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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, 2003
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 26,911,648 shares of voting stock held by
non-affiliates of the registrant, based upon the closing sale price of the
common stock on June 30, 2003, the last business day of the registrant's most
recently completed second fiscal quarter, of $24.06 per share as reported on the
New York Stock Exchange was $647,494,251. 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 20, 2004, the registrant had 28,339,963 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, 2003.
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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, 2002.............3
Major Customers..............................................4
Employees and Office Space...................................4
Title to Properties..........................................5
Seasonality..................................................5
Competition..................................................5
Government Regulations.......................................5
Risk Factors.................................................7
Cautionary Statement about Forward-Looking Statements.......18
Available Information.......................................19
Glossary....................................................20
ITEM 2. PROPERTIES......................................................22
Operations..................................................22
Acquisitions and Divestitures...............................25
Reserves....................................................26
Production..................................................27
Productive Wells............................................28
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, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES...............................................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.................40
Critical Accounting Policies and Estimates..................48
Additional Comparative Data in Tabular Format...............52
Comparison of Financial Results and Trends Between
2003 and 2002...............................................53
Comparison of Financial Results and Trends Between
2002 and 2001...............................................54
Other Liquidity and Capital Resource Information............56
Accounting Matters..........................................56
Environmental...............................................57
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK (included with the content of ITEM 7)...............57
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.....................57
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.............................57
ITEM 9A. CONTROLS AND PROCEDURES.........................................57
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..............58
ITEM 11. EXECUTIVE COMPENSATION..........................................58
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS..................58
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..................58
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES..........................58
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K.............................................59
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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 Oklahoma and northern Texas, primarily
in the Anadarko and Arkoma basins, with significant activity in the
Northeast Mayfield field in Beckham County, Oklahoma;
o the ArkLaTex region that spans northern Louisiana and portions of
Arkansas, Mississippi and eastern Texas, with the most recent
activity in the James Lime Horizontal trend;
o the Gulf Coast region, including the Judge Digby field and our
fee property in St. Mary Parish, Louisiana;
o the Rocky Mountain region consisting of the Williston Basin in
eastern Montana and western North Dakota and the Powder River,
Green River and Wind River basins in Wyoming. The most recent
activity in the Rockies includes the dolomite formations under
the Bakken Shale; continued exploration in the Red River
formation, most recently in the Ridgelawn field; and our
initiation of the development of coalbed methane reserves in the
Hanging Woman Basin; and
o the Permian Basin in eastern New Mexico and western Texas.
As of December 31, 2003, we had estimated proved reserves of
approximately 47.8 MMBbl of oil and 307.0 Bcf of natural gas, or a total of
593.7 BCFE, 89 percent of which were proved developed and 52 percent of which
were natural gas, with a PV-10 value of $1.3 billion. This represents a 21
percent increase in reserve volumes and a 55 percent increase in PV-10 value
from a year earlier. For the year ended December 31, 2003, we produced 76.9 BCFE
representing average daily production of 210.7 MMCFE per day, a 40 percent
increase over 2002.
We 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 the
foundation for steady growth, including a non-conventional gas play in the Rocky
Mountain region. In 2003, we spent $146.5 million in capital expenditures
related to drilling activities, $77.4 million on acquisition of oil and gas
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properties and $7.5 million on acquisition of leasehold.
We measure and rank our investment decisions based on their
risk-adjusted estimated internal rate of return and return on investment. When
we issue stock for the acquisition of properties or a corporate entity we base
our investment decision on the transaction's impact on net asset value per
share.
In the past, we have sold selected assets when we believed attractive
prices were available, and we will continue to evaluate such opportunities in
the future. For example, in 2003 we sold certain oil and gas properties for
total proceeds of approximately $23.5 million, resulting in a gain for financial
reporting purposes of $7.3 million.
We seek to develop our existing property base and acquire acreage with
additional potential in our core areas. From January 1, 2001, through December
31, 2003, we participated in the drilling or recompletion of 691 gross wells
with an average success rate of 83 percent. During that same period we added
estimated proved reserves of 483.5 BCFE at an average finding cost of $1.27 per
MCFE. Our average annual production replacement was 260 percent during this
three-year period, and our production has grown from an average daily rate of
148.2 MMCFE per day in 2001 to 210.7 MMCFE per day in 2003.
As of December 31, 2003, we had an acreage position of 2,004,749 gross
(1,086,367 net) acres of which 1,284,367 gross (806,326 net) acres were
undeveloped. Our current leasehold position represents a 75 percent increase on
a gross acre basis and a 100 percent increase on a net acre basis over 2002. In
addition to this acreage position, we have 24,914 net acres of fee properties in
the highly prolific St. Mary Parish of Louisiana and mineral servitudes
representing 14,296 gross (9,534 net) acres in Louisiana.
For 2004 we have budgeted capital expenditures of $173.4 million for
ongoing development, exploitation and exploration programs in our core operating
areas and $100.0 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 increased leasehold position is a
strategic asset. Our senior technical managers, each possessing over
20 years of experience, head up regional technical offices supported
by centralized administration from our Denver office. We believe
that our long-standing presence, our established networks of local
industry relationships and our acreage holdings in our core
operating areas provide us with a competitive advantage. We believe
these strengths and our organizational structure will allow us to
continue to expand our operations without the need to
proportionately increase the number of our employees.
2
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,
secondary recovery and specialized logging tools to enhance the
potential of our existing properties. In 2003 we participated in the
drilling or recompletion of 254 gross wells with an 83 percent
success rate.
o Make Selective Acquisitions. We seek to make selective niche
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 believe that the focus on
relatively smaller negotiated transactions where we have specialized
geologic knowledge or operating experience has enabled us to acquire
attractively priced and under-exploited properties. In addition, we
will pursue corporate acquisitions that we believe will be accretive
and are capable of being integrated into the Company. Examples of
this type of acquisition include our 1999 Nance Petroleum
Corporation and King Ranch Energy, Inc. acquisitions, both of which
were accomplished with the issuance of our common stock. A more
recent example is the January 2003 acquisition of oil and gas
properties from Flying J. Although this transaction was not a
corporate acquisition, we used a combination of restricted stock, a
loan to Flying J and options on our stock. We have budgeted $100
million for acquisitions in 2004.
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, 2003, we operated 70 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 75 percent of
our 2004 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 less than 20 percent at the end of December
2003.
Significant Developments Since December 31, 2002
o 2003 Acquisition of Oil and Gas Properties from Flying J. In January
2003 St. Mary acquired oil and gas properties in our Rocky Mountain
region from Flying J Oil & Gas Inc. and Big West Oil & Gas
Inc. (collectively "Flying J"). This acquisition included properties
located in the Williston, Powder River, Wind River and Green River
basins with 91.4 BCFE of proved reserves as of the acquisition date
and significant undeveloped leasehold acreage. During 2003 we
produced 2,631 MMcf of gas and 778 MBbl of oil from the properties
acquired from Flying J. As part of the transaction, we issued
3,380,818 shares of restricted common stock, subject to a put and
call option agreement. In addition, we made a nonrecourse loan to
Flying J of $71.6 million, which was secured by a pledge of the
shares issued. This transaction was valued for financial reporting
purposes as an acquisition of oil and gas properties in exchange for
$71.6 million in cash and a net option valued at $1.0 million. As
discussed below, in February 2004 we repurchased the shares and
Flying J repaid the loan.
3
o Increase in 2003 Year-End Reserves. Proved reserves increased 21
percent to 593.7 BCFE at December 31, 2003, from 490.8 BCFE at
December 31, 2002. We added 113.0 BCFE through acquisitions,
primarily in the Rocky Mountain region, and 91.3 BCFE from drilling
activities. There were net upward revisions of previous reserves
totaling 21.0 BCFE. This upward revision was the result of a 6.7
BCFE increase from price and a 14.3 BCFE increase from performance.
The 21 percent increase in reserves over last year is net of current
year sales of oil and gas properties with 45.6 BCFE of reserves.
o Mid-Continent Drilling Results. The majority of the reserve
additions from drilling came from our Mid-Continent region and were
primarily attributable to activity in the Northeast Mayfield area.
This drilling activity is in the Atoka and Upper Morrow / Springer
formations.
o Revolving Credit Agreement. In January 2003 we entered into a new
long-term revolving credit agreement with nine banks. The facility
has a maximum loan amount of $300 million and is subject to periodic
borrowing base calculations. As of the end of 2003, our borrowing
base is $275 million and we have elected a loan commitment amount of
$150 million. The maturity date of the facility is January 27, 2006.
Borrowings under the facility were $11.0 million as of December 31,
2003.
o Coal Bed Methane Project. In December 2003, we announced that we are
proceeding with the development of coalbed methane reserves in the
Hanging Woman Basin located in the northern part of the Powder River
Basin along the border between Montana and Wyoming. We have
approximately 139,000 net lease acres in total. Our development will
initially concentrate on approximately 65,000 net acres in Wyoming.
We have estimated probable reserves associated with this
development, but we have not recorded any proved reserves through
December 31, 2003.
o Repurchase of Shares from Flying J. In February 2004, we repurchased
the 3,380,818 restricted shares of our common stock held by Flying J
for $91.0 million. In connection with this transaction, Flying J
completely repaid our $71.6 million loan to them. The $19.4 million
net cash outlay for the share repurchase was funded from our
existing cash balances and borrowings under our bank credit
facility.
Major Customers
During 2003 sales to BP America Production Company accounted for 13.6
percent, sales to Midcoast Energy accounted for 13.1 percent and sales to Tesoro
Refining and Marketing accounted for 11.4 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.
