 0.99
============== ============= ==============
Diluted earnings per common share:
Income before cumulative effect of change in accounting principle $ 2.88 $ 2.65 $ 0.97
Cumulative effect of change in accounting
principle, net of income tax - 0.15 -
-------------- -------------- --------------
Diluted net income per common share $ 2.88 $ 2.80 $ 0.97
============== ============== ==============
Cash dividends declared per common share $ 0.10 $ 0.10 $ 0.10
============== ============== ==============
The accompanying notes are an integral part to these
consolidated financial statements.
F-3
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(In thousands, except share amounts)
Accumulated
Common Stock Additional Treasury Stock Deferred Other Total
----------------- Paid-in --------------------- Stock-Based Retained Comprehensive Stockholders'
Shares Amount Capital Shares Amount Compensation Earnings Income (Loss) Equity
---------- ------ --------- ----------- --------- ------------ -------- ------------- -------------
Balances, December 31, 2001 28,779,808 $ 288 $137,384 (1,009,900) $(16,210) $ - $157,739 $ 6,916 $ 286,117
Comprehensive income:
Net income - - - - - - 27,560 - 27,560
Unrealized net loss on
marketable equity
securities available
for sale - - - - - - - (725) (725)
Change in derivative
instrument fair value - - - - - - - (14,644) (14,644)
Reclassification to earnings - - - - - - - 1,447 1,447
Minimum pension liability
adjustment - - - - - - - (761) (761)
-------------
Total comprehensive income 12,877
-------------
Cash dividends declared, $ 0.10
per share - - - - - - (2,787) - (2,787)
Issuance of common stock
under Employee Stock
Purchase Plan 18,217 - 344 - - - - - 344
ESPP disqualified distribution - - 21 - - - - - 21
Sale of common stock, including
income tax benefit of
stock option exercises 177,085 2 2,743 - - - - - 2,745
Accelerated vesting of retiring
director's options - - 52 - - - - - 52
Directors' stock compensation 8,000 - 144 - - - - - 144
---------- ------ --------- ----------- --------- ------------ -------- ------------- -------------
Balances, December 31, 2002 28,983,110 $ 290 $140,688 (1,009,900) $(16,210) $ - $182,512 $ (7,767) $ 299,513
Comprehensive income:
Net income - - - - - - 95,575 - 95,575
Unrealized net
gain on marketable
equity securities
available for sale - - - - - - - 716 716
Change in derivative
instrument fair value - - - - - - - (21,873) (21,873)
Reclassification to earnings - - - - - - - 13,846 13,846
Minimum pension liability
adjustment - - - - - - - 197 197
-------------
Total comprehensive income 88,461
-------------
Cash dividends declared, $ 0.10
per share - - - - - - (3,150) - (3,150)
Issuance of common stock
under Employee Stock
Purchase Plan 16,994 - 375 - - - - - 375
Value of option right granted
to Flying J - - 995 - - - - - 995
Sale of common stock, including
income tax benefit of
stock option exercises 245,019 2 4,304 - - - - - 4,306
Directors' stock compensation - - - 7,200 153 - - - 153
---------- ------ --------- ----------- --------- ------------ -------- ------------- -------------
Balances, December 31, 2003 29,245,123 $ 292 $146,362 (1,002,700) $(16,057) $ - $274,937 $ (14,881) $ 390,653
Comprehensive income:
Net income - - - - - - 92,479 - 92,479
Change in derivative
instrument fair value - - - - - - - (14,795) (14,795)
Reclassification to earnings - - - - - - - 31,849 31,849
Minimum pension liability
adjustment - - - - - - - 101 101
-------------
Total comprehensive income 109,634
-------------
Cash dividends declared, $ 0.10
per share - - - - - - (2,849) - (2,849)
Repurchase of common stock from
Flying J - - (19,406) - - - - - (19,406)
Treasury stock purchases - - - (489,300) (16,336) - - - (16,336)
Retirement of treasury stock (1,229,400) (12) (26,737) 1,229,400 26,749 - - - -
Issuance of common stock
under Employee Stock
Purchase Plan 13,874 - 375 - - - - - 375
Sale of common stock, including
income tax benefit of
stock option exercises 699,526 7 17,839 - - - - - 17,846
Deferred compensation related to
issued restricted stock
unit awards - - 8,122 - - (8,122) - - -
Accrued stock-based compensation - - 1,106 - - - - - 1,106
Amortization of deferred
stock-based compensation - - - - - 3,083 - - 3,083
Directors' stock compensation - - - 12,600 349 - - - 349
---------- ------ --------- ----------- --------- ------------ -------- ------------- -------------
Balances, December 31, 2004 28,729,123 $ 287 $127,661 (250,000) $ (5,295) $ (5,039) $364,567 $ 2,274 $ 484,455
========== ====== ========= =========== ========= ============ ======== ============= =============
The accompanying notes are an integral part to these
consolidated financial statements.
F-4
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
--------------------------------------------------
2004 2003 2002
-------------- -------------- --------------
Reconciliation of net income to net cash provided by operating activities:
Net income $ 92,479 $ 95,575 $ 27,560
Adjustments to reconcile net income to net cash
provided by operating activities:
(Gain) loss on sale of proved properties (1,803) (7,278) 2,633
Depletion, depreciation, amortization
and abandonment liability accretion 92,223 81,960 54,432
Exploratory dry hole expense 4,162 8,482 7,677
Impairment of proved properties 494 185 -
Abandonment and impairment of unproved properties 1,420 3,796 2,446
Unrealized derivative loss 260 310 373
Change in Net Profits Plan liability 24,398 5,317 846
Deferred and accrued stock-based compensation 4,189 - -
Income tax benefit from the exercise of stock options 3,816 1,151 719
Deferred income taxes 39,573 20,536 13,914
Other (1,948) 2,088 (1,642)
Cumulative effect of change in accounting principle, net of tax - (5,435) -
Changes in current assets and liabilities:
Accounts receivable (39,880) (29,685) 11,085
Prepaid expenses and other 157 490 (4,173)
Accounts payable and accrued expenses 17,622 26,827 25,839
-------------- -------------- --------------
Net cash provided by operating activities 237,162 204,319 141,709
-------------- -------------- --------------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 2,829 23,497 1,624
Capital expenditures (199,385) (123,823) (97,257)
Acquisition of oil and gas properties, including related
$71,594 loan to Flying J in 2003 (68,805) (76,413) (87,466)
Deposits to short-term investments available-for-sale (1,470) (12,529) (13,523)
Receipts from short-term investments available-for-sale 12,500 2,450 12,538
Receipts from restricted cash 10,353 11,500 -
Deposits to restricted cash - (21,853) -
Other (3,028) 232 3,153
-------------- -------------- --------------
Net cash used in investing activities (247,006) (196,939) (180,931)
-------------- -------------- --------------
Cash flows from financing activities:
Proceeds from credit facility 181,497 140,933 37,400
Repayment of credit facility (155,500) (145,020) (87,400)
Proceeds from issuanace of convertible debt - - 96,657
Proceeds from sale of common stock for exercise of stock options 14,030 3,530 2,390
Repurchase of common stock (35,743) - -
Dividends paid (2,849) (3,150) (2,787)
-------------- -------------- --------------
Net cash provided by (used in) financing activities 1,435 (3,707) 46,260
-------------- -------------- --------------
Net change in cash and cash equivalents (8,409) 3,673 7,038
Cash and cash equivalents at beginning of period 14,827 11,154 4,116
-------------- -------------- --------------
Cash and cash equivalents at end of period $ 6,418 $ 14,827 $ 11,154
============== ============== ==============
The accompanying notes are an integral part to these
consolidated financial statements.
F-5
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(In thousands)
Supplemental schedule of additional cash flow information and noncash investing
and financing activities:
For the Years Ended December 31,
--------------------------------------------------
2004 2003 2002
-------------- -------------- --------------
(in thousands)
Cash paid for interest, including amounts capitalized $ 8,859 $ 7,555 $ 2,498
Cash paid (refunded) for income taxes 14,787 28,858 (550)
In August 2004 the Company closed a transaction whereby it exchanged oil and gas
properties valued at $1.4 million together with $769,000 of cash for oil and gas
properties valued at $2.2 million.
In June 2004 the Company issued 232,861 restricted stock units pursuant to the
Company's restricted stock plan. The total value of the grant was $8.3 million,
which as of December 31, 2004 has been reduced by $178,000 for forfeitures. The
Company has recorded compensation expense related to the 2004 grant of $3.1
million for the year ended December 30, 2004.
In January 2004 and May 2004 the Company issued 4,200 shares and 8,400 shares,
respectively, of common stock from treasury to its non-employee directors
pursuant to the Company's non-employee director stock compensation plan. The
Company recorded compensation expense of $349,000 for year ended December 31,
2004.
In January 2003 the Company issued 7,200 shares of common stock from treasury to
its non-employee directors and recorded compensation expense of $153,000.
In January 2003 the Company issued 3,380,818 restricted shares of common stock
to Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. (collectively,
"Flying J") and entered into a put and call option agreement, valued at $995,000
for financial reporting purposes, with Flying J with respect to those shares in
connection with the acquisition of oil and gas properties and related assets and
liabilities.
In June 2002 the Company issued 800 shares of common stock to a non-employee
director and recorded compensation expense of $14,763.
In April 2002 the Company accepted 9,472,562 shares of common stock in
Constellation Copper Corporation ("Constellation", formerly known as Summo
Minerals Corporation) in lieu of cash payment for the relief of a $1,400,000
loan and $15,311 in interest due to the Company.
In January 2002 the Company issued 7,200 shares of common stock to its
non-employee directors and recorded compensation expense of $129,683.
The accompanying notes are an integral part to these
consolidated financial statements.
F-6
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004
Note 1 - Summary of Significant Accounting Policies
Description of Operations
St. Mary Land & Exploration Company ("St. Mary" or the "Company")
is an independent energy company engaged in the exploration, exploitation,
development, acquisition and production of natural gas and crude oil. The
Company's operations are conducted entirely in the continental United States.
Basis of Presentation
The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. Subsidiaries that are not wholly
owned are accounted for using full consolidation with minority interest or by
the equity or cost method as appropriate. Equity method investments are included
in other noncurrent assets, and minority interest is included in other
noncurrent liabilities in the accompanying consolidated balance sheets. All
significant intercompany accounts and transactions have been eliminated
Certain amounts in 2003 and 2002 financial statements have been
reclassified to conform to the 2004 financial statement presentation. The
non-cash portion of Net Profits Interest Bonus Plan (the "Net Profits Plan")
expense and the corresponding liability have been reclassified as separate line
items in the accompanying financial statements for all periods presented. As a
result, prior period general and administrative expense, exploration expense and
other non-current liabilities have been reclassified to conform to the current
presentation. Additionally, wells in progress have been classified as a separate
line item in the consolidated balance sheets for all periods presented. As a
result, prior period unproved oil and gas properties, net of impairment
allowance, have been reclassified to conform to the current presentation.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of oil and gas
reserves, assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates
Cash and Cash Equivalents
The Company considers all liquid investments purchased with an initial
maturity of three months or less to be cash equivalents. The carrying value of
cash and cash equivalents approximates fair value due to the short-term nature
of these instruments.