During 2001 sales to Transok Gas Company accounted for 12.0 percent and sales to
BP Amoco accounted for 11.3 percent of our total oil and gas production revenue.
Employees and Office Space
As of December 31, 2003, we had 226 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 47,395 square
feet of office space in Denver, Colorado for our executive and administrative
offices, of which 9,479 square feet is subleased. We also lease approximately
17,318 square feet of office space in Tulsa, Oklahoma; approximately 11,740
square feet in Shreveport, Louisiana; approximately 7,500 square feet in
Lafayette, Louisiana; and approximately 22,160 square feet in Billings, Montana.
4
As of March 1, 2004, our Lafayette, Louisiana office will relocate to
Houston, Texas. The Lafayette lease expires on November 30, 2004, and we plan to
continue making lease payments through the term of the lease. We will lease
approximately 11,015 square feet in Houston.
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 properties.
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. Seasonal anomalies such as mild winters sometimes lessen this
fluctuation. 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.
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. The foundation for a strong drilling program is our leasehold
position. Our competitive position depends on our geological, geophysical and
engineering expertise, our financial resources, and our ability to select,
acquire and develop proved reserves. We believe that the locations of our
leasehold acreage, our exploration, drilling and production capabilities and the
experience of our management and that of our industry partners generally enable
us to compete effectively in our core operating areas. However, we compete with
a substantial number of major and independent oil and gas companies that have
larger technical staffs and greater financial and operational resources than we
do. Many of these companies not only engage in the acquisition, exploration,
development and production of oil and natural gas reserves, but also have
refining operations, market refined products 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.
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.
5
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;
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
6
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. As a result, these laws and regulations may
substantially increase the costs of 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
Risks Related to Our Business
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.
7
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. We expect the markets for oil and gas
to continue to be volatile. Any substantial or extended decline in the price of
oil or gas would have a material adverse effect on our financial condition and
results of operations. It could reduce our cash flow and borrowing capacity, as
well as the value and the amount of our oil and gas reserves. Lower prices may
also reduce the amount of oil and gas that we can economically produce.
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 the price and level of foreign imports;
o worldwide economic conditions;
o marketability of production;
o the level of consumer demand;
o the price, availability and acceptance of alternative fuels;
o the availability of pipeline capacity;
o weather conditions; and
o actions of federal, state, local and foreign authorities.
These external factors and the volatile nature of the energy markets
make it difficult to estimate future prices of oil and natural gas. 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 our financial condition, results of operations and
reserves. Further, oil and gas prices do not necessarily move in tandem. Since
approximately 52 percent of our proved reserves were natural gas reserves as of
December 31, 2003, our financial results are slightly more affected by changes
in natural gas prices.
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. As of December 31, 2003,
our proved reserves would last approximately 7.7 years if produced constantly at
the 2003 rate of production. However, our properties do not produce at a
8
constant rate but rather 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. Without successful exploration or
acquisition activities, our reserves, production and revenues will decline
rapidly. In addition, approximately 11 percent of our total estimated proved
reserves as of December 31, 2003 were undeveloped. By their nature, undeveloped
reserves are less certain. Recovery of such reserves requires significant
capital expenditures and successful drilling operations. We may not be able to
find and develop or acquire sufficient additional reserves at an acceptable
cost.
Our producing property acquisitions carry significant risks.
Our recent growth is due in part to, and our growth strategy relies in
part on, the economic acquisition of producing properties. Successful
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. In connection with these
assessments, we perform a review of the subject properties that we believe is
generally consistent with industry practices. However, such a review will not
reveal all existing or potential problems. In addition, our review may not
permit us to become sufficiently familiar with the properties to fully assess
their deficiencies and capabilities. We do not inspect every well. Even when we
do inspect a well, we may not always discover structural, subsurface or
environmental problems that may exist or arise.
In connection with our acquisitions, we may not be entitled to
contractual indemnification for preclosing liabilities, including environmental
liabilities. Normally, we acquire interests in properties on an "as is" basis
with limited remedies for breaches of representations and warranties. In
addition, 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.
Additionally, significant acquisitions can change the nature of our
operations and business depending upon the character of the acquired properties,
which may have substantially different operating and geological characteristics
or be in different geographic locations than our existing properties. While it
is our current intention to continue to concentrate on acquiring properties with
development, exploitation and exploration potential located in our five core
operating areas, we may in the future decide to pursue acquisitions of
properties located in other geographic regions. To the extent that such 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.
We seek to make selective niche acquisitions of oil and gas properties,
and we will pursue corporate acquisitions that we believe will be accretive.
However, integrating acquired properties and businesses involves a number of
special risks. These risks include 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. Any of these or
other similar risks could lead to potentially adverse short-term or long-term
effects on our operating results. We may not be able to obtain adequate funds
for future property or corporate acquisitions, successfully integrate our future
property or corporate acquisitions or we may not realize any of the anticipated
benefits of the acquisitions.
9
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 $231.4 million for 2003 and $193.0
million during 2002. We have budgeted total capital expenditures of $273.4
million in 2004. With the cash provided by operating activities and borrowings
under our credit facility, we believe we will have sufficient cash to fund
budgeted capital expenditures in 2004. If additional development or attractive
acquisition opportunities arise, we may consider other forms of financing,
including the public offering or private placement of equity or debt securities.
However, 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 in future years 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.
o 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;
o prices of oil and natural gas;
o lease operating expense, including workovers and taxes; and
o administrative expense.
Issuing equity securities to satisfy our financing requirements could
cause substantial dilution to existing stockholders. Debt financing could lead
to:
o a substantial portion of our operating cash flow being dedicated to
the payment of principal and interest;
o us being more vulnerable to competitive pressures and economic
downturns; and
o restrictions on our operations.
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, 2003, we had approximately $111.0 million in
outstanding loans, including $100.0 million outstanding under our 5.75% Senior
Convertible Notes due 2022. Our level of debt could have important consequences
on our operations, including:
10
o making it more difficult for us to satisfy our debt obligations
and, if we fail to comply with the requirements of any of our debt
obligations, possibly resulting in an event of default;
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;
o detracting from our ability to withstand successfully a downturn in
our business or the economy generally; and
o placing us at a competitive disadvantage against other less
leveraged competitors.
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.
The indenture for our Convertible Notes does not limit our ability to
incur additional debt. We may therefore incur additional debt, including secured
debt under our bank credit facility or otherwise, in order to make future
acquisitions or to develop our properties. A higher level of debt increases the
risk that we may default on our debt obligations. We may not be able to generate
sufficient cash flow to pay the interest on our debt, and 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 redeterminations of our borrowing base. We may not have
sufficient funds to make such repayments. 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.
We may not be able to obtain bank credit facility borrowing base
redeterminations that adequately meet our anticipated financing needs.
Our long-term revolving 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 2003 the
banks conducted their normal semi-annual borrowing base redetermination that
resulted in a borrowing base of $275 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 2004. The banks may not agree to a borrowing base redetermination
that is adequate for our financing needs at that time.
11
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 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 $4.0 million, $2.4
million and $4.7 million in 2003, 2002 and 2001, 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.
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. Therefore, these
estimates are not precise. 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, 2003, approximately 11 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 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
12
industry standards, these estimated costs may not be accurate, development may
not occur as scheduled and actual results may not be 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, 2003, were estimated using a calculated weighted
average sales price of $31.01 per barrel of oil (NYMEX) and $5.70 per Mcf of gas
(Gulf Coast spot price), after adjustment for transportation, quality and basis
differentials. During 2003 our monthly average realized gas prices were as high
as $9.28 per Mcf and as low as $4.49 per Mcf. For the same period our monthly
average realized oil prices were as high as $35.73 per Bbl and as low as $28.07
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
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;
13
o pressure or irregularities in formations;
o equipment failures or accidents;
o adverse weather conditions;
o shortages in experienced labor;
o compliance with governmental requirements; 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 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.
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 as a result of:
o personal injuries or loss of life;
o severe damage to or destruction of property, natural resources and
equipment;
o pollution or other environmental damage due to spills or other
discharges of hazardous materials;
o clean-up and remediation responsibilities and costs;
o regulatory investigations and penalties; and/or
o suspension of operations.
14
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 our 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.
Other independent oil and gas companies' limited access to capital may change
our exploration and development plans.
Many independent oil and gas companies have limited access to the
capital necessary to finance their activities. As a result, some of the other
working interest owners of our wells may be unwilling or unable to pay their
share of the costs of projects as they become due. These problems could cause us
to change, suspend or terminate our drilling and development plans with respect
to the affected project.
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.
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
15
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.
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. We currently do not have employment agreements with our executive
officers other than Mark Hellerstein, our Chief Executive Officer. We do not
carry any key person life insurance policies.
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
16
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.
The market price of our common stock has been volatile. From January 1,
2002, to February 20, 2004, the last daily sale price of our common stock
reported by the New York Stock Exchange or the NASDAQ National Market ranged
from a low of $18.75 per share to a high of $30.70 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.
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 noncumulative 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
We have a stockholder rights plan that was adopted by our Board of
Directors in 1999. The plan is designed to enhance the board's ability to
prevent an acquirer from depriving stockholders of the long-term value of their
investment and to protect stockholders against attempts to acquire us by means
of unfair or abusive takeover tactics. If the Board of Directors decides in
accordance with its fiduciary obligations that the terms of a potential
acquisition do not reflect the long-term value of St. Mary, the Board of
17
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 20, 2004, we had 28,339,963 shares of common stock
outstanding. Of the shares outstanding, approximately 27,156,818 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
3,431,278 shares of our common stock were outstanding, of which 2,347,985 were
exercisable. These options are exercisable at prices ranging from $9.25 to
$33.31 per share. Sales of substantial amounts of common stock, or a perception
that such sales could occur, and the existence of options or warrants to
purchase shares of commons 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 approximately 14.4 percent of the
outstanding shares of our common stock as of February 20, 2004. While no formal
arrangements exist, these extended family members may 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 bank 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
share or discontinue the payment of dividends altogether. Our credit facility
limits the annual per share dividend rate that we may pay to $0.20.