F-7
Short-term Investments
The Company's short-term investments consist primarily of
investment-grade marketable debt, which is classified as available-for-sale.
Securities that have been categorized as available-for-sale are stated at fair
value based on quoted market prices. The following table summarizes the
estimated fair value of the components of the Company's available-for-sale
short-term investments:
As of December 31,
----------------------------------------
2004 2003
----------------- ----------------
(in thousands)
Corporate debt securities $ 1,412 $ 1,009
Escrowed cash $ - $ 11,500
----------------- ----------------
Total $ 1,412 $ 12,509
================= ================
Concentration of Credit Risk
Substantially all of the Company's receivables are within the oil and
gas industry, primarily from purchasers of oil and gas and from joint interest
owners. Although diversified among many companies, collectability is dependent
upon the financial wherewithal of each individual company as well as the general
economic conditions of the industry. The receivables are not collateralized. To
date the Company has had minimal bad debts.
The Company has accounts with separate banks in Denver, Colorado;
Shreveport, Louisiana; Tulsa, Oklahoma; Houston, Texas; and Billings, Montana.
At December 31, 2004, 2003 and 2002, the Company had $22.2 million, $23.5
million, and $4.9 million respectively, invested in money market funds
(including margin accounts) consisting of corporate commercial paper, repurchase
agreements and U.S. Treasury obligations. The difference between the investment
amount and the cash and cash equivalents amount on the consolidated balance
sheets, represents uncleared disbursements. The Company's policy is to invest in
highly rated instruments and to limit the amount of credit exposure at each
individual institution.
Oil and Gas Producing Activities
The Company follows the successful efforts method of accounting for its
oil and gas properties. Under this method of accounting, all property
acquisition costs and costs of exploratory and development wells are capitalized
when incurred, pending determination of whether the well has found proved
reserves. If an exploratory well does not find proved reserves, the costs of
drilling the well are charged to expense. Exploratory dry hole costs are
included in cash flows from investing activities as part of capital expenditures
within the consolidated statements of cash flows. The costs of development wells
are capitalized whether productive or nonproductive. The Company had no
exploratory well costs that had been suspended for one year or more as of
December 31, 2004 or 2003.
Geological and geophysical costs and the costs of carrying and
retaining unproved properties are expensed as incurred. Depletion, depreciation
and amortization ("DD&A") of capitalized costs of proved oil and gas
properties is provided on a field-by-field basis using the units of production
method based upon proved reserves. The computation of DD&A takes into
consideration restoration, dismantlement and abandonment costs and the
anticipated proceeds from equipment salvage. As of December 31, 2004, the
Company's capitalized proved oil and gas properties included $51.2 million of
estimated salvage value, which is excluded from the Company's DD&A
calculation. On January 1, 2003, the Company adopted the provisions of Statement
of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset
Retirement Obligations," which provides guidance on accounting for dismantlement
and abandonment costs (see Note 9 - Asset Retirement Obligations).
F-8
The Company reviews its long-lived assets for impairments when events
or changes in circumstances indicate that an impairment may have occurred. The
impairment test for proved properties compares the expected undiscounted future
net revenues on a field-by-field basis with the related net capitalized costs at
the end of each period. Expected future cash flows are calculated on all proved
reserves using a discount rate and price forecasts selected by the Company's
management. The discount rate is a rate that management believes is
representative of current market conditions. The price forecast is based on
NYMEX strip pricing for the first three years and is then escalated to specified
maximum prices. Operating costs are escalated in these estimates. When the net
capitalized costs exceed the undiscounted future net revenues of a field, the
cost of the field is reduced to fair value, which is determined using discounted
future net revenues. An impairment allowance is provided on unproved property
when the Company determines that the property will not be developed or that the
carrying value is not realizable.
Sales of Proved and Unproved Properties
The sale of a partial interest in a proved property is accounted for as
normal retirement, and no gain or loss is recognized as long as this treatment
does not significantly affect the units-of-production depletion rate. A gain or
loss is recognized for all other sales of producing properties and is included
in the results of operations.
The sale of a partial interest in an unproved property is accounted for
as a recovery of cost when substantial uncertainty exists as to recovery of the
cost applicable to the interest retained. A gain on the sale is recognized to
the extent that the sales price exceeds the carrying amount of the unproved
property. A gain or loss is recognized for all other sales of nonproducing
properties and is included in the results of operations.
Other Property and Equipment
Other property and equipment such as office furniture and equipment,
automobiles and computer hardware and software is recorded at cost. Costs of
renewals and improvements that substantially extend the useful lives of the
assets are capitalized. Maintenance and repairs are expensed when incurred.
Depreciation is provided using the straight-line method over the estimated
useful lives of the assets from three to 15 years. When other property and
equipment is sold or retired, the capitalized costs and related accumulated
depreciation are removed from the accounts.
Gas Balancing
The Company uses the sales method to account for gas imbalances. Under
this method, revenue is recorded based on gas actually sold by the Company. The
Company records revenue for its share of gas sold by other owners that cannot be
volumetrically balanced in the future due to insufficient remaining reserves.
Related receivables totaling $1.5 million at December 31, 2004, and $1.2 million
at December 31, 2003, are included in other noncurrent assets in the
accompanying consolidated balance sheets. The Company also reduces revenue for
gas sold by the Company that cannot be volumetrically balanced in the future due
to insufficient remaining reserves. Related payables totaling $726,000 at
December 31, 2004, and $500,000 at December 31, 2003, are included in other
noncurrent liabilities in the accompanying consolidated balance sheets.
Receivables and payables are valued based on prices used in recent settlements
between the Company and its imbalance counterparties, and receivables are
recorded net of collection allowance. The Company's remaining overproduced and
underproduced gas balancing positions are considered in the Company's proved oil
and gas reserves (see Note 12 - Disclosures about Oil and Gas Producing
Activities).
F-9
Derivative Financial Instruments
The Company seeks to protect its rate of return on acquisitions of
producing properties, and other production by hedging cash flows. The Company
intends for derivative instruments used for this purpose to be designated as,
and to qualify as, cash flow hedging instruments under SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities," and related pronouncements.
The Company generally limits its aggregate hedge position to no more than 50
percent of its total production but will hedge larger percentages of total
production in certain circumstances. The Company seeks to minimize basis risk
and indexes the majority of its oil hedges to NYMEX prices and the majority of
its gas hedges to various regional index prices associated with pipelines in
proximity to the Company's areas of gas production.
The Company's hedge positions are diversified with various
counterparties, and the Company requires that such counterparties have clear
indications of current financial strength. See Note 10 - Derivative Financial
Instruments for additional discussion of derivatives.
Fair Value of Financial Instruments
The Company's financial instruments including cash and cash
equivalents, restricted cash, accounts receivable and accounts payable are
carried at cost, which approximates fair value due to the short-term maturity of
these instruments. The recorded value of the Company's credit facility
approximates its fair value as it bears interest at a floating rate. The
Company's interest rate swaps are recorded at fair value as discussed in Note 10
- - Derivative Financial Instruments. The Company's 5.75% Senior Convertible Notes
Due 2022 (the "Convertible Notes") are recorded at cost, and the fair value is
disclosed in Note 5 - Long-Term Debt. The Company's other financial instruments
and investments in available-for-sale securities are marked to market with
changes in fair value being recorded in accumulated other comprehensive income.
Since considerable judgment is required to develop estimates of fair value, the
estimates provided are not necessarily indicative of the amounts the Company
could realize upon the sale or refinancing of such instruments.
Net Profits Plan
The Company records the estimated liability of future payments under
its Net Profits Plan because it is a vested employee benefit. The estimated
liability is calculated based on a number of assumptions, including estimates of
oil and gas reserves, recurring and workover lease operating expense, tax rates,
present value discount factors and certain pricing assumptions. The estimates
the Company uses in calculating the liability are modified from period to period
based on new information attributable to the underlying assumptions. Changes in
the estimated liability of future payments associated with the Net Profits Plan
are recorded as increases or decreases to expense in the current period as a
separate line item in the consolidated statements of operations. The estimated
Net Profits Plan liability is recorded separately as a noncurrent liability in
the accompanying consolidated balance sheets.
The amounts due and payable under the Net Profits Plan as cash
compensation related to the current period operations are recognized as
compensation expense and are included within general and administrative expense
and exploration expense. The corresponding current liability is included in
accounts payable and accrued expenses in the accompanying consolidated balance
sheets. This treatment provides for a consistent matching of cash expense with
net cash flows from the oil and gas properties in each respective pool of the
Net Profits Plan.
Income Taxes
Deferred income taxes are provided on the difference between the tax
basis of an asset or liability and its carrying amount in the financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered or
settled, respectively.
F-10
Earnings Per Share
Basic net income per common share of stock is calculated by dividing
net income available to common stockholders by the weighted-average of common
shares outstanding during each period.
During the first quarter of 2003, the Company issued 3,380,818 shares
of common stock as part of an acquisition. On February 9, 2004, the Company
repurchased and retired these shares (see Note 11-Repurchase of St. Mary Common
Stock). These shares were considered outstanding from January 29, 2003, to
February 9, 2004, for purposes of calculating basic and diluted net income per
common share and were weighted accordingly in the calculation of common shares
outstanding. The shares were included in the temporary equity section of the
consolidated balance sheet as of December 31, 2003.
Diluted net income per common share of stock is calculated by dividing
adjusted net income by the weighted-average of common shares outstanding,
including the effect of other dilutive securities. Adjusted net income is used
for the if-converted method and is derived by adding interest expense paid on
the Convertible Notes back to net income and then adjusting for nondiscretionary
items that are based on income and that would have changed had the Convertible
Notes been converted at the beginning of the period. Potentially dilutive
securities of the Company consist of in-the-money outstanding options to
purchase the Company's common stock, shares into which the Convertible Notes may
be converted and unvested restricted stock units.
The shares underlying the grants of restricted stock units are excluded
from basic and diluted earnings per share until the measurement date for grants
made under the Restricted Stock Plan. Upon measurement, all unvested shares
attributable to the restricted stock unit grant are included in the diluted
share calculation. Vested shares are included in both basic and diluted earnings
per share.