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;
18
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, expected
acquisition benefits, production rates and reserve replacement, reserve
estimates, drilling and operating risks, competition, 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.
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.
19
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.
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
by the amount of estimated net proved reserves added during the same period
(including the effect on proved reserves of reserve revisions).
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.
20
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 heat
required to raise the temperature of a one-pound mass of water 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.
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.
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.
21
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.
ITEM 2. PROPERTIES
Operations
St. Mary's exploration, development and acquisition activities are
focused in five core operating areas: the Mid-Continent region; the Gulf Coast
region; the ArkLaTex region; the Rocky Mountain region in Montana, North Dakota
and Wyoming; and the Permian Basin region in West Texas and New Mexico.
Information concerning each of our major areas of operations, and summary of our
estimated proved reserves as of December 31, 2003, is shown below.
Estimated Proved Reserves
-------------------------------------------------------
Oil Gas MMCFE PV-10 Value
------------------------- ------------------------------
(MBbl) (MMcf) Amount Percent (In thousands) Percent
----------- ----------- ----------- ---------- ----------------- ---------
Mid-Continent 1,090 145,611 152,148 26% $ 405,304 32%
Rocky Mountain 37,730 63,752 290,133 49% 514,134 40%
ArkLaTex 1,299 60,032 67,826 11% 155,944 12%
Gulf Coast 328 31,096 33,065 5% 112,426 9%
Permian Basin 7,340 6,533 50,572 9% 90,358 7%
----------- ----------- ----------- ---------- ----------------- ---------
Total 47,787 307,024 593,744 100% $ 1,278,166 100%
=========== =========== =========== ========== ================= =========
Mid-Continent Region. Since 1973 St. Mary has been active in the
Mid-Continent region. Operations there are managed by our 35-person Tulsa,
Oklahoma office. We have ongoing exploration and development programs in the
Anadarko and Arkoma basins of Oklahoma and Texas. The Mid-Continent region
accounts for 26 percent of our estimated proved reserves as of December 31,
2003, or 152.1 BCFE, 85 percent of which were proved developed and 96 percent of
which were natural gas. In 2003 our capital expenditures in the Mid-Continent
were $72.2 million. We participated in drilling 77 gross wells in this region in
2003, 90 percent of which were completed as producers. We operated 39 of these
drilling projects. In addition, we participated in 10 gross recompletions with
the same 90 percent success rate.
St. Mary's development and exploration budget in the Mid-Continent
region for 2004 totals $59.5 million. We plan to operate 31 drilling wells in
the Mid-Continent region during 2004 and to utilize five to seven drilling rigs
throughout the year. Our 2004 budget also reflects participation in an
additional 16 wells to be operated by other entities.
Anadarko Basin. 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 state of the art
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 continue to benefit from the continuing consolidation of
operators in the basin as we pursue attractive opportunities to acquire
properties.
22
Approximately 77 percent of our 2004 Mid-Continent capital budget is
allocated to deeper, higher-potential wells in the Morrow/Springer formations as
well as the Atoka formations at the Northeast Mayfield Field in Beckham County,
Oklahoma on the southern edge of the Anadarko Basin. The remaining 23 percent of
the drilling activities for 2004 will be focused on low-to-medium-risk
development in the Cromwell, Granite Wash, Osborne, Red Fork and Spiro
formations.
The Northeast Mayfield prospect is the largest concentration of our
reserves. This field represents approximately 39 BCFE or seven percent of our
proved reserves and $123.5 million, or approximately 10 percent of our total
PV-10 value. Our average working interest in this field is 25 percent, and we
have an interest in approximately 48 gross wells of which we operate 38 percent.
Other significant fields in the Mid-Continent region are the Centrahoma
field located in Coal County, Oklahoma in the Arkoma Basin and the Elk City
field in Beckham County, Oklahoma. Centrahoma represents three percent of total
proved reserves and $41.4 million or three percent of total PV-10 value, and Elk
City represents two percent of total proved reserves and $36.0 million of PV-10
value. Here we operate 86 percent and 16 percent of the wells in the respective
fields and have an average working interest of approximately 72 percent and 14
percent, respectively.
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 on our behalf since 1991. This area has
expanded into the Green River and Wind River basins with properties acquired
from Choctaw and Flying J and into the Hanging Woman Basin with our coal-bed
methane project. The acquisition of the Flying J properties added approximately
92.0 BCFE of reserves to the Company as of the acquisition date. In total, the
Rocky Mountain region accounted for 49 percent of our estimated proved reserves
as of December 31, 2003, or 290.1 BCFE, 95 percent of which were proved
developed and 78 percent of which were oil.
Our office in Billings, Montana includes a 58-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.
St. Mary spent $100.3 million on exploration, development and
acquisitions in the Williston Basin in 2003. The acquisition of the Flying J
properties comprised $68.7 million of our total property acquisitions for the
Company. As of the end of 2003, the Flying J properties were producing 2,112
barrels of oil and 7,362 Mcf of gas on a daily basis. In total, the incremental
production from the Flying J acquisition in 2003 was 7.3 BCFE.
Our capital budget for the Rocky Mountain region is approximately $63.9
million in 2004. This increase is a result of the increased development of the
dolomite portion of the Bakken formation and $12.2 million is dedicated to the
development of our coalbed methane project at Hanging Woman Basin. In 2004 we
plan to drill 26 conventional operated wells with working interests ranging from
25 percent to 100 percent, with nine of these wells having a working interest
greater than 90 percent. We also plan to drill 112 wells in our coalbed methane
project at Hanging Woman Basin, all of which we will operate. We will operate
projects representing approximately $43.4 million of the total Rocky Mountain
budget.
The concentration of our fields is less significant in the Rocky
Mountains. The total of the Rough Rider, the Bainville North, Brush Lake and
Standard Draw fields represent approximately 47.9 BCFE (7.9 MBOE) or eight
percent of our total proved reserves. The PV-10 value represented by these four
fields is $90.4 million, approximately 7 percent of our total reserves. Our
average working interest varies from a low of 27 percent in the Standard Draw
23
field to a high of 98 percent in the Brush Lake field.
ArkLaTex Region. Our 18-person office in Shreveport, Louisiana manages
St. Mary's operations in the ArkLaTex region. The ArkLaTex region accounts for
11 percent of our estimated proved reserves as of December 31, 2003, or 67.8
BCFE; 80 percent of which were proved developed and 89 percent of which were
natural gas. In 1992, we acquired oil and gas properties and rights to over
6,000 square miles of proprietary 2-D seismic data in the region. Much 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.
Our holdings in the ArkLaTex region are comprised of interests in
approximately 346 producing gross wells, including 104 wells operated by us;
interests in leases totaling approximately 76,400 gross acres; and mineral
servitudes totaling approximately 14,300 gross acres. The development of the
Huxley field in Shelby County, Texas was the focus of the 2003 activity for the
region. This field represents 14.6 BCFE or two percent of the total reserves for
the Company. The PV-10 value attributable to the Huxley field is $41.4 million.
The Box Church Field located in Limestone County, Texas represents three percent
of our proved reserves and two percent of PV-10 value and continues to be a
highly profitable area for St. Mary. Production from the Box Church Field in
2003 was 1.3 BCFE.
In 2004 we will continue to focus on the search for new opportunities
and potential analog fields in which to apply our proprietary geologic models
and production techniques. We anticipate participating in 41 gross wells in the
ArkLaTex region and will operate 24 of those drilling projects. The total
capital expenditures budgeted for the region in 2004 is $21.6 million and will
include drilling in the Spider prospect and a mix of exploratory and development
programs throughout our prospect inventory.
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
$4.6 million of gross oil and gas royalty revenue in 2003. Our Gulf Coast region
presence increased significantly in 1999 with the acquisition of King Ranch
Energy. The Gulf Coast region accounts for six percent of our estimated proved
reserves as of December 31, 2003, or 33.1 BCFE, 94 percent of which were proved
developed and 31.1 BCF of which were natural gas.
Our team based in Houston, Texas manages St. Mary's diverse activities
in our Gulf Coast and Permian Basin regions. Moving the Gulf Coast operations
from Lafayette, Louisiana to Houston is anticipated to be a catalyst for growth
for us in the region. Our exploration and development budget in the Gulf Coast
region for 2004 is $18.4 million of which 55 percent of these expenditures will
be for operated projects.
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 2003, this field represented slightly more than three percent of
our total PV-10 value with 12.6 BCFE of proved reserves. Production from the
Judge Digby field totaled 6.5 BCFE in 2003. Production from this field continues
to decrease and this area is becoming a smaller component of the value of the
Company.
24
Fee Lands. Since the initial discovery of oil on our fee lands in 1938, our
cumulative oil and gas revenues, primarily landowner's royalties, from the Bayou
Sale, Horseshoe Bayou and Belle Isle fields have exceeded $245 million. We
currently lease 9,945 acres and have granted a seismic option to Seismic
Exchange, Inc. on the remaining 14,969 acres. A 3-D seismic shoot over the
entire fee land has been concluded and we anticipate receiving the newly shot
and processed 3-D seismic early in 2004. These optioned acres are located
primarily in the middle portion of our property where little exploration has
taken place historically. If the lease option is exercised, the lease will
provide us a 25 percent royalty and the option to participate for up to 25
percent as a working interest owner. This working interest election is an
individual well-by-well election. We are hopeful this will encourage development
drilling by our lessees, facilitate the origination of new prospects and
stimulate exploration interest in deeper, untested horizons. However, there can
be no assurance that such activities will result. Our principal operators on the
fee properties are BP, Cabot and Amerada Hess.
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. 3-D seismic imaging of
existing fields and advanced secondary recovery programs are substantially
increasing oil recoveries in the Permian 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 secondary recovery projects. The Permian Basin region accounted
for nine percent of our estimated proved reserves as of December 31, 2003, or
50.6 BCFE, of which 70 percent were proved developed and 87 percent were oil.
St. Mary participated in drilling 19 gross wells in 2003 with a 74
percent success rate. The Parkway Delaware water flood project, located in Eddy
County, New Mexico represents 19.8 BCFE or three percent of our proved reserves.
The East Shugart Delaware Unit is a pilot water flood located in Lea and Eddy
Counties, New Mexico that is analogous to the Parkway Delaware Unit. In the
fourth quarter of 2003, production increased in response to pilot water flood
activities. Proved reserves, primarily related to increased recovery due to the
water flood, now total 15.0 BCFE. Production from the Permian Basin properties
represented 4 BCFE or five percent of the total production for the Company in
2003.
Our Permian Basin capital budget for 2004 is $10.0 million. We plan to
drill four injection wells and perform recompletion work in the East Shugart
Delaware waterflood, and we plan to drill six in-fill wells in the Parkway
field.
Acquisitions and Divestitures
In addition to the acquisition from Flying J of the oil and gas
properties in the Rocky Mountain region, we completed a few smaller niche
acquisitions during the past year. In January 2003 we acquired the remaining 50
percent interest in the Ft. Chadbourne field in Coke and Runnels Counties, Texas
at a favorable price. Later in the year, we sold our 100 percent working
interest ownership in the Ft. Chadbourne field, recognizing a gain on the sale.
In total the acquisitions in 2003 added 112.4 BCFE of proved reserves
of which 87 percent was proved developed. In addition to the proved reserves, we
acquired significant leasehold acreage in the Flying J acquisition.
The total dispositions of oil and gas properties in 2003 resulted in
net proceeds of $23.5 million, and the reserves attributable to the sales were
45.6 BCFE.
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, 2003, as prepared by both Ryder Scott
Company, independent petroleum engineers, and us. For the periods presented,
Ryder Scott Company evaluated properties representing a minimum of 80 percent of
our total PV-10 value while we evaluated the remainder. 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
sections entitled "Risk Factors - Risks Related to Our Business - Estimates of
oil and gas reserves are not precise."
As of December 31,
-------------------------------------------------------------------
Proved Reserves Data: 2003 2002 2001
- --------------------------------------------- --------------------- ------------------- -------------------
Oil (MBbl) 47,787 36,119 23,669
Gas (MMcf) 307,024 274,172 241,231
MMCFE 593,744 490,887 383,247
PV-10 value, without tax effect (in
thousands) (1) $ 1,278,166 $ 824,808 $ 363,795
Standardized measure of discounted
future net cash flows (in thousands) $ 859,956 $ 581,862 $ 281,877
Proved developed reserves 89% 88% 86%
Production replacement 293% 306% 166%
Reserve life (years) (2) 7.7 8.9 7.1
- ----------------
(1) PV-10 value as of December 31, 2003, was calculated using the weighted
average sales price of $31.01 per barrel of oil and $5.70 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, 2003, 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,
-----------------------------------------------------
2003 2002 2001
---------------- ---------------- ----------------
Operating Data:
Net production:
Oil (MBbl) 4,541 2,815 2,434
Gas (MMcf) 49,663 38,164 39,491
MMCFE 76,909 55,055 54,093
Average net daily production:
Oil (Bbl) 12,441 7,713 6,667
Gas (Mcf) 136,062 104,558 108,195
MCFE 210,709 150,836 148,199
Average sales price (1):
Oil (per Bbl) $ 26.96 $ 25.34 $ 23.29
Gas (per Mcf) $ 4.89 $ 3.00 $ 3.73
Additional per MCFE data:
Lease operating expense $ 0.77 $ 0.66 $ 0.75
Transportation costs $ 0.09 $ 0.06 $ 0.04
Production taxes $ 0.29 $ 0.20 $ 0.23
General and administrative $ 0.33 $ 0.26 $ 0.22
Depreciation, depletion, amortization
and liability accretion $ 1.07 $ 0.99 $ 0.95
- --------------------------------
(1) Includes the effects of St. Mary's hedging activities. See
"Management's Discussion and Analysis of Financial Condition and
Results of Operations."
27
Productive Wells
As of December 31, 2003, we had working interests in 1,449 gross (737
net) productive oil wells and 1,616 gross (370 net) productive gas wells.
Productive wells are either producing wells or wells capable of commercial
production although currently shut in. One or more completions in the same
wellbore are counted as one well. A well is categorized under state reporting
regulations as an oil well or a gas well based upon the ratio of gas to oil
produced when it first commenced production, and such designation may not be
indicative of current production.
Drilling Activity
All of our drilling activities are conducted on a contract basis with
independent drilling contractors. We do not own any drilling equipment. The
following table sets forth the wells drilled and recompleted in which St. Mary
participated during each of the three years indicated:
Years Ended December 31,
-----------------------------------------------------------------------------
2003 2002 2001
------------------------- ------------------------ ------------------------
Gross Net Gross Net Gross Net
------------ ----------- ----------- ----------- ---------- ------------
Development:
Oil 36 14.88 26 11.52 48 14.49
Gas 140 43.79 103 38.89 154 33.28
Non-productive 37 15.98 27 14.42 31 7.13
------------ ----------- ----------- ----------- ---------- ------------
213 74.65 156 64.83 233 54.90
------------ ----------- ----------- ----------- ---------- ------------
Exploratory:
Oil 7 3.03 3 1.22 3 1.55
Gas 14 7.20 1 0.10 9 1.84
Non-productive 7 4.40 8 2.64 7 2.56
------------ ----------- ----------- ----------- ---------- ------------
28 14.63 12 3.96 19 5.95
------------ ----------- ----------- ----------- ---------- ------------
Farmout or non-consent 10 - 8 - 9 -
------------ ----------- ----------- ----------- ---------- ------------
Total (1) 251 89.28 176 68.79 261 60.85
============ =========== =========== =========== ========== ============
- ----------------------
(1) Does not include 15, 14 and 12 gross wells completed on St. Mary's fee
lands during 2003, 2002 and 2001, 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, 2003. 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 2,136 356 167 28 2,303 384
Colorado 2,645 2,553 26,164 13,120 28,809 15,673
Louisiana 93,833 33,184 30,168 14,923 124,001 48,107
Montana 72,200 38,703 527,930 365,336 600,130 404,039
New Mexico 7,480 2,255 1,280 916 8,760 3,171
North Dakota 147,110 81,178 140,466 89,349 287,576 170,527
Oklahoma 231,386 62,246 47,835 23,230 279,221 85,476
Texas 101,407 31,027 63,192 19,875 164,599 50,902
Utah (3) 480 115 10,107 8,906 10,587 9,021
Wyoming 58,861 27,562 427,382 264,503 486,243 292,065
Other (4) 2,824 857 9,676 6,140 12,500 6,997
---------- ---------- ----------- --------- ----------- -----------
720,362 280,036 1,284,367 806,326 2,004,729 1,086,362
---------- ---------- ----------- --------- ----------- -----------
Louisiana Fee Properties 9,944 9,944 14,970 14,970 24,914 24,914
Louisiana Mineral Servitudes 9,745 5,306 4,551 4,228 14,296 9,534
---------- ---------- ----------- --------- ----------- -----------
19,689 15,250 19,521 19,198 39,210 34,448
---------- ---------- ----------- --------- ----------- -----------
Total 740,051 295,286 1,303,888 825,524 2,043,939 1,120,810
========== ========== =========== ========= =========== ===========
- -----------------
(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 41,523
gross acres in Utah.
(4) Includes interests in Alabama, Kansas, Mississippi, Nevada, South Dakota,
and Washington.
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 this date,
no legal proceedings are pending against us that 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 has appealed this decision and the Ninth Circuit Court of Appeals has
granted expedited status to this appeal. Briefing should be complete by the end
of the first quarter of 2004, but that does not necessarily indicate when the
Ninth Circuit Court of Appeals will render a decision. Notwithstanding our
success in the lower court, there is no assurance as to the 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 2003.
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 51 Chairman of the Board, President and Chief
Executive Officer
Douglas W. York 42 Executive Vice President and Chief Operating
Officer
Robert L. Nance 67 Senior Vice President, and President and Chief
Executive Officer of Nance Petroleum
Corporation, a wholly-owned subsidiary of
St. Mary
Jerry R. Schuyler 48 Senior Vice President and Regional Manager
Kevin E. Willson 47 Senior Vice President - Mid-Continent Drilling
and Production
Robert T. Hanley 57 Vice President - Investor Relations and
Management Reporting
David W. Honeyfield 37 Vice President - Finance, Treasurer and
Secretary
Milam Randolph Pharo 51 Vice President - Land and Legal
Garry A. Wilkening 53 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 1995.
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
31
Financial Officer of Panterra Petroleum, a partnership between St. Mary and
Nance Petroleum Corporation, from 1992 to 1999.