The treasury stock method is used to measure the dilutive impact of
stock options. The following table details the weighted-average dilutive and
anti-dilutive securities related to stock options for the periods presented:
For the Years Ended December 31,
------------------------------------------------------------
2004 2003 2002
---------------- --------------- ---------------
Dilutive 749,644 455,055 534,610
Anti-dilutive 93 713,382 1,539,227
The dilutive effect of stock options and unvested restricted stock
units is considered in the detailed calculation below. There were no
anti-dilutive securities related to restricted stock units for any periods
presented.
Shares associated with the conversion feature of the Convertible Notes
are accounted for using the if-converted method as described above. A total of
3,846,153 potentially dilutive shares related to the Convertible Notes were
included in the calculation of diluted net income per common share for the years
ended December 31, 2004 and 2003. A total of 3,076,922 potentially dilutive
shares related to the Convertible Notes were excluded from the 2002 calculation
of diluted net income per share because they were not dilutive. The Convertible
Notes were issued in March 2002.
F-11
The following table sets forth the calculation of basic and diluted
earnings per share:
For the Years Ended December 31,
------------------------------------------------
2004 2003 2002
-------------- ------------- -------------
(In thousands, except per share amounts)
Income before cumulative effect of change in accounting
principle $ 92,479 $ 90,140 $ 27,560
Cumulative effect of change in accounting principle, net
of income tax - 5,435 -
------------- ------------- -------------
Net income 92,479 95,575 27,560
------------- ------------- -------------
Adjustments to net income for dilution:
Add: interest expense avoided if Convertible Notes
converted to equity 6,354 6,337 -
Less: other adjustments (64) (63) -
Less: income tax effect of dilution items (2,312) (2,403) -
------------- ------------- -------------
Net income adjusted for the effect of dilution $ 96,457 $ 99,446 $ 27,560
============= ============= =============
Basic weighted-average common shares outstanding 28,851 31,233 27,856
Add: dilutive effect of stock options 750 455 535
Add: dilutive effect of Convertible Notes using the
if-converted method 3,846 3,846 -
------------- ------------- -------------
Diluted weighted-average common shares outstanding 33,447 35,534 28,391
============= ============= =============
Basic earnings per common share:
Income before cumulative effect of change in
accounting principle $ 3.21 $ 2.89 $ 0.99
Cumulative effect of change in accounting principle - 0.17 -
------------- ------------- -------------
Total $ 3.21 $ 3.06 $ 0.99
============= ============= =============
Diluted earnings per common share:
Income before cumulative effect of change in
accounting principle $ 2.88 $ 2.65 $ 0.97
Cumulative effect of change in accounting principle - 0.15 -
------------- ------------- -------------
Total $ 2.88 $ 2.80 $ 0.97
============= ============= =============
Stock-Based Compensation
At December 31, 2004, the Company had stock-based employee compensation
plans that included restricted stock units and stock options issued to employees
and non-employee directors as more fully described in Note 7 - Compensation
Plans. The Company accounts for stock-based compensation using the intrinsic
value recognition and measurement principles prescribed in Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB No. 25")
and related interpretations. No compensation expense is reflected in net income
for stock options as all stock options had an exercise price equal to the market
value of the underlying common stock on the date of grant. The total measured
expense for restricted stock unit ("RSU") grants is initially recorded as
deferred stock-based compensation and is charged to compensation expense based
on the vesting schedule. The portion of the estimated future RSU grant related
to current year performance that will vest immediately upon grant is recorded to
compensation expense in the current year. The following table illustrates the
pro forma effect on net income and earnings per share if the Company had applied
the fair value recognition provisions of SFAS No. 123, "Accounting for
Stock-Based Compensation," to stock-based employee compensation:
F-12
For the Years Ended December 31,
----------------------------------------------
2004 2003 2002
------------- ------------ -------------
(In thousands, except per share amounts)
Net income -
As reported: $ 92,479 $ 95,575 $ 27,560
Add: stock-based employee compensation
expense included in reported net income,
net of related tax effects 2,650 - -
Less: stock-based employee compensation
expense determined under fair value
method for all awards, net of
related income tax effects (6,062) (5,853) (4,666)
------------- ------------ -------------
Pro forma $ 89,067 $ 89,722 $ 22,894
============= ============ =============
Pro forma basic earnings per share -
- -------------------------------------
Income before cumulative effect of change in
accounting principle $ 3.09 $ 2.70 $ 0.82
Cumulative effect of change in accounting principle - 0.17 -
------------- ------------ -------------
Total $ 3.09 $ 2.87 $ 0.82
============= ============ =============
Pro forma diluted earnings per share -
- ---------------------------------------
Income before cumulative effect of change in
accounting principle $ 2.78 $ 2.48 $ 0.81
Cumulative effect of change in accounting principle - 0.15 -
------------- ------------ -------------
Total $ 2.78 $ 2.63 $ 0.81
============= ============ =============
For purposes of pro forma disclosures, the estimated fair values of the
options are amortized to expense over the options' vesting periods. The effects
of applying SFAS No. 123 in the pro forma disclosure are not necessarily
indicative of actual future amounts.
In December 2004 the Financial Accounting Standards Board ("FASB")
issued SFAS No. 123 (Revised 2004), "Shared-Based Payment". This statement
provides for the accounting for transactions in which an entity exchanges equity
instruments or incurs liabilities in exchange for goods or services. See Note 7
- - Compensation Plans for additional disclosures about stock-based compensation.
Comprehensive Income
Comprehensive income consists of net income, unrealized gains and
losses on marketable equity securities held for sale, the effective portion of
derivative instruments classified as cash flow hedges, and accrued pension
benefit obligation in excess of plan assets. Comprehensive income is presented
net of income taxes in the consolidated statements of stockholders' equity and
comprehensive income.
F-13
The balances of after-tax components comprising accumulated other
comprehensive income and loss are presented in the following table:
Marketable Minimum Accumulated Other
Equity Derivative Pension Comprehensive
Securities Instruments Liability Income (Loss)
------------- --------------- ------------ --------------------
Balances, December 31, 2001 $ 9 $ 6,907 $ - $ 6,916
Reclass to earnings - 1,447 - 1,447
Other 2002 changes (725) (14,644) (761) (16,130)
------------- --------------- ------------ --------------------
Balances, December 31, 2002 (716) (6,290) (761) (7,767)
Reclass to earnings 716 13,846 - 14,562
Other 2003 changes - (21,873) 197 (21,676)
------------- --------------- ------------ --------------------
Balances, December 31, 2003 - (14,317) (564) (14,881)
Reclass to earnings - (14,795) - (14,795)
Other 2004 changes - 31,849 101 31,950
------------- --------------- ------------ --------------------
Balances, December 31, 2004 $ - $ 2,737 $ (463) $ 2,274
============= =============== ============ ====================
Tax effects allocated to each component of other comprehensive income:
Marketable Minimum Other
Equity Derivative Pension Comprehensive
Securities Instruments Liability Income (Loss)
------------- ---------------- ------------ ----------------
For the period ending December 31, 2002
Before tax amount $ (1,121) $ (18,067) $ (1,188) $ (20,376)
Tax (expense) benefit 396 4,870 427 5,693
------------- ---------------- ------------ ----------------
After tax amount (725) (13,197) (761) (14,683)
============= ================ ============ ================
For the period ending December 31, 2003
Before tax amount 1,160 (13,170) 274 (11,736)
Tax (expense) benefit (444) 5,143 (77) 4,622
------------- ---------------- ------------ ----------------
After tax amount 716 (8,027) 197 (7,114)
============= ================ ============ ================
For the period ending December 31, 2004
Before tax amount - 27,401 168 27,569
Tax (expense) benefit - (10,347) (67) (10,414)
------------- ---------------- ------------ ----------------
After tax amount $ - $ 17,054 $ 101 $ 17,155
============= ================ ============ ================
F-14
Major Customers
During 2004 one customer individually accounted for 20 percent of the
Company's total oil and gas production revenue. During 2003 three customers
individually accounted for 14 percent, 13 percent and 11 percent of the
Company's total oil and gas production revenue. During 2002 there were no sales
to individual customers that accounted for more than 10 percent of total oil and
gas production revenue.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration,
development and production of natural gas and crude oil, and all of the
Company's operations are conducted in the continental United States.
Consequently, the Company currently reports as a single industry segment.
Note 2 - Accounts Receivable and Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
As of December 31,
-------------------------------------------
2004 2003
------------------ -------------------
(In thousands)
Accrued oil and gas sales $ 79,107 $ 48,925
Due from joint interest owners 20,587 12,554
Other 5,270 3,061
------------------ -------------------
Total accounts receivable $ 104,964 $ 64,540
================== ===================
Accounts payable and accrued expenses are comprised of the following:
As of December 31,
---------------------------------------
2004 2003
------------------ ----------------
(In thousands)
Accrued drilling costs $ 34,446 $ 22,201
Revenue payable 41,875 16,215
Accrued lease operating expense 13,066 12,195
Accrued cash bonus and net profit payments 4,264 8,026
Trade payables 7,506 6,247
Oil hedge accrual 3,027 1,400
Other 5,933 14,933
------------------ ----------------
Total account payable and accrued expenses $ 110,117 $ 81,217
================== ================
F-15
Note 3 - Acquisitions and Divestitures
Goldmark Acquisition
On November 1, 2004, the Company acquired Goldmark Engineering Inc.
along with proved and unproved oil and gas properties from various other parties
(collectively, "Goldmark") in exchange for $23.3 million of cash. The allocation
of the purchase price was $29.4 million of proved reserves and unproved acreage,
$1.2 million of cash, $753,000 of other assets, $446,000 of payables, a $2.8
million asset retirement liability, and a $4.8 million deferred tax liability.
The acquisition was accounted for using the purchase method of accounting and
was funded with cash on hand and borrowings under the Company's existing credit
facility. Operating results from the acquired properties have been included in
the consolidated statements of operations only from the date of closing. The
final purchase accounting allocations will be dependent on a determination of
post closing adjustments incurred subsequent to the acquisition date.
Border Acquisition (Previously referred to by the Company as the Nemours
Acquisition)
On December 15, 2004, the Company completed the acquisition of proved
and unproved oil and gas properties from Border Company and other parties in
exchange for $37.8 million in cash. The allocation of the purchase price was
$38.5 million of proved reserves and unproved acreage and a $649,000 asset
retirement obligation. The final purchase accounting allocations will be
dependent on a determination of post closing adjustments incurred subsequent to
the acquisition date. The Company utilized a portion of its existing credit
facility to fund the acquisition, and the transaction was accounted for as a
purchase.
Agate Acquisition
On January 5, 2005, the Company closed the acquisition of Agate
Petroleum, Inc. for $39.6 million in cash. The estimated preliminary purchase
accounting will result in the Company recording approximately $42.1 million to
proved and unproved oil and gas properties, $3.0 million to working capital,
$9.4 million to goodwill, a deferred income tax liability of $13.6 million and a
$1.3 million asset retirement obligation. The final purchase accounting
allocation will be dependent on the determination of working capital, tax basis
and fair value of the oil and gas properties as of the date of closing. The
goodwill and deferred income tax liability are a result of acquiring assets with
tax basis that is lower than book basis because present value considerations
cannot be applied to the amounts recorded for deferred income taxes.
Flying J Acquisition
On January 29, 2003, the Company acquired oil and gas properties and
other assets and liabilities from Flying J Oil & Gas Inc. and Big West Oil
& Gas Inc. (collectively, "Flying J"). As consideration for the properties,
St. Mary issued 3,380,818 restricted shares of its common stock to Flying J. In
addition, St. Mary made a non-recourse loan to Flying J of $71.6 million at the
one-year LIBOR plus 2 percent for up to a 39-month period. The loan was funded
using cash on hand and borrowing under the credit facility in place at the time
of the transaction. This loan was secured by a pledge of the shares of common
stock issued to Flying J, with the final nine months of interest on that loan to
be with recourse to Flying J. St. Mary also entered into a put and call option
agreement with Flying J whereby during the 39-month loan period Flying J could
elect to put their shares of St. Mary common stock to the Company for $71.6
million plus accrued interest on the loan during the first thirty months of the
loan period, and St. Mary could elect to call the shares for $97.4 million, with
the proceeds from the exercise of either the put option or the call option to be
applied to the repayment of the loan plus accrued and unpaid interest. The
shares issued were restricted for a period of two years, and Flying J was
prohibited from selling the shares during that period. If neither Flying J nor
St. Mary exercised their respective option rights, the loan plus accrued
interest was to be repaid prior to the release of the security interest in the
shares.
F-16
For financial reporting purposes, the effect of the above arrangements
is that the Company acquired oil and gas properties and other assets and
liabilities in exchange for $71.6 million of cash plus a net option to Flying J
valued at $995,000 resulting in a total valuation of $72.6 million. The
allocation of the purchase price for the net assets acquired was $72.4 million
of proved reserves and unproved acreage, $445,000 of other assets, a $1.9
million asset retirement liability, a $2.0 million hedge liability, and $3.7
million in net cash received for purchase price adjustments. The acquisition was
accounted for using the purchase method of accounting. Operating results from
the acquired properties have been included in the consolidated statements of
operations only from the date of closing.
The shares of common stock that were issued in this transaction were
recorded as temporary equity since they were subject to the put option whereby
the Company could have been required to repurchase these shares. The shares of
common stock were considered outstanding for basic and diluted earnings per
share calculations. The loan arising from this transaction was considered a
contra-temporary equity item on the 2003 consolidated balance sheet, as opposed
to an asset, since the loan was non-recourse to Flying J except with respect to
interest accrued after the first thirty months and was secured by the restricted
common stock issued as part of this transaction. Interest was not accrued for
financial reporting purposes because of the non-recourse nature of the note.
As described more fully in Note 11 - Repurchase of St. Mary Common
Stock, the Company entered into a separately negotiated transaction in February
2004 with Flying J to repurchase the 3,380,818 restricted shares issued in the
acquisition.
Sales of Properties
Throughout 2004 the Company sold interests in certain non-core
properties. The Company received cash proceeds of $2.8 million and recognized a
gain of approximately $1.8 million from these sales. For property sales that
occurred in the fourth quarter of 2004, the final proceeds and gain amounts are
subject to the resolution of final post-closing adjustments and settlements.
Throughout 2003 the Company sold interests in certain non-core properties
primarily in Texas and Wyoming. The Company received $23.5 million in net
proceeds and recognized a gain of approximately $7.3 million from these sales.
Note 4 - Income Taxes
The provision for income taxes consists of the following:
For the Years Ended December 31,
------------------------------------------
2004 2003 2002
-------------- ------------- -------------
(In thousands)
Current taxes:
Federal $ 21,143 $ 29,582 $ 719
State 1,389 2,656 569
Deferred taxes 31,217 23,692 13,731
-------------- ------------- -------------
Total income tax expense $ 53,749 $ 55,930 $ 15,019
============== ============= =============
The above taxes from operations are net of alternative fuels credits
(Internal Revenue Code Section 29) of $167,000 in 2002. Current federal tax
expense does not reflect the tax benefit of $3.8 million in 2004, $1.2 million
in 2003 and $719,000 in 2002 for deductions from stock option exercises.
F-17
The components of the net deferred tax liability are as follows:
December 31,
-----------------------------------
2004 2003
----------------- ----------------
(In thousands)
Deferred tax liabilities:
Oil and gas properties $ 146,427 $ 100,103
Interest on Convertible Notes 4,192 2,791
Amounts included in accumulated other comprehensive income 2,246 -
Derivative instruments and other 435 41
----------------- ----------------
Total deferred tax liabilities 153,300 102,935
----------------- ----------------
Deferred tax assets:
Net Profits Plan liability 11,598 2,358
State tax net operating loss carryforward or carryback 2,981 2,094
Federal net operating loss carryforward or carryback 2,882 2,900
Stock compensation 1,590 -
State and federal income tax benefit 1,100 1,002
Deferred capital loss 758 1,840
Amounts included in accumulated other comprehensive income 1,033 9,222
Other, primarily employee benefits 969 2,286
----------------- ----------------
Total deferred tax assets 22,911 21,702
Valuation allowance (1,714) (842)
----------------- ----------------
Net deferred tax assets 21,197 20,860
----------------- ----------------
Total net deferred tax liabilities 132,103 82,075
Less: current deferred income tax liabilities (2,357) -
Add: current deferred income tax assets 84 8,872
----------------- ----------------
Non-current net deferred tax liabilities $ 129,830 $ 90,947
================= ================
Current federal refundable income tax $ - $ 454
Current federal income tax payable $ 939 $ -
Current state refundable income tax $ 139 $ -
Current state income tax payable $ - $ 1,334
At December 31, 2004, the Company had state net operating loss
carryforwards of approximately $42.8 million and state tax credits of $93,000,
which expire between 2005 and 2023. The Company's valuation allowance relates to
those state net operating loss carryforwards and state tax credits that the
Company anticipates will expire before they can be utilized. The Company has
concluded that permanent items included in the calculation of income tax for
certain states may impact its ability to deduct net operating losses incurred in
those states and has adjusted its valuation allowances accordingly.
F-18
Federal income tax expense and benefit differs from the amount that
would be provided by applying the statutory U.S. Federal income tax rate to
income before income taxes for the following reasons:
For the Years Ended December 31,
-------------------------------------------------
2004 2003 2002
--------------- ---------------- ----------------
(In thousands)
Federal statutory taxes $ 51,180 $ 49,668 $ 14,477
Increase (reduction) in taxes resulting from:
State taxes (net of federal benefit) 2,586 5,812 2,092
Statutory depletion (224) (224) (218)
Alternative fuel credits (Section 29) - - (167)
Change in valuation allowance 872 115 (1,202)
Other (665) 559 37
--------------- ---------------- ----------------
Income tax expense from operations $ 53,749 $ 55,930 $ 15,019
=============== ================ ================
Acquisitions, drilling and basis differentials impacting the prices
received for crude oil and natural gas impact the apportionment of taxable
income to the states where the Company owns properties. As these factors change,
the Company's state income tax rate changes. This change applied to the
Company's total temporary differences will impact the total income tax reported
in the current year and is reflected in state taxes in the table above. These
impacts are evaluated upon completion of the prior year income tax return, after
significant acquisitions are closed and at the end of the year.
Note 5 - Long-term Debt
Revolving Credit Facility
The Company has a revolving credit facility with a group of banks. The
credit facility specifies a maximum loan amount of $300.0 million and has a
maturity date of January 27, 2006. Borrowings under the facility are secured by
a pledge of collateral that includes the majority of the Company's oil and gas
properties and the common stock of the material subsidiaries of the Company. The
bank group authorized a borrowing base of $325.0 million in October 2004 under
its normal semi-annual redetermination. The borrowing base redetermination
process considers the value of St. Mary's oil and gas properties, using oil and
gas pricing criteria specified by the bank syndicate, and other assets as
determined by the bank syndicate. Although the borrowing base exceeds the
maximum loan amount, the most that the Company could borrow under the facility
is limited to the maximum loan amount. The Company has elected an aggregate
commitment amount of $150.0 million. The Company must comply with certain
financial and non-financial covenants including the limitation of our annual
dividend rate to no more than $0.20 per share. The Company is in compliance with
all of the covenants. Interest and commitment fees are accrued based on the
borrowing base utilization percentage table below. Eurodollar loans accrue
interest at LIBOR plus the applicable margin from the utilization table, and
Alternative Base Rate (ABR) loans accrue interest at Prime plus the applicable
margin from the utilization table. Commitment fees are accrued on the unused
portion of the aggregate commitment amount and are included in interest expense
in the consolidated statements of operations.
Borrowing base
utilization percentage <50% =>50%<75% =>75%<90% >90%
- -------------------------------------------------------------------------------
Eurodollar Loans 1.25% 1.50% 1.75% 2.00%
ABR Loans 0.00% 0.25% 0.50% 0.75%
Commitment Fee Rate 0.30% 0.38% 0.38% 0.50%
At December 31, 2004, the Company's borrowing base utilization
percentage as defined under the credit agreement was 24.7 percent. The Company
had $10.0 million in ABR borrowings and $27.0 million in LIBOR based loans
outstanding under its revolving credit agreement as of December 31, 2004. As of
F-19
February 15, 2005, the Company had an outstanding ABR balance of $2 million and
an outstanding balance of $44 million under its LIBOR alternative.
5.75% Senior Convertible Notes Due 2022
As of December 31, 2004, the Company also had $100.0 million in
outstanding borrowings under the Convertible Notes. The Convertible Notes
provide for the payment of contingent interest of up to an additional 0.5
percent during six-month interest periods based on the Convertible Note market
price before the beginning of the particular six-month period. Under that
provision, interest was accrued at a total rate of 6.25 percent for 2004. Based
on the trading price of the Convertible Notes over the determination period, the
Company will be subject to the contingent interest payments for the period from
September 16, 2004, to March 15, 2005.