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 2003. 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 EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information. St. Mary's common stock is currently traded on the
New York Stock Exchange under the symbol SM after transferring from the NASDAQ
National Market System on November 20, 2002. The range of high and low sales
prices for the quarterly periods in 2003 and 2002, as reported by the New York
Stock Exchange after November 19, 2002, and the NASDAQ National Market System
before November 20, 2002, is set forth below:
Quarter Ended High Low
- ------------------------- ----------------- -----------------
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
December 31, 2002 $ 27.35 $ 23.16
September 30, 2002 24.71 19.00
June 30, 2002 25.05 21.00
March 31, 2002 23.25 18.75
32
Holders. As of February 20, 2004, the number of record holders of St.
Mary's common stock was 173. Management believes, after inquiry, that the number
of beneficial owners of our common stock is in excess of 3,700.
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 2003. We expect that our practice of paying dividends on our common
stock will continue, although the payment of future dividends on our common
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 bank credit facility, including the requirement that we
maintain certain levels of stockholders' equity and the limitations 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 $3.1 million in 2003 and
$2.8 million in 2002.
Restricted Shares. On January 29, 2003, St. Mary issued 3,380,818
restricted shares of our common stock in connection with the acquisition of oil
and gas properties from Flying J Oil & Gas Inc. and Big West Oil & Gas
Inc. As of December 31, 2003 these shares were subject to contractual
restrictions on transfer for a period of two years. The Company repurchased
these shares on February 9, 2004 in a separately negotiated transaction.
Issuer Purchases of Equity Securities. St. Mary did not repurchase any
shares of its common stock during the fourth quarter of 2003.
Equity Compensation Plans. St. Mary has a stock option plan, an
incentive stock option plan, an employee stock purchase plan and 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 of the Notes to Consolidated
Financial Statements included in 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, 2003:
( a ) ( b )
Number of securities Weighted-average ( c )
to be issued upon exercise price of Number of securities
Exercise of outstanding options, remaining available for
outstanding options, Warrants and rights future issuance under
warrants and rights equity compensation
plans (excluding
securities reflected in
Plan Category column (a))
- ----------------------------------- --------------------- --------------------- --------------------------
Equity compensation plans approved
by security holders 3,525,128 $ 23.12 1,723,013 (1)
Equity compensation plans not
approved by security holders - - -
--------------------- --------------------- --------------------------
Total 3,525,128 $ 23.12 1,723,013
===================== ===================== ==========================
- --------------
(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 selected consolidated financial 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,
-------------------------------------------------------------------
2003 2002 2001 2000 1999
------------- ------------ ------------ ------------- -------------
(In thousands, except per share data)
Income Statement Data:
Operating revenues:
Oil and gas production $365,114 $185,670 $203,973 $188,407 $ 73,387
Gas marketing revenue 13,438 8,399 420 - -
Gain (loss) on sale of proved properties 7,278 (2,633) 367 3,404 (55)
Derivative gain - 3,188 - - -
Other
8,104 1,770 2,709 3,855 1,582
------------- ------------ ------------ ------------- -------------
Total operating revenues 393,934 196,394 207,469 195,666 74,914
------------- ------------ ------------ ------------- -------------
Operating expenses:
Oil and gas production 88,509 50,839 55,000 38,461 19,574
Depletion, depreciation & amortization 81,960 54,432 51,346 40,129 22,574
Exploration 26,653 19,501 19,518 9,633 11,593
Impairment of proved properties 185 - 820 4,449 3,982
Abandonment and impairment of
unproved properties 3,796 2,446 3,865 1,841 6,616
General and administrative 25,179 14,299 11,762 11,166 9,172
Gas marketing expense 12,229 7,982 420 - -
Derivative loss 310 - 1,573 - -
Other 1,802 1,206 1,253 1,437 1,802
------------- ------------ ------------ ------------- -------------
Total operating expenses 240,623 150,705 145,557 107,116 75,313
------------- ------------ ------------ ------------- -------------
Income (loss) from operations 153,311 45,689 61,912 88,550 (399)
Non-operating (expense) income (7,241) (3,110) 376 737 75
Income tax (expense) benefit (55,930) (15,019) (21,829) (33,667) 406
------------- ------------ ------------ ------------- -------------
Income before cumulative effect of change
in accounting principle 90,140 27,560 40,459 55,620 82
Cumulative effect of change in accounting
principle, net of income taxes 5,435 - - - -
------------- ------------ ------------ ------------- -------------
Net income $ 95,575 $ 27,560 $ 40,459 $ 55,620 $ 82
============= ============ ============ ============= =============
34
Years Ended December 31,
------------------------------------------------------------------
2003 2002 2001 2000 1999
------------ ------------ ------------- ------------ --------------
(In thousands, except per share data)
Basic earnings per common share
Income before cumulative effect of change
in accounting principle $ 2.89 $ 0.99 $ 1.45 $ 2.00 $ -
Cumulative effect of change in accounting
principle 0.17 - - - -
------------ ------------ ------------- ------------ --------------
Basic net income per common share $ 3.06 $ 0.99 $ 1.45 $ 2.00 $ -
============ ============ ============= ============ ==============
Diluted earnings per common share:
Income before cumulative effect of change
in accounting principle $ 2.65 $ 0.97 $ 1.42 $ 1.97 $ -
Cumulative effect of change in accounting
principle 0.15 - - - -
------------ ------------ ------------- ------------ --------------
Diluted net income per common share $ 2.80 $ 0.97 $ 1.42 $ 1.97 $ -
============ ============ ============= ============ ==============
Basic weighted average common shares
outstanding 31,233 27,856 27,973 27,781 22,198
Diluted weighted average common shares
outstanding 35,534 28,391 28,555 28,271 22,329
Cash dividends per share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.10
Balance Sheet Data (end of period):
Working capital $ 3,101 $ 2,050 $ 34,000 $ 40,639 $ 13,440
Net property and equipment 611,287 471,939 358,930 252,411 180,664
Total assets 735,854 537,139 436,989 321,895 230,438
Long-term obligations 110,696 113,601 64,000 22,000 13,000
Total stockholders' equity 390,653 299,513 286,117 250,136 188,772
Other Data:
Net Cash provided by (used in):
Operating activities 204,319 141,709 127,492 92,267 40,755
Investing activities (196,939) (180,931) (159,075) (112,868) (22,243)
Financing activities (3,707) 46,260 29,080 13,025 (12,138)
Capital and exploration expenditures, cash and
non cash, including asset retirement
obligation 236,949 192,988 182,863 125,184 91,184
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 at the wellhead 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, 2003, we had estimated proved reserves of 593.7 BCFE, with a
before income tax PV-10 value of $1.3 billion and an after income tax value of
$860.0 million.
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 2003 oil and gas producers enjoyed high oil and gas commodity
prices, primarily due to colder winter weather in the northeast, falling
domestic gas deliverability, and very low gas storage levels creating a near
shortage situation early in the year.
Reserve Replacement and Growth
Like all oil and gas exploration and production companies, we face the
challenge of natural resource production decline. As oil and gas is depleted
from a well, oil and gas production from that well naturally decreases. 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, through acquisitions and
drilling, more reserves 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. We have successfully achieved this goal over
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.
36
In 2003 our pre-tax PV-10 value for proved reserves increased 55
percent to $1.3 billion, with a standardized measure value of $860.0 million,
reflecting a 21 percent increase in reserves as well as 5 percent and 37 percent
respective increases in oil and gas reserve pricing, to $31.01 per barrel and
$5.70 per Mcf.
Included in the proved reserve increase noted above is a positive
revision of 21.0 BCFE, of which 14.3 BCFE related to positive well performance.
We replaced 293 percent of our 2003 production at a finding cost of $1.05 per
MCFE, including the impact of asset retirement obligations. Relative to our
peers we have a very low PUD percentage of 11 percent at year-end. We are
pleased with these results and believe they compare favorably with industry
results.
2003 Highlights
In 2003 we enjoyed record earnings, high oil and gas prices, a 40
percent increase in production, a 21 percent increase in proved reserves
obtained at a low reserve replacement cost, moderate increases in operating
costs, profitable sales of non-strategic assets, and advancement of the Hanging
Woman Basin coalbed methane project to the development stage. Highlights for
2003 also include good drilling results at Huxley in East Texas and Northeast
Mayfield in Oklahoma; participation in the new Bakken horizontal dolomite play
in the Williston Basin; better than expected production performance at the
Parkway Delaware waterflood project in the Permian Basin and at the Judge Digby
field in South Louisiana; and increased production from the acquisition of
properties in the Rocky Mountain region from Flying J in January 2003 and from
Burlington Resources in December 2002. We opened a Houston office, which will
now be directing our Gulf Coast and Permian Basin regional operations.
In 2003 colder winter weather in the northeast, falling domestic gas
deliverability, and very low gas storage levels created a near shortage
situation early in the year and acted as a catalyst for extremely high prices
during the first quarter. Moderate summer weather and decreased demand allowed
gas storage to refill to normal levels at the beginning of the 2003-2004 winter
season. Despite these factors, gas prices remained strong due to the industry's
inability to grow deliverability from the maturing basins of North America and
due to difficulties encountered in both obtaining access to the vast public
lands of the western United States and building a pipeline to transport Alaskan
natural gas to the lower 48 states. Oil prices were also very strong, reflecting
low inventories and uncertainties resulting from a Venezuelan strike, West
African unrest, the Iraqi war, the OPEC action to curtail production to maintain
its desired price target and crude oil refining issues in the United States.
NYMEX prices for the year averaged $5.39 per MMBtu and $30.97 per barrel, up 41
percent on a realized MCFE basis. At December 31, 2003, the 12-month NYMEX strip
was $29.98 per barrel for oil and $5.37 per MMBtu for gas.
Net income for the year 2003 was a record $95.6 million or $2.80 per
diluted share compared to $27.6 million or $0.97 per diluted share for the prior
year. Net cash provided by operating activities was $204.3 million, up 44
percent, from 2002. Production increased 40 percent to 76.9 BCFE. Our average
realized price increased 41 percent to $4.75 per MCFE. Unit costs increased
modestly for the period as lease operating expense (including taxes) increased
$0.23 to $1.15 per MCFE, DD&A (including impairments) increased $0.08 to
$1.07 per MCFE and general and administrative expense increased $0.06 to $0.33
per MCFE.
2004 Outlook
We enter 2004 on a positive note. Oil and gas prices are high, and the
long-term outlook is positive. We have attractive prospects to be drilled. Rig
and other service costs are moderate. The country's ability to supply gas
remains challenging as the average decline rate for natural gas has increased
37
from 17 percent to 28 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, and better
completion techniques that allow reserves to be produced faster. New sources of
gas such as LNG, frontier regions (e.g. deepwater Gulf of Mexico and Mackenzie
Delta, Alaska) and unconventional gas plays are both more costly and have long
lead times, but at some point could have a positive impact on supply. We believe
oil prices are unusually high now due to low inventory levels. Longer term,
however, we are beginning to see excess oil capacity in the world diminish and
OPEC informally appearing to target a higher price range due to the decline in
the value of the dollar. As the global economy continues to recover from the
recent economic downturn, we anticipate the demand for oil will increase.
We enter 2004 in very good financial condition and with a capital
expenditure budget of $273.4 million. Here is our plan to build value in 2004:
o Of the $273.4 million capital expenditures budget, 36 percent is
allocated for acquisitions, 22 percent for exploration and
development in the Mid-Continent region, 19 percent in the Rocky
Mountain region, 8 percent in the ArkLaTex region, 7 percent in the
Gulf Coast region and 4 percent in the Permian region. Four percent
of the budget is allocated to development of our Hanging Woman Basin
coalbed methane play and other CBM projects. The 2004 exploration
and development budget is $173.4 million, which represents a 28
percent increase over the 2003 exploration and development budget.
o We will begin development of our Hanging Woman Basin coalbed methane
project with the drilling of approximately 100 wells in Wyoming and
the construction of infrastructure such as electric grid and
pipeline. We currently expect production of natural gas to begin in
2005.
o In early 2004 we will receive newly shot and processed 3-D seismic
covering our entire 24,914 fee acreage position in St. Mary Parish,
Louisiana. We have optioned 14,969 acres for lease primarily in the
middle portion of our property where little exploration has
historically taken place. Providing the option is exercised, the
lease terms will give us a 25 percent royalty interest and the
option to participate for up to 25 percent as a working interest
owner if the lease option is exercised. We can make the working
interest elections on an individual well-by-well basis.
38
A year-to-year overview of selected reserve, production and financial
information, including trends:
Selected Operations Data (In Thousands, Except Price and Per MCFE Amounts):
- ---------------------------------------------------------------------------
As of and for the Years Ended % of Change Between
------------------------------------------
2003 2002 2001 2003/2002 2002/2001
------------ ----------- ----------- --------- ---------
Total Proved Reserves (SEC Case 10 Basis)
- ------------------------------------------
Natural Gas (Mcf) 307,024 274,172 241,231
Oil (Bbl) 47,787 36,119 23,669
MCFE 593,744 490,887 383,247 21% 28%
Net Production Volumes
- ----------------------
Natural Gas (Mcf) 49,663 38,164 39,491
Oil (Bbl) 4,541 2,815 2,434
MCFE 76,909 55,055 54,093 40% 2%
Oil & Gas Production Revenues
- ---------------------------------
Gas Production $ 242,670 $ 114,334 $ 147,292
Oil Production 122,444 71,336 56,681
------------ ----------- -----------
Total $ 365,114 $ 185,670 $ 203,973 97% (9)%
============ =========== ===========
Oil & Gas Production Costs
- ------------------------------
Lease Operating Expenses $ 59,152 $ 36,472 $ 40,505
Transportation Costs 7,197 3,184 2,321
Production Taxes 22,160 11,183 12,174
------------ ----------- -----------
Total $ 88,509 $ 50,839 $ 55,000 74% (8)%
============ =========== ===========
Average Realized Sales Price (1)
- --------------------------------
Natural Gas (Per Mcf) $ 4.89 $ 3.00 $ 3.73 63% (20)%
Oil (Per Bbl) $ 26.96 $ 25.34 $ 23.29 6% 9%
Per MCFE Data:
- --------------
Net Realized Price $ 4.75 $ 3.37 $ 3.77 41% (11)%
Lease Operating Expense (0.77) (0.66) (0.75) 17% (12)%
Transportation Costs (0.09) (0.06) (0.04) 50% 50%
Production Taxes (0.29) (0.20) (0.23) 45% (13)%
General and Administrative (0.33) (0.26) (0.22) 27% 19%
------------ ----------- -----------
Operating Profit $ 3.27 $ 2.19 $ 2.53 49% (13)%
============ =========== ===========
Depletion, Depreciation and Amortization $ 1.07 $ 0.99 $ 0.95 8% 4%
Financial Information (In Thousands, Except Per Share Amounts):
- ---------------------------------------------------------------
As of and for the Years Ended % of Change Between
------------------------------------------
2003 2002 2001 2003/2002 2002/2001
------------ ----------- ----------- --------- ---------
Working Capital $ 3,101 $ 2,050 $ 34,000 51% (94)%
Long-Term Debt $ 110,696 $ 113,601 $ 64,000 (3)% 78%
Stockholders' Equity $ 390,653 $ 299,513 $ 286,117 30% 5%
Net Income $ 95,575 $ 27,560 $ 40,459 247% (32)%
Basic Net Income Per Common Share $ 3.06 $ 0.99 $ 1.45 209% (32)%
Diluted Net Income Per Common Share $ 2.80 $ 0.97 $ 1.42 189% (32)%
Basic Weighted Average Shares Outstanding 31,233 27,856 27,973 12% -%
Diluted Weighted Average Shares Outstanding 35,534 28,391 28,555 25% (1)%
Net Cash Provided By Operating Activities $ 204,319 $ 141,709 $ 127,492 44% 11%
Net Cash Used In Investing Activities $ (196,939) $(180,931) $(159,075) 9% 14%
Net Cash Provided By (Used In) Financing
Activities $ (3,707) $ 46,260 $ 29,080 (108)% 59%
- ---------------------
(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.
We have experienced a 60 percent increase in reserve volumes over the
two years presented above. These increases are a result of drilling results
which added 131.6 BCFE, acquisitions which added 214.6 BCFE, a 130 percent
increase in natural gas prices used to evaluate reserves, and a 71 percent
increase in crude oil prices used to evaluate reserves. We target replacing 200
percent of our production each year. We anticipate that we must continue our
successful drilling program and make one or more relatively significant
acquisitions per year in the current price environment to achieve this level of
growth. If we achieve our goal but commodity prices decrease, we may not be able
to sustain the 2003 results we attained.
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 2001 or 2003.
We closed our acquisition of Burlington properties in late 2002 and our
acquisition of 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 to result in a 40 percent increase in production from 2002 to
2003.
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 2004 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.
General and administrative expense is also projected to increase for
compensation expense associated with our net profits interest bonus plan,
expensing of stock-based compensation and costs we incur to comply with
legislative responses to the recent scandals that have plagued corporate
America.
Excluding the cumulative effect of change in accounting principle, our
net income increase in 2003 was primarily driven by a 40 percent production
increase combined with realized price increases of 63 percent for natural gas
and 6 percent for oil. We note that we contained our costs and, as a result, our
operating profit as a percentage of net realized price was 69 percent in 2003
compared to 65 percent in 2002 and 67 percent in 2001. Net income as a
percentage of oil and gas revenue increased from 20 percent in 2001 and 15
percent in 2002 to 25 percent in 2003.
We have in-the-money stock options and convertible notes that can be
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 earnings per share in 2003
reflects an increase in net income from operations, the effect of a change in
accounting principle offset by increases in outstanding shares related to stock
options, and the shares issued in the Flying J transaction, which we repurchased
in early 2004. The change in diluted earnings per share in 2003 reflects the
inclusion of shares related to our convertible debt offset by the add-back of
interest expense related to that debt.
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.
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
40
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. An unexpected decrease in prices would reduce
expected cash flow from operating activities, might reduce the borrowing base on
our credit facility, could reduce the value of our non-strategic properties and
historically has limited our industry's access to the capital markets.
Our current credit facility. On January 29, 2003, we entered into a new
$300.0 million credit facility with Wachovia Bank as Administrative Agent and
eight other participating banks. This new credit facility replaced a previous
credit facility and has a maturity date of January 27, 2006. The calculated
borrowing base as of December 31, 2003 is $275.0 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. 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,
and Alternate Base Rate borrowings accrue interest at prime plus the applicable
margin from the utilization table located in Note 5 of Part IV, Item 15 of this
report. 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 $11.0 million on December 31,
2003, was comprised of ABR borrowings.