The Convertible Notes are general unsecured obligations and rank on
parity in right of payment with all existing and future unsecured senior
indebtedness and other general unsecured obligations. They are senior in right
of payment to all future subordinated indebtedness. The Convertible Notes are
convertible into the Company's common stock at a conversion price of $26.00 per
share, subject to adjustment. The Company can redeem the Convertible Notes with
cash in whole or in part at a repurchase price of 100 percent of the principal
amount plus accrued and unpaid interest (including contingent interest)
beginning on March 20, 2007. The note holders have the option of requiring the
Company to repurchase the Convertible Notes for cash at 100 percent of the
principal amount plus accrued and unpaid interest (including contingent
interest) upon (1) a change in control of St. Mary or (2) on March 20, 2007,
March 15, 2012, and March 15, 2017. If the note holders require repurchase on
March 20, 2007, the Company may elect to pay the repurchase price with cash,
shares of its common stock valued at a discount at the time of repurchase, or
any combination of cash and its discounted common stock. The shares of common
stock used in any repurchase will be discounted at 95 percent of market price if
33 percent or less of the repurchase price is in shares of our common stock;
otherwise, the stock will be discounted at 93 percent of market value. St. Mary
is not restricted from paying dividends, incurring debt, or issuing or
repurchasing its securities under the indenture for the Convertible Notes. There
are no financial covenants in the indenture. Based on the market price of the
Convertible Notes, the estimated fair value of the Convertible Notes was
approximately $171.8 million as of December 31, 2004, and approximately $135.3
million as of December 31, 2003.
Weighted-Average Interest Rate Paid and Capitalized Interest
The weighted-average interest rate paid in 2004 was 7.1 percent
including commitment fees paid on the unused portion of the credit facility
aggregate commitment, amortization of deferred financing costs, amortization of
the contingent interest embedded derivative and the effect of interest rate
swaps. The impact of these items over a lower average outstanding loan balance
results in a higher weighted-average interest rate despite lower LIBOR interest
rates than in previous periods. The company capitalized interest costs of $1.4
million, $780,000, and $427,000 for the years ended December 31, 2004, 2003 and
2002, respectively.
Note 6 - Commitments and Contingencies
The Company leases office space under various operating leases with
terms extending as far as May 31, 2012. Rent expense, net of sublease income,
was $1.5 million, $1.3 million, and $1.1 million in 2004, 2003 and 2002,
respectively. The Company also leases office equipment under various operating
leases. The Company has a non-cancelable sublease of approximately $1.3 million
through 2012. The annual minimum lease payments for the next five years and
thereafter are presented below:
F-20
Years Ending December 31, (In thousands)
- ----------------------------- -------------------
2005 $ 2,440
2006 1,814
2007 1,306
2008 1,193
2009 1,065
Thereafter 2,876
------------------
Total $ 10,694
==================
The Company is subject to litigation and claims that have arisen in the
ordinary course of business. The Company accrues for such items when a liability
is both probable and the amount can be reasonably estimated. In the opinion of
management, the results of such litigation and claims will not have a material
effect on the results of operations or the financial position of the Company.
Management believes it has sufficiently provided for such items in the
consolidated balance sheets.
Note 7 - Compensation Plans
Cash Bonus Plan
The Company has a cash bonus plan that normally allows participants to
receive up to 50 percent, but in special situations to receive up to 100 percent
of their aggregate base salary. Any awards under the cash bonus plans are based
on a combination of Company and individual performance. The Company accrued $2.0
million for cash bonuses in 2004 that will be paid in 2005, and $5.4 million for
cash bonuses in 2003 that were paid in 2004.
Net Profits Plan
Under the Company's Net Profits Plan, oil and gas wells that are
completed or acquired during a year are designated within a specific pool. Key
employees designated as participants by the Company's Compensation Committee of
the Board of Directors and employed by the Company on the last day of that year
vest and become entitled to bonus payments after the Company has received net
cash flows returning 100 percent of all costs and expenses associated with that
pool. Thereafter, 10 percent of future cash flows generated by the pool are
allocated among the participants and distributed at least annually. The
percentage of cash flows from the pool to be allocated among the participants
increases to 20 percent after the Company has recovered 200 percent of the total
costs and expenses for the pool, including payments made under the Net Profits
Plan at the 10 percent level.
Expense related to current distributions made under the Net Profits
Plan in 2004, 2003 and 2002 were $8.0 million, $8.9 million, and $4.8 million,
respectively. These amounts relate to current realized results from oil and gas
operations in the respective periods.
The Company records the estimated liability for the Net Profits Plan
based on the discounted value of estimated future payments associated with each
individual pool. The following table presents the changes in the estimated
liability attributable to the Net Profits Plan:
F-21
As of December 31,
----------------------------------------------
2004 2003
--------------------- ---------------------
(In thousands)
Beginning liability for Net Profits Plan $ 6,163 $ 846
Change in liability for accretion and change
in estimates 32,410 14,235
Reduction in liability for cash payments made or
accrued and recognized as compensation expense
under the Net Profits Plan (8,012) (8,918)
--------------------- ---------------------
Ending liability for Net Profits Plan $ 30,561 $ 6,163
===================== =====================
The Company records the expense associated with changes in the present
value of estimated future payments under the Net Profits Plan as a separate item
in the consolidated statements of operations. The change in the estimated
liability is recorded as an increase or decrease to expense in the current
period. The amount recorded as an increase or decrease to expense associated
with the change in the estimated liability is not allocated to general and
administrative costs or exploration costs because the adjustment of the
liability is associated with the future net cash flows from oil and gas
properties in the respective pools rather than current period performance. The
table below presents the estimated allocation of the change in the liability if
the Company did allocate the adjustment to these specific line items:
For the Years Ended December 31,
------------------------------------------------------------
2004 2003 2002
--------------- ------------------ ------------------
(In thousands)
General and administrative expense $ 14,609 $ 3,982 $ 616
Exploration expense 9,789 1,335 230
--------------- --- ------------------ -- ------------------
Total $ 24,398 $ 5,317 $ 846
=============== === ================== == ==================
401(k) Plan
The Company has a defined contribution pension plan (the "401(k) Plan")
that is subject to the Employee Retirement Income Security Act of 1974. The
401(k) Plan allows eligible employees to contribute up to 60 percent of their
base salaries. The Company matches each employee's contributions up to 6 percent
of the employee's base salary and may also make additional contributions at its
discretion. The Company's contributions to the 401(k) Plan were $834,000,
$746,000, and $621,000 for the years ended December 31, 2004, 2003, and 2002,
respectively. No discretionary contributions were made by the Company to the
401(k) Plan in any of these three years.
Employee Stock Purchase Plan
Under the St. Mary Land & Exploration Company Employee Stock
Purchase Plan ("the ESPP"), eligible employees may purchase shares of the
Company's common stock through payroll deductions of up to 15 percent of
eligible compensation. The purchase price of the stock is 85 percent of the
lower of the fair market value of the stock on the first or last day of the
purchase period, and shares issued under the ESPP are restricted for a period of
18 months from the date issued. The ESPP is intended to qualify under Section
423 of the Internal Revenue Code. The Company has set aside 1,000,000 shares of
its common stock to be available for issuance under the ESPP. Shares issued
under the ESPP totaled 13,874 in 2004, 16,994 in 2003, and 18,217 in 2002. Total
proceeds to the Company for the issuance of these shares were $375,000 in 2004,
$375,000 in 2003, and $344,000 in 2002. The Company recorded compensation
expense of $21,000 in 2002 due to nonqualified dispositions of stock acquired by
employees under the ESPP. No compensation expense has been recorded under the
ESPP after 2002 since all shares issued under the ESPP after July 1, 2001 were
issued as restricted shares and are not subject to disqualified disposition.
F-22
Stock Option Plans
The Company has a Stock Option Plan and an Incentive Stock Option Plan
(collectively, the "Option Plans"). The Option Plans grant options to purchase
shares of the Company's common stock to eligible employees, contractors, and
current and former members of the Board of Directors. There are 5,600,000 shares
of the Company's common stock reserved for issuance under the Option Plans. This
number is reduced to the extent that restricted stock or restricted stock units
are granted under the Restricted Stock Plan. All options granted to date under
the Option Plans have been granted at exercise prices equal to the respective
market prices of the Company's common stock on the grant dates. There were
869,862 shares available for grant under the Option Plans (including the
Restricted Stock Plan, as described later) as of December 31, 2004.
A summary of activity associated with the Company's Option Plans during
the last three years follows:
For the Years Ended December 31,
---------------------------------------------------------------------------------
2004 2003 2002
-------------------------- --------------------------- --------------------------
Weighted- Weighted- Weighted-
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------------- ------------ ------------- ------------- ------------- ------------
Outstanding, start of year 3,525,128 $ 23.10 3,061,566 $ 21.34 2,151,675 $ 19.42
Granted 58,678 37.79 858,431 26.70 1,109,541 23.55
Exercised (699,526) 20.06 (245,019) 12.88 (177,085) 11.44
Forfeited (58,605) 24.99 (149,850) 24.00 (22,565) 25.08
------------- ------------- -------------
Outstanding, end of year 2,825,675 24.12 3,525,128 23.10 3,061,566 21.34
============= ============= =============
Exercisable, end of year 2,220,681 23.51 2,441,246 22.36 1,944,382 19.79
Weighted-average fair
value of options granted
granted
during the year $ 16.87 $ 12.28 $ 10.77
F-23
A summary of additional information related to options outstanding as
of December 31, 2004, follows:
Options Outstanding Options Exercisable
----------------------------------------------- ----------------------------
Weighted-
Average Weighted- Weighted-
Remaining Average Average
Range of Number Contractual Exercise Number Exercise
Exercise Prices Outstanding Life Price Exercisable Price
- ------------------------ --------------- -------------- -------------- ------------- -------------
$ 9.25 - $ 12.52 389,204 4.4 years $ 11.50 389,204 $ 11.50
12.53 - 16.69 120,077 6.4 years 15.82 120,077 15.82
16.70 - 20.87 47,209 3.0 years 17.50 47,209 17.50
20.88 - 25.04 1,000,032 7.5 years 23.22 757,885 23.10
25.05 - 29.21 733,671 8.7 years 26.73 413,354 26.65
29.22 - 33.39 482,530 6.0 years 33.31 482,530 33.31
33.40 - 37.56 18,750 9.2 years 33.43 1,875 33.43
37.57 - 41.74 34,202 10 years 41.74 8,547 41.74
--------------- -------------
Total 2,825,675 7.0 years 24.12 2,220,681 23.51
=============== =============
SFAS No. 123 establishes a fair value method of accounting for
stock-based compensation plans through either recognition or disclosure. The
Company accounts for stock-based compensation under the intrinsic value method
pursuant to APB No. 25 and has elected to adopt SFAS No. 123 through compliance
with the disclosure requirements set forth in the Statement. Because the
exercise price of the Company's stock options equals the market price of the
underlying stock on the date of grant, no compensation expense is recognized
under APB No. 25. Pro forma information regarding net income and earnings per
share is required by SFAS No. 123 and has been determined as if the Company had
accounted for its employee stock options under the fair value method of that
Statement. This pro forma information is prominently disclosed in Note 1-Summary
of Significant Accounting Policies.
The fair value of options is measured at the date of grant using the
Black-Scholes option-pricing model. The fair values of options granted were
estimated using the following weighted-average assumptions:
For the Years Ended December 31,
----------------------------------------------
2004 2003 2002
--------------- -------------- --------------
Risk free interest rate:
Stock options 4.1% 3.6% 3.8%
Employee stock purchase plan 3.1% 3.7% 3.5%
Dividend yield:
Stock options 0.3% 0.4% 0.4%
Employee stock purchase plan 0.3% 0.4% 0.4%
Volatility factor of the expected market
price of the Company's common stock:
Stock options 35.9% 39.9% 48.0%
Employee stock purchase plan 23.8% 20.2% 30.1%
Expected life of the options (in years)
Stock options 9.0 7.0 5.9
Employee stock purchase plan 0.5 0.5 0.5
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options that have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. The Company's stock options have characteristics significantly
F-24
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, it is
management's opinion that the valuations afforded by the existing models are
different from the value that the options would realize if traded in the market.
Restricted Stock Plan
In May 2004 the Restricted Stock Plan was approved by the Company's
stockholders, establishing a long-term incentive program whereby grants of
restricted stock or restricted stock units may be awarded to eligible employees,
consultants, and members of the Board of Directors. Restrictions and vesting
periods for the awards are determined at the discretion of the Board of
Directors and are set forth in the award agreements. The total number of shares
of the Company's common stock reserved for issuance under the Restricted Stock
Plan is 5,600,000. This number is reduced to the extent that stock options are
granted under the Company's Option Plans.
St. Mary made grants of 232,861 RSUs in June 2004. The total expense
associated with these grants was $8.3 million as measured on the date of the
grant and has been reduced by $178,000 for forfeitures as of December 31, 2004.
The total measured expense was initially recorded as deferred stock-based
compensation and is being charged to compensation expense based on the vesting
schedule. The RSU grants vest 25 percent immediately upon issuance and 25
percent on each of the first three anniversary dates. The vested shares
underlying the RSU grants will be issued on the third anniversary of the grants,
at which time the shares carry no further restrictions. As of December 31, 2004,
there were 169,616 unvested RSUs, which included the total of the 2004 grants
less the vested portion of the grants and units forfeited due to employee
terminations prior to vesting. Compensation expense for the year ended December
31, 2004, related to the 2004 grants totaled $3.1 million. In addition, the
Company recorded $1.1 million of compensation expense for the year ended
December 31, 2004, related to the expected 25 percent immediate vesting of the
estimated 2005 RSU grants.
Non -Employee Director Stock Compensation Plan
In May 2003, stockholders approved a Non-Employee Director Stock
Compensation Plan to authorize the issuance of up to 30,000 shares of St. Mary
common stock to non-employee directors as part of their compensation over an
anticipated period of up to five years. The purpose of the plan is to attract,
retain, and motivate non-employee directors. As of December 31, 2004, 12,600
shares have been issued under this plan.
Note 8 - Pension Benefits
The Company's employees participate in a non-contributory pension plan
covering substantially all employees who meet age and service requirements (the
"Qualified Pension Plan"). The Company also has a supplemental non-contributory
pension plan covering certain management employees (the "Nonqualified Pension
Plan").
F-25
Obligations and Funded Status
For the Years Ended December 31,
-------------------------------------------------
2004 2003 2002
------------- -------------- -------------
(In thousands)
Change in benefit obligations:
Projected benefit obligation at beginning of year $ 8,048 $ 6,330 $ 5,098
Service cost 1,139 963 442
Interest cost 489 428 358
Amendments - - (46)
Actuarial loss 1,236 620 503
Benefits paid (738) (293) (25)
------------- -------------- -------------
Projected benefit obligation at end of year $ 10,174 $ 8,048 $ 6,330
============= ============== =============
Change in plan assets:
Fair value of plan assets at beginning of year $ 3,694 $ 2,478 $ 2,042
Actual return on plan assets 434 608 (255)
Employer contribution 1,285 901 716
Benefits paid (738) (293) (25)
------------- -------------- -------------
Fair value of plan assets at end of year $ 4,675 $ 3,694 $ 2,478
============= ============== =============
Funded status: $ (5,499) $ (4,354) $ (3,758)
Unrecognized net loss 3,754 2,874 2,925
Unrecognized prior service cost - (15) (41)
------------- -------------- -------------
Accrued benefit cost $ (1,745) $ (1,495) $ (874)
============= ============== =============
Amounts Recognized in the Consolidated Balance Sheets
As of December 31,
----------------------------------------------
2004 2003
--------------------- ---------------------
(In thousands)
Accrued benefit cost $ 1,745 $ 1,495
Accumulated other comprehensive income 746 914
--------------------- ---------------------
Net amount recognized $ 2,491 $ 2,409
===================== =====================
Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31,
-----------------------------------------
2004 2003
------------------- -----------------
(In thousands)
Projected benefit obligation $ 10,174 $ 8,048
Accumulated benefit obligation $ 7,143 $ 6,058
Fair value of plan assets $ 4,675 $ 3,694
The Company's accumulated benefit obligation for the Qualified Pension
Plan was $5.9 million at December 31, 2004, and $4.8 million at December 31,
2003. The accumulated benefit obligation exceeds plan assets by $1.2 million.
The tax-adjusted liability of $463,000 was recorded in other comprehensive
income at December 31, 2004.
F-26
The Company's accumulated benefit obligation for the Nonqualified
Pension Plan was $1.2 million at December 31, 2004, and $1.2 million at December
31, 2003. There are no plan assets in the Nonqualified Pension Plan due to the
nature of the plan.
Components of Net Periodic Benefit Cost
For the Years Ended December 31,
---------------------------------------------
2004 2003 2002
------------- -------------- --------------
(In thousands)
Components of net periodic benefit cost:
Service cost $ 1,139 $ 963 $ 442
Interest cost 489 428 358
Expected return on plan assets (295) (172) (146)
Amortization of prior service cost (16) (25) (25)
Amortization of net actuarial loss 218 329 211
------------- -------------- --------------
Net periodic benefit cost $ 1,535 $ 1,523 $ 840
============= ============== ==============
Prior service costs are amortized on a straight-line basis over the
average remaining service period of active participants. Gains and losses in
excess of 10 percent of the greater of the benefit obligation and the
market-related value of assets are amortized over the average remaining service
period of active participants.
Additional Information
The minimum liability included in other accumulated comprehensive
income, net of taxes, decreased by $101,000 and $197,000 for the years ended
December 31, 2004 and 2003, respectively, and increased by $761,000 for the year
ended December 31, 2002.
Assumptions
Weighted-average assumptions to measure the Company's projected benefit
obligation and net periodic benefit cost are as follows:
As of December 31,
--------------------------------------
2004 2003
---------------- ----------------
Projected benefit obligation
- ----------------------------
Discount rate 5.75% 6.25%
Expected return on plan assets 8.00% 8.00%
Rate of compensation increase 4.00% 3.50%
Net periodic benefit cost
- -------------------------
Discount rate 6.25% 6.50%
Expected return on plan assets 8.00% 8.00%
Rate of compensation increase 3.50% 3.75%
F-27
Plan Assets
The Company's weighted-average asset allocation for the Qualified Plan
is as follows:
As of December 31,
Target -----------------------------------
Asset Category 2005 2004 2003
- --------------------- ---------------- ---------------- ---------------
Equity securities 60.0% 63.0% 61.4%
Debt securities 40.0% 34.7% 38.0%
Other 0% 2.3% 0.6%
---------------- ---------------- ---------------
Total 100.0% 100.0% 100.0%
================ ================ ===============
Equity securities do not include any shares of the Company's common
stock for any period presented. There is no asset allocation for the
Nonqualified Pension Plan since that plan does not have its own assets. An
expected return on plan assets of eight percent was used to calculate the
Company's obligation under the Qualified Plan. Factors considered in determining
the expected return include the 60 percent equity and 40 percent debt securities
mix of investment for plan assets and the long-term historical rate of return
provided by the equity and debt securities markets. The estimated rate of return
on plan assets was 11.7 percent for 2004 and 24.6 percent for 2003. The
difference in investment income using the projected rate of return compared to
the actual rates of return for the past two years was not material and will not
have a material effect on the statements of operation or on cash flows from
operating activities in future years.
Contributions
The Company contributed $1.3 million, $901,000, and $716,000 to the
pension plans in the years ended December 31, 2004, 2003, and 2002,
respectively. St. Mary expects to contribute approximately $1.1 million to the
pension plans in 2005.
Benefit Payments
The Company made actual benefit payments of $738,000, $293,000, and
$25,000 in the years ended December 31, 2004, 2003 and 2002, respectively.
Expected benefit payments over the next ten years follows:
Years Ended December 31, (in thousands)
- ----------------------------------- ---------------
2005 $ 368
2006 $ 371
2007 $ 469
2008 $ 597
2009 $ 837
2010 through 2014 $ 11,752
F-28
Note 9 - Asset Retirement Obligations
As of January 1, 2003, the Company adopted the provisions of SFAS No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally
applies to legal obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and/or the normal
operation of a long-lived asset. SFAS No. 143 requires the Company to recognize
an estimated liability for future costs associated with the abandonment of its
oil and gas properties. A liability for the fair value of an asset retirement
obligation and a corresponding increase to the carrying value of the related
long-lived asset is recorded at the time a well is completed or acquired. The
increase in carrying value is included in proved oil and gas properties on the
consolidated balance sheets. The Company depletes the amount added to proved oil
and gas property costs and recognizes accretion expense in connection with the
discounted liability over the remaining estimated economic lives of the
respective oil and gas properties. Prior to the adoption of SFAS No. 143, the
Company had recognized an abandonment liability for its offshore wells. These
offshore liabilities were reversed upon adoption of SFAS No. 143, and the
methodology described above was used to determine the liability associated with
abandoning all wells, including those offshore.
The estimated liability is based on historical experience in abandoning
wells, estimated economic lives, external estimates as to the cost to abandon
the wells in the future and federal, and state regulatory requirements. The
liability is discounted using a credit-adjusted risk-free rate estimated at the
time the liability is incurred or revised. The credit-adjusted risk-free rates
used to discount the Company's abandonment liabilities range from 6.50 percent
to 7.25 percent. Revisions to the liability could occur due to changes in
estimated abandonment costs or well economic lives, or if federal or state
regulators enact new requirements regarding the abandonment of wells.