Our weighted average interest rate paid in 2003 was 6.3 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 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, 2003, 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 the interest rate swaps, we had
floating-rate debt of $61.0 million and had $50.0 million of fixed-rate debt at
December 31, 2003. Assuming constant debt levels, the cash flow impact for the
next year resulting from a one-percentage point change in interest rates would
be approximately $610,000 before taxes. The results of operations impact might
be less than this amount as a direct effect of the capitalization of interest to
wells drilled in the next year. In prior years when our debt amount was at a
reduced level we capitalized a larger percentage of our interest expense. Since
we cannot predict the exact amount that would be capitalized, we cannot predict
the exact affect that a one-percentage point shift would have on the results of
operations.
41
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 provides flexibility to modify our
uses of cash flow.
Over the course of 2003 we reduced our outstanding debt by a net $3.0
million, paid $76.4 million for property acquisitions including the $71.6
million loan to Flying J and spent $123.8 million on capital development using
cash flows from operations. We have also made $28.9 million of cash payments for
income taxes.
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 bank credit facility. See Note 13
of Part IV, Item 15 of this report. At February 20, 2004, we have $10.0 million
outstanding on our credit facility.
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
----------------------------- -----------------------------
2003/2002 2002/2001 2003/2002 2002/2001
------------- ------------ ------------- ------------
Net Cash Provided By Operating Activities $ 62,610 $ 14,217 44% 11%
============= ============ ============= ============
Net Cash Used In Investing Activities $ (16,008) $ (21,856) 9% 14%
============= ============ ============= ============
Net Cash Provided By (Used In) Financial Activities $ (49,967) $ 17,180 (108)% 59%
============= ============ ============= ============
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 an
increase in outstanding accounts receivable of $29.7 million at December 31,
2003. 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
42
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 may be used for 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. The volumes, 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 operation
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 bank 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.
Our senior convertible notes. In March 2002 we issued in a private
placement a total of $100.0 million of our 5.75% convertible notes due 2022 with
a 0.5% contingent interest provision. 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. The convertible notes convert 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 notes is in
2007. Our current stock price is in excess of the $26.00 conversion price. 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. On October 3, 2003, we executed new interest rate
swaps on a total notional amount of $50.0 million of the convertible notes which
we expect will lower interest expense in 2004.
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.
Analysis of cash flow changes between 2002 and 2001
Operating activities. The increase reflects a change between years of
$29.3 million in other current assets relating to the collection of receivables,
payment of prepaid items and collection of refundable income taxes. We also had
a change between years of $5.2 million from increased accounts payable. These
items increasing cash flow from operations were offset by a decrease in net
income of $13.1 million and a $7.1 million decrease in the effect of non-cash
items between the periods.
Investing activities. Total 2002 capital expenditures for cash,
including acquisitions of oil and gas properties, increased $13.9 million or 8
percent to $184.7 million in 2002 compared to $170.8 million in 2001 due to an
increase in acquisition activity in 2002 offset by our planned decrease in cash
expended on drilling activities.
43
In November 2001 we purchased oil and gas properties from Choctaw II
Oil & Gas, Ltd. for $40.5 million in cash. We used a portion of our credit
facility for this acquisition.
Financing activities. Net cash provided by financing activities
increased $17.2 million to $46.3 million in 2002 compared to $29.1 million in
2001. This increase reflects our March 2002 private placement of $100.0 million
of 5.75% senior convertible notes due 2022. A portion of the net proceeds of
$96.7 million was used to repay the balance due on our credit facility at that
time. By year end we had borrowed $14.0 million on our credit facility.
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, to acquire additional geoscientists and/or engineers, or gain a
significant acreage and production foothold in a new basin.
Expenditures for exploration and development of oil and gas properties
and acquisitions are the primary use of our capital resources. We anticipate
spending approximately $273 million for capital and exploration expenditures in
2004 with $100 million allocated for acquisitions of producing properties.
Anticipated ongoing exploration and development expenditures for each of our
core areas are as follows (in millions):
o Mid-Continent region $ 59.5
o Rocky Mountain region 51.7
o ArkLaTex region 21.6
o Gulf Coast region 18.4
o Coal Bed Methane 12.2
o Permian Basin region 10.0
--------
$ 173.4
========
We regularly review our capital expenditure budget to reflect changes
in current and projected cash flow, acquisition opportunities, debt requirements
and other factors. The above allocations are subject to change based on various
factors and results.
44
The following table sets forth certain information regarding the costs
incurred by us in our oil and gas activities and the amounts we budgeted for
those activities during the periods indicated.
Years Ended December 31,
----------------------------------------------------
2003 2002 2001
--------------- --------------- ---------------
(In thousands)
Development costs $ 111,908 $ 74,376 $ 98,617
Exploration costs 34,631 22,778 24,506
Acquisitions:
Proved 77,398 87,706 41,188
Unproved 7,480 8,128 18,552
--------------- --------------- ---------------
Total before asset retirement obligation $ 231,417 $ 192,988 $ 182,863
=============== =============== ===============
Total including asset retirement Obligation $ 236,949 $ 192,988 $ 182,863
=============== =============== ===============
Original Budgeted Amount $ 225,000 $ 164,000 $ 155,000
=============== =============== ===============
Long-term debt outstanding on
revolving credit facility $ 11,000 $ 14,000 $ 64,000
=============== =============== ===============
Excluding asset retirement obligation amounts, our costs incurred for
capital and exploration activities in 2003 increased $38.4 million or 20 percent
compared to 2002. We spent $154.0 million in 2003 for unproved property
acquisitions and exploration and development costs compared to $105.3 million in
2002. This increase was a result of a planned $29.7 million increase in the
drilling activity budget and an additional $19.0 million spent on opportunities
that arose during 2003. We reallocated $12.6 million from the acquisitions
budget for these opportunities.
In December 2003 we decided to proceed with the development of coalbed
methane reserves in our Hanging Woman Basin project. We have 139,000 net lease
acres in the basin and plan to concentrate our initial development on 65,000 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.
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 bank credit facility. We
believe that internally generated cash flow and our credit facility will be
utilized in 2004. 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 an economic
acquisition 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.
The budgeted amounts and the long-term debt amounts in the table above indicate
the flexibility we have to respond to investment opportunities.
Financing alternatives
In 2003 and continuing into 2004 we are seeing the debt and equity
financing capital markets open up to energy companies who operate in the
exploration and production segment. This is a result of relatively strong
commodity prices and the general strength reflected in the balance sheets of the
45
companies in this segment. We are not currently considering accessing the
capital markets in 2004. 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. To maintain our financial flexibility we
are likely to begin negotiations on a new credit facility later in the year.
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 20, 2004 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,
-----------------------------------------------------
2003 2002 2001
-------------- ---------------- ---------------
(In thousands)
Natural Gas $ 13,889 $ 6,944 $ 8,982
Oil $ 6,979 $ 4,350 $ 3,476
-------------- ---------------- ---------------
Total $ 20,868 $ 11,294 $ 12,458
============== ================ ===============
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 production to the prices we used to elevate the economics
of our acquisition. The percentage of our production that is hedged currently is
a direct result of the timing of our acquisitions from Burlington and Flying J.
Aside from the major acquisitions our discretionary hedging activity has been
limited.
46
The table below describes the volumes and average contract prices of
hedges we have in place. All of our oil and gas derivatives are swap agreements.
These hedges tend to make our earnings less sensitive to movements in commodity
price and were factored in the analysis of sensitivity above.
Gas (per MMBtu) Oil (per Bbl)
--------------- -------------
Contract Weighted Average Weighted Average
Month Volumes Contract Price Volumes Contract Price
- ----- ------- -------------- ------- --------------
2004
January 1,544,500 $ 4.61 157,500 $ 23.71
February 1,298,300 4.56 153,500 23.71
March 1,293,000 4.57 174,800 24.48
April 738,900 3.72 178,000 24.66
May 731,600 3.72 174,800 24.67
June 725,500 3.73 173,000 24.67
July 722,700 3.73 172,500 24.65
August 716,600 3.74 170,900 24.65
September 712,400 3.74 169,300 24.64
October 710,300 3.74 167,700 24.64
November 620,000 3.83 165,200 24.64
December 617,000 3.83 163,100 24.64
----------------- ------------------- --------------- -------------------
Total 2004 10,430,800 4.08 2,020,300 24.49
----------------- ------------------- --------------- -------------------
2005
January - - 27,000 29.20
February - - 27,000 29.20
March - - 5,900 29.20
----------------- ------------------- --------------- -------------------
Total 2005 - - 59,900 29.20
----------------- ------------------- --------------- -------------------
All Contracts 10,430,800 $ 4.08 2,080,200 $ 24.63
================= =================== =============== ===================
We anticipate that all hedge transactions will occur as expected.
For contracts in place on December 31, 2003, a hypothetical change of
10 percent in future gas strip prices representing a $0.52 increase per MMBtu
applied to a notional amount of 10.4 million MMBtu covered by natural gas swaps
would cause a change in hedge gain or loss included in gas revenue of $5.5
million in 2004. A hypothetical change of 10 percent in the future NYMEX strip
oil prices representing a $3.01 increase per Bbl applied to a notional amount of
2.1 MMBbl covered by crude oil swaps would cause a change in hedge gain or loss
included in oil revenue of $6.1 million in 2004 and $168,000 in 2005.
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. As we do not believe we
have the ability to predict interest rates, we attempt to maintain a balanced
allocation between fixed and floating rate debt. As our usage of the credit
facility 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 Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities."
47
Excluding accrued payments due to us at December 31, 2003, the interest rate
swaps had a fair value liability of $104,000. Unless we access our credit
facility to make an acquisition or interest rates increase dramatically,
interest expense next year should decrease due to these fixed to floating
interest rate swaps.