Upon adoption of SFAS No. 143, the Company recorded a discounted
liability of $21.4 million, reversed the existing offshore abandonment liability
of $9.1 million, increased property and equipment by $12.8 million, decreased
accumulated DD&A by $8.3 million and recognized a one-time cumulative effect
gain of $5.4 million (net of deferred tax benefit of $3.4 million).
A reconciliation of the Company's asset retirement obligation liability
is as follows:
As of December 31,
---------------------------------
2004 2003
-------------- ---------------
(In thousands)
Beginning asset retirement obligation $ 25,485 $ -
Liability from SFAS 143 adoption - 21,403
Liabilities incurred 7,187 4,395
Liabilities settled (620) (3,169)
Accretion expense 1,984 1,719
Revision to estimated cash flows 6,875 1,137
-------------- ---------------
Ending asset retirement obligation $ 40,911 $ 25,485
============== ===============
F-29
The following tables illustrate the effect on the asset retirement
obligation liability, net income and earnings per share if the Company had
adopted the provisions of SFAS No. 143 on January 1, 2002. The pro forma amounts
are calculated using current information, assumptions and interest rates as of
January 1, 2003 (in thousands, except per share amounts).
As of December 31,
--------------------------------
2002
--------------------------------
Asset retirement obligation liability $ 21,829
Year Ended December 31,
------------------------------
2002
------------------------------
Net income
As reported $ 27,560
Pro forma $ 26,622
Basic earnings per share
As reported $ 0.99
Pro forma $ 0.96
Diluted earnings per share
As reported $ 0.97
Pro forma $ 0.94
Note 10 - Derivative Financial Instruments
The Company realized a net loss of $50.6 million from its derivative
contracts for the year ended December 31, 2004, a net loss of $22.7 million for
the year ended December 31, 2003, and a net gain of $953,000 for the year ended
December 31, 2002.
The following table summarizes derivative instrument gain (loss)
activity (in thousands):
For the Years Ended December 31,
---------------------------------------------
2004 2003 2002
--------------- -------------- ------------
Derivative contract settlements included
in oil and gas hedge loss $ (50,299) $ (22,439) $ (2,235)
Ineffective portion of hedges qualifying
for hedge accounting included in
derivative gain (loss) 113 (246) (32)
Non-qualified derivative contracts included
in derivative gain (loss) (373) (64) 3,220
--------------- -------------- ------------
Total gain (loss) $ (50,559) $ (22,749) $ 953
=============== ============== ============
Oil and Gas Commodity Hedges
The Company has in place derivative contracts for the sale of oil and
natural gas. The Company attempts to qualify these instruments as cash flow
hedges for accounting purposes. The table below describes the volumes and
average contract prices of hedges currently in place. The Company's oil and
natural gas derivative contracts include swap and collar arrangements. Gas
contracts are indexed to a variety of regional indexes, and the oil contracts
are NYMEX based.
F-30
Swaps Gas (per MMBtu) Oil (per Bbl)
- -----
------------------------------------------- ------------------------------------------
Weighted-Average Weighted-Average
Contract Contract Price Contract Price
Period Volumes (Regional Index) Volumes (NYMEX)
--------------- ----------------------- --------------- -----------------------
2005
- ----
Quarter Ending:
March 31, 2,297,800 $ 7.16 242,452 $ 40.19
June 30, 2,026,600 $ 6.16 184,214 $ 42.56
September 30, 1,605,000 $ 6.24 188,980 $ 41.61
December 31, 1,590,000 $ 6.54 138,770 $ 40.80
--------------- ---------------
Total 2005 7,519,400 $ 6.56 754,416 $ 41.24
--------------- ---------------
2006
- ----
Quarter Ending:
March 31, 720,000 $ 6.49 103,366 $ 38.93
June 30, 710,000 $ 5.51 99,976 $ 38.15
September 30, 690,000 $ 5.49 100,372 $ 37.47
December 31, 270,000 $ 5.55 77,686 $ 36.42
--------------- ---------------
Total 2006 2,390,000 $ 5.80 381,400 $ 37.83
--------------- ---------------
2007
- ----
Quarter Ending:
March 31, - $ - 63,410 $ 35.63
June 30, - $ - 61,072 $ 35.35
September 30, - $ - 62,684 $ 35.10
December 31, - $ - 60,620 $ 34.79
--------------- ---------------
Total 2007 - $ - 247,786 $ 35.22
--------------- ---------------
All Contracts 9,909,400 $ 6.38 1,383,602 $ 39.22
=============== ===============
Collars Gas (per MMBtu)
- -------
---------------------------------------------------------------------
Weighted- Weighted-
Average Average
Contract Floor Ceiling
Period Price Price Volumes Index
----- ----- ------- -----
2005
- ----
Quarter Ending:
March 31, $ 6.62 $ 8.08 540,000 IF ANR OK
June 30, $ 5.73 $ 7.20 540,000 IF ANR OK
September 30, $ 5.75 $ 7.30 415,000 IF ANR OK
December 31, $ 6.00 $ 7.63 390,000 IF ANR OK
---------------------
All Contracts $ 6.05 $ 7.57 1,885,000
=====================
F-31
The Company seeks to minimize basis risk and indexes its oil contracts
to NYMEX prices and its gas contracts to various regional index prices
associated with pipelines in proximity to the Company's areas of gas production.
Swap natural gas volumes associated with specific Inside FERC ("IF") regional
indexes are as follows:
Regional Index MMBtu
--------------
IF ANR OK 4,679,400
IF Reliant N/S 2,920,000
IF PEPL 2,310,000
--------------
Total 9,909,400
==============
Derivative gain (loss) in the consolidated statements of operations for
the year ended December 31, 2004, and 2003, include a net gain of $113,000 and a
net loss of $246,000 from ineffectiveness related to oil and natural gas
derivative contracts, respectively. On December 31, 2004, the estimated fair
value of oil and natural gas derivative contracts designated and qualifying as
cash flow hedges under SFAS No. 133 was a net asset of $4.2 million. If prices
remain unchanged from year end levels, the Company would reclassify this amount
to oil and gas hedge gain included in operating revenue as the hedged production
quantity is produced. As of December 31, 2004, the net amount of unrealized gain
net of deferred income taxes to be reclassified from accumulated other
comprehensive income to oil and gas production operating revenues in the next
twelve months was $5.0 million. The Company anticipates that all original
forecasted transactions will occur by the end of their originally specified
periods.
Interest Rate Derivative Contracts
In October 2003 the Company entered into fixed-to-floating interest
rate swaps for a total notional amount of $50.0 million through March 20, 2007.
Under the swaps, St. Mary will be paid a fixed interest rate of 5.75 percent and
will pay a variable interest rate of 235 basis points above the six-month LIBOR
rate as determined on the semi-annual settlement date. The payment dates of the
swaps match the interest payment dates of the Convertible Notes. The six-month
LIBOR rate on December 31, 2004, was 2.78 percent. Realized gains included in
interest expense on these swaps were $795,000 in 2004. Derivative gain (loss) in
the consolidated statements of operations for the year ended December 31, 2004,
and 2003, includes a $328,000 and $104,000 net loss, respectively, from
mark-to-market adjustments for this derivative. The fair value of the swaps was
a liability of $432,000 and $104,000 as of December 31, 2004, and 2003,
respectively.
Included in the consolidated statements of operations in 2002 is a net
realized gain of $3.6 million included in derivative gain. This gain was
generated from the settlement of a fixed-to-floating interest rate swap contract
entered into in March 2002 on $50.0 million of the Convertible Notes. This swap
did not qualify for fair value hedge treatment under SFAS No. 133 and related
pronouncements. This contract was closed out on December 3, 2002.
Convertible Note Derivative Instrument
The Company's Convertible Notes contain a provision for payment of
contingent interest if certain conditions are met. Under SFAS No. 133 this
provision is considered an embedded equity-related derivative that is not
clearly and closely related to the fair value of an equity interest and
therefore must be treated as a separate derivative instrument. The value of the
derivative at issuance of the Convertible Notes in March 2002 was $474,000. This
amount was recorded as a decrease to the Convertible Notes payable in the
consolidated balance sheets. Of this amount, $95,000, $95,000 and $75,000 have
been amortized through interest expense for the years ended December 31, 2004,
2003, and 2002, respectively. Derivative gain (loss) in the consolidated
statements of operations for the years ended December 31, 2004, 2003, and 2002,
includes a $45,000 net loss, a $40,000 net gain and a $341,000 net loss,
respectively, from mark-to-market adjustments for this derivative. The fair
value of this derivative at December 31, 2004 and 2003, was a liability of
$820,000 and $775,000, respectively.
F-32
Note 11 - Repurchase of St. Mary Common Stock
Flying J Repurchase Transaction
On February 9, 2004, the Company repurchased from Flying J 3,380,818
restricted shares of St. Mary common stock for a total of $91.0 million. These
shares were originally issued by St. Mary to Flying J on January 29, 2003, in
connection with St. Mary's acquisition of oil and gas properties. In addition to
issuing the shares in the acquisition, St. Mary loaned Flying J $71.6 million.
Flying J used the proceeds to repay their outstanding loan balance to St. Mary
of $71.6 million. Accrued interest, which was not recorded by the Company for
financial reporting purposes due to the non-recourse nature of the loan, was
forgiven. The net $19.4 million cash outlay was funded from the Company's
existing cash balances and borrowings under its credit facility.
Stock Repurchase Program
In August 2004 the Company's Board of Directors approved an
increase in the number of shares that may be repurchased under the original
authorization approved in August of 1998 to 3,000,000 as of the effective date
of the resolution. St. Mary had not made any repurchases under the program since
2001. The shares may be repurchased from time to time in open market
transactions or privately negotiated transactions, subject to market conditions
and other factors, including certain provisions of St. Mary's existing credit
facility agreement and compliance with securities laws. Stock repurchases may be
funded with existing cash balances, internal cash flow and borrowings under the
credit facility. The stock repurchase program may be suspended or discontinued
at any time. As of December 31, 2004, a total of 1,499,200 shares of the
Company's common stock had been repurchased under the plan. The company
repurchased 489,300 and -0- shares in 2004 and 2003, respectively. In September
2004 the Company retired from treasury the 489,300 shares repurchased in 2004
together with 740,100 shares repurchased in prior years.
Note 12 - Disclosures about Oil and Gas Producing Activities
Costs Incurred in Oil and Gas Producing Activities:
Costs incurred in oil and gas property acquisition, exploration and
development activities, whether capitalized or expensed, are summarized as
follows. The 2004 and 2003 amounts include $14.1 million and $5.5 million,
respectively, of capitalized costs associated with asset retirement obligations.