Schedule of contractual obligations
The following table summarizes our future estimated principal payments
and minimum lease payments for the periods specified (in millions):
Less than More than 5
Contractual Obligations Total 1 year 1-3 years 3-5 years years
- ---------------------------------- ----------- ----------- ----------- ----------- -------------
Long-Term Debt $ 111.0 $ - $ 11.0 $ 100.0 $ -
Operating Leases 10.5 2.2 3.0 2.2 3.1
Other Long-Term Liabilities 8.9 1.0 1.1 0.2 6.6
----------- ----------- ----------- ----------- -------------
Total $ 130.4 $ 3.2 $ 15.1 $ 102.4 $ 9.7
=========== =========== =========== =========== =============
This table includes our 2004 estimated pension liability payment of
approximately $987,000, but excludes the remaining unfunded portion of $1.4
million, as we cannot determine with accuracy the timing of future payments. We
have not included asset retirement obligations for the same reason. Pension
liabilities and asset retirement obligations are discussed in Note 8 and Note 9,
respectively, of Part IV, Item 15 of this report.
In the next year we have one office space lease that will expire. A
second lease for office space will expire in year 3, and a third 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. However, our common shares outstanding would increase by
3,846,150 shares.
Our projected requirements for cash to pay interest, dividends and
income taxes in 2004 are $7.9 million, $3.2 million, and $29.5 million,
respectively.
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 calculated
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
48
accounting policies you should see Note 1 - Summary of Significant Accounting
Policies and Note 11 - 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 estimate an
exploration and production company has because they affect the perceived value
of our company 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 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. 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 reflects the estimated MMCFE change and percentage
change to our reported reserve volumes from the described hypothetical changes:
Years Ended December 31,
--------------------------------------------------------------------------------
2003 2002 2001
------------------------ ----------------------- -------------------------
MMCFE Percent MMCFE Percent MMCFE Percent
Change Change Change Change Change Change
----------- --------- ---------- --------- ----------- ----------
A 10% decrease in Pricing 9,479 2% 8,700 2% 22,629 6%
=========== ========== ===========
A 10% decrease in Proven
Undeveloped Reserves 6,744 1% 6,043 1% 5,353 1%
=========== ========== ===========
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. 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.
49
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 $5.9 million in 2003, $3.7
million in 2002 and $3.3 million in 2001.
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. We include this gain
or loss in oil and gas production revenues. 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 production revenues in our statement 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 2003, 2002 and 2001 by
the following amounts: $(14.3 million), $(6.3 million), and $6.9 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. We evaluate
the realizability of our proved producing and other long-lived assets whenever
events or changes in circumstances indicate that an impairment may have
occurred. Our impairment test compares the expected undiscounted future net
revenues from a property, using escalated pricing with the related net
capitalized costs of the property at the end of each period. When the net
capitalized costs exceed the undiscounted future net revenue of a property, the
cost of the property is written down to our estimate of fair value, which is
determined by applying a 15 percent discount rate to future net revenues. 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
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
50
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. 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 1.0 percent change in our effective tax
rate would have affected our calculated income tax expense by $1.5 million,
$426,000 and $623,000 for the years ended December 31, 2003, 2002 and 2001,
respectively.
Stock options. In December 2002 the FASB issued SFAS No. 148,
"Accounting for Stock-Based Compensation -- Transition and Disclosure: an
amendment of FASB Statement No. 123." This statement amends SFAS No. 123,
"Accounting for Stock-Based Compensation", to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee 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 has been reflected in
our net income 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. This model requires us to make estimates
regarding the risk free interest rate, our dividend yield, the volatility of our
stock price, and the expected life of the options. A change in any one of these
estimates can have a material impact on the amount of calculated compensation
expense. See Notes 1 and 7 of Part IV, Item 15 of this report for additional
details.
51
Additional Comparative Data in Tabular Format:
Change Between Years
----------------------------------------
Oil and Gas Production Revenues 2003 and 2002 2002 and 2001
------------------ ------------------
Increase (decrease) in oil and gas production
revenues (in thousands) $ 179,444 $ (18,303)
================== ==================
Components of Revenue Increases (Decreases):
Natural Gas
- -----------
Price change per Mcf $ 1.89 $ (0.73)
Price percentage change 63% (20)%
Production change (MMcf) 11,499 (1,327)
Production percentage change 30% (3)%
Oil
- ---
Price change per Bbl $ 1.62 $ 2.05
Price percentage change 6% 9%
Production change (MBbl) 1,726 381
Production percentage change 61% 16%
Our product mix as a percentage of total oil and gas revenue and production:
Revenue 2003 2002 2001
- ------- -------------- -------------- -------------
Natural Gas 66% 62% 72%
Oil 34% 38% 28%
Production
Natural Gas 65% 69% 73%
Oil 35% 31% 27%
Information regarding the effects of oil and gas hedging activity:
Natural Gas Hedging 2003 2002 2001
- ------------------- ------------------ ------------------ ------------------
Percentage of gas production hedged 40% 45% 41%
Natural gas MMBtu hedged 21.7 million 18.9 million 17.6 million
Decrease in gas revenue ($11.4 million) ($4.1 million) ($19.2 million)
Average realized gas price per Mcf before hedging $ 5.12 $ 3.10 $ 4.22
Oil Hedging 2003 2002 2001
- ----------- ------------------ ------------------ ------------------
Percentage of oil production hedged 54% 54% 35%
Oil volumes hedged (MBbl) 2,474 1,518 841
Increase (decrease) in oil revenue ($11.1 million) $1.9 million ($1.9 million)
Average realized gas price per Bbl before hedging $ 29.40 $ 24.69 $ 24.08
Information regarding the components of exploration expense:
Summary of Exploration Expense (In millions) 2003 2002 2001
- --------------------------------------------- ------------------ ------------------ ------------------
Geological and geophysical expenses $ 5.1 $ 3.5 $ 4.6
Exploratory dry holes 8.5 7.7 9.0
Overhead and other expenses 13.1 8.3 5.9
------------------ ------------------ ------------------
$ 26.7 $ 19.5 $ 19.5
================== ================== ==================
52
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
acquisitions. Wells completed in 2002 and 2003 and properties acquired in 2002
and during 2003 have added revenue of $135.3 million and average net daily
production of 71.0 MMCFE in 2003 compared to 2002.
The hedging activity table reflects increased hedging of oil production
as a result of our Burlington and Flying J acquisitions.
Gain (loss) on sale of proved properties. In 2003 we closed the sale of
certain Texas, Wyoming and other properties and recognized net gains of $8.8
million.
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 additions of higher cost
oil properties in our; Rocky Mountain region through our
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. Exploration expense increased 37 percent in 2003. The most
significant component of our increase to exploration expense was $4.8 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. General and administrative expenses
increased $10.9 million or 76 percent to $25.2 million for 2003, compared with
$14.3 million in 2002. Approximately $5.3 million of the 2003 expense is
non-cash and relates to the mark-to-market effect of our net profits interest
bonus plan. The increase in cost on a per MCFE basis reflects a higher
percentage increase in G&A, primarily due to an increase in our compensation
expense, than the proportionate increase in production of 40 percent for the
period.
An increase in our employee count from 185 to 226 has resulted in a
general increase in G&A of $5.4 million between 2003 and 2002. That increase
plus a $12.4 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
53
offset by an $8.3 million increase in COPAS overhead reimbursement from
operations and G&A we allocated to exploration expense. COPAS overhead
reimbursement from operations has increased by $3.5 million due to an increase
of 413 in the number of 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 have received from the current
price environment for past employee performance and the performance of our
employees during the current year.
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 5.75% 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% 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 Taxes. 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 reflects 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 is $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 results 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. We have increased our budget for drilling expenditures
and revenues are projected for a slight increase in 2004. 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 decrease.
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.
Comparison of Financial Results and Trends between 2002 and 2001
Oil and Gas Production Revenues. Average net daily production increased
to 150.8 MMCFE in 2002 compared to 148.2 MMCFE in 2001. Our November 2001
acquisition from Choctaw II Oil & Gas, Ltd. added $13.7 million of revenue
and average daily production of 11.2 MMCFE in 2002. Wells completed in 2002 and
our acquisitions added average net daily production of 19.7 MMCFE. These
increases offset declines in average daily production from older properties that
include an average 5.8 MMCFE/day decline from the Judge Digby field.
Gain (loss) on sale of proved properties. In December 2002 we closed
the sale of certain Texas properties and recognized a $2.6 million net loss.
Oil and Gas Production Expenses. Total production expenses decreased
$4.2 million, or 8 percent in 2002 to $50.8 million compared with $55.0 million
in 2001. In the second quarter of 2002 our Gulf Coast region experienced a $2.7
54
million decrease in LOE that was comprised of a decrease in workover expense and
an adjustment due to the issuance of a revised Authorization for Expenditure by
the operator at Judge Digby. This revised AFE indicated that workover LOE we
previously expensed under the original AFE should have been capitalized and
recorded as property, plant and equipment. Our total workover expense decreased
$5.1 million from 2001 to 2002. Other decreases in LOE attributable to our
efforts to reduce LOE in total and on a per MCFE basis were offset by $7.3
million of LOE incurred on properties acquired since November 2001, wells
completed in 2002 and the $863,000 increase in transportation costs. The
$991,000 decrease in production taxes reflects the decrease in revenue discussed
above.
Total oil and gas production costs per MCFE decreased 10 percent to
$0.92 for 2002 compared with $1.02 in 2001. This decrease is comprised of the
following:
o A $0.03 decrease in production taxes due to lower realized per MCFE
prices;
o A $0.09 decrease