For the Years Ended December 31,
-----------------------------------------------------
2004 2003 2002
--------------- --------------- ---------------
(In thousands)
Development costs $ 190,829 $ 111,908 $ 74,376
Exploration 37,977 33,296 22,548
Acquisitions:
Proved 69,054 73,989 85,559
Unproved 7,646 8,942 2,147
Leasing activity 7,877 7,480 8,128
--------------- --------------- ---------------
Total $ 313,383 $ 235,615 $ 192,758
=============== =============== ===============
Oil and Gas Reserve Quantities (Unaudited):
For all years presented the reserve information for greater than 80
percent of the PV-10 value was prepared by Ryder Scott Company L.P. and/or
Netherland, Sewell and Associates, Inc. ("NSAI"). The Company engaged NSAI for
the first time in 2004. St. Mary prepared the reserve estimates for the
remainder of all properties. The Company emphasizes that reserve estimates are
inherently imprecise and that estimates of new discoveries and undeveloped
locations are more imprecise than estimates of established proved producing oil
and gas properties. Accordingly, these estimates are expected to change as
future information becomes available.
F-33
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods. All of the
Company's proved reserves are located in the United States.
Presented below is a summary of the changes in estimated reserves of
the Company:
For the Years Ended December 31,
-------------------------------------------------------------------------------------------
2004 2003 2002
---------------------------- --------------------------- ----------------------------
Oil or Oil or Oil or
Condensate Gas Condensate Gas Condensate Gas
-------------- ----------- ------------ ----------- ------------- -----------
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
Developed and undeveloped:
Beginning of year 47,787 307,024 36,119 274,172 23,669 241,231
Revisions of previous estimate 1,994 (21,885) 2,856 3,904 3,611 4,696
Discoveries and extensions 6,306 63,185 3,681 69,189 1,250 32,813
Purchases of minerals in place 5,773 17,635 11,952 41,335 10,578 38,118
Sales of reserves (487) (165) (2,280) (31,913) (174) (4,522)
Production (4,799) (46,598) (4,541) (49,663) (2,815) (38,164)
-------------- ----------- ------------ ----------- ------------- -----------
End of year (a) 56,574 319,196 47,787 307,024 36,119 274,172
============== =========== ============ =========== ============= ===========
Proved developed reserves:
Beginning of year 43,693 264,140 33,580 228,973 20,679 205,637
============== =========== ============ =========== ============= ===========
End of year 47,992 272,295 43,693 264,140 33,580 228,973
============== =========== ============ =========== ============= ===========
- -------------------
(a) At December 31, 2004, 2003, and 2002 amounts include approximately
480, 1,119, and 1,151 MMcf, respectively, representing the
Company's net underproduced gas balancing position.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited):
SFAS No. 69, "Disclosures about Oil and Gas Producing Activities,"
prescribes guidelines for computing a standardized measure of future net cash
flows and changes therein relating to estimated proved reserves. The Company has
followed these guidelines, which are briefly discussed below.
Future cash inflows and future production and development costs are
determined by applying benchmark prices and costs, including transportation,
quality and basis differentials, in effect at year-end to the year-end estimated
quantities of oil and gas to be produced in the future. Each property the
Company operates is also charged with field-level overhead in the estimated
reserve calculation. Estimated future income taxes are computed using current
statutory income tax rates, including consideration for estimated future
statutory depletion. The resulting future net cash flows are reduced to present
value amounts by applying a 10 percent annual discount factor.
Future operating costs are determined based on estimates of
expenditures to be incurred in developing and producing the proved oil and gas
reserves in place at the end of the period, using year-end costs and assuming
continuation of existing economic conditions, plus Company overhead incurred by
the central administrative office attributable to operating activities.
F-34
The assumptions used to compute the standardized measure are those
prescribed by the FASB and the Securities and Exchange Commission. These
assumptions do not necessarily reflect the Company's expectations of actual
revenues to be derived from those reserves, nor their present value. The
limitations inherent in the reserve quantity estimation process, as discussed
previously, are equally applicable to the standardized measure computations
since these estimates are the basis for the valuation process. The following
prices, adjusted for transportation, quality and basis differentials, were used
in the calculation of the standardized measure:
2004 2003 2002
----------- ---------- ----------
Gas (per Mcf) $ 5.80 $ 5.70 $ 4.21
Oil (per Bbl) $ 40.06 $ 31.01 $ 29.31
The following summary sets forth the Company's future net cash flows
relating to proved oil and gas reserves based on the standardized measure
prescribed in SFAS No. 69:
As of December 31,
------------------------------------------------------
2004 2003 2002
--------------- ---------------- ----------------
(In thousands)
Future cash inflows $ 4,118,188 $ 3,232,605 $ 2,238,513
Future production costs (1,349,380) (963,226) (696,132)
Future development costs (164,797) (101,935) (87,859)
Future income taxes (827,368) (735,947) (429,618)
--------------- ---------------- ----------------
Future net cash flows 1,776,643 1,431,497 1,024,904
10 percent annual discount (742,705) (571,541) (443,042)
--------------- ---------------- ----------------
Standardized measure of discounted
future net cash flows $ 1,033,938 $ 859,956 $ 581,862
=============== ================ ================
The principle sources of change in the standardized measure of
discounted future net cash flows are:
For the Years Ended December 31,
-------------------------------------------------------
2004 2003 2002
----------------- ---------------- --------------
(In thousands)
Standard measure, beginning of year $ 859,956 $ 581,862 $ 281,877
Sales of oil and gas produced, net of
production costs and hedging (368,099) (299,044) (137,066)
Net changes in prices and production costs 166,826 168,661 298,079
Extensions, discoveries and other, net of
production costs 279,763 226,181 92,227
Purchase of minerals in place 73,875 178,264 160,089
Development costs incurred during the year 46,156 22,763 23,802
Changes in estimated future development costs (17,489) 11,175 4,265
Revisions of previous quantity estimates (24,271) 45,551 49,892
Accretion of discount 125,175 78,869 34,749
Sales of reserves in place (3,906) (47,270) (708)
Net change in income taxes (75,389) (211,381) (177,335)
Changes in timing and other (28,659) 104,325 (48,009)
----------------- ---------------- --------------
Standardized measure, end of year $ 1,033,938 $ 859,956 $ 581,862
================= ================ ==============
F-35
Note 13 - Quarterly Financial Information (Unaudited)
The Company's quarterly financial information for fiscal 2004 and 2003
is as follows (in thousands, except per share amounts):
First Second Third Fourth
Quarter Quarter Quarter Quarter
------------- -------------- -------------- --------------
Year Ended December 31, 2004
- ----------------------------
Total revenue $ 96,482 $ 102,151 $ 108,078 $ 126,388
Less: costs and expenses 60,603 65,566 71,575 83,440
------------- -------------- -------------- --------------
Income from operations $ 35,879 $ 36,585 $ 36,503 $ 42,948
Income before income taxes $ 34,535 $ 35,262 $ 35,125 $ 41,306
Net income $ 21,449 $ 21,836 $ 22,565 $ 26,629
Basic net income per common share $ 0.72 $ 0.76 $ 0.79 $ 0.94
Diluted net income per common share $ 0.66 $ 0.69 $ 0.71 $ 0.83
Dividends declared per common share $ - $ 0.05 $ 0.05 -
Year Ended December 31, 2003
- ----------------------------
Total revenue $ 101,155 $ 103,628 $ 90,935 $ 97,990
Less: costs and expenses 54,736 61,619 66,624 57,418
------------- -------------- -------------- --------------
Income from operations $ 46,419 $ 42,009 $ 24,311 $ 40,572
Income before income taxes and cumulative effect
of accounting principle $ 44,433 $ 39,986 $ 22,551 $ 39,100
Net income $ 32,797 $ 24,317 $ 13,786 $ 24,675
Basic earnings per common share:
Income before cumulative effect of
change in accounting principle $ 0.90 $ 0.77 $ 0.44 $ 0.78
Cumulative effect of change in
accounting principle 0.18 - - -
------------- -------------- -------------- --------------
Basic net income per common share $ 1.08 $ 0.77 $ 0.44 $ 0.78
============= ============== ============== ==============
Diluted earnings per common share:
Income before cumulative effect of
change in accounting principle $ 0.81 $ 0.71 $ 0.41 $ 0.72
Cumulative effect of change in
accounting principle 0.16 - - -
------------- -------------- -------------- --------------
Diluted net income per common share $ 0.97 $ 0.71 $ 0.41 $ 0.72
============= ============== ============== ==============
Dividends declared per common share $ - $ 0.05 $ - $ 0.05
F-36
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
ST. MARY LAND & EXPLORATION COMPANY
---------------------------------------
(Registrant)
Date: February 25, 2005 By: /S/ MARK A HELLERSTEIN
-----------------------
Mark A. Hellerstein
Chairman of the Board of Directors, President
and Chief Executive Officer
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints each of Mark A. Hellerstein and David W.
Honeyfield his or her true and lawful attorney-in-fact and agent with full power
of substitution and resubstitution, and each with full power to act alone, for
the undersigned and in his or her name, place and stead, in any and all
capacities, to sign any amendments to this Annual Report on Form 10-K for the
fiscal year ended December 31, 2004, and to file the same, with exhibits thereto
and other documents in connection therewith, with the Securities and Exchange
Commission, hereby ratifying and confirming all that each of said
attorney-in-fact, or his substitute or substitutes, may do or cause to be done
by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
- --------- ----- ----
/S/ MARK A. HELLERSTEIN
- -----------------------
Mark A. Hellerstein Chairman of the Board February 25, 2005
of Directors, President
and Chief Executive Officer
/S/ DAVID W. HONEYFIELD
- -----------------------
David W. Honeyfield Vice President-Finance, February 25, 2005
Secretary and Treasurer
/S/ GARRY A. WILKENING
- ----------------------
Garry A. Wilkening Vice President-Administration February 25, 2005
and Controller
Signature Title Date
- --------- ----- ----
/S/BARBARA M. BAUMANN
- ---------------------
Barbara M. Baumann Director February 25, 2005
/S/ LARRY W. BICKLE
- -------------------
Larry W. Bickle Director February 25, 2005
/S/ RONALD D. BOONE
- -------------------
Ronald D. Boone Director February 25, 2005
/S/ THOMAS E. CONGDON
- ---------------------
Thomas E. Congdon Director February 25, 2005
/S/ WILLIAM J. GARDINER
- -----------------------
William J. Gardiner Director February 25, 2005
/S/ WILLIAM D. SULLIVAN
- -----------------------
William D. Sullivan Director February 25, 2005
/S/ JOHN M. SEIDL
- -----------------
John M. Seidl Director February 25, 2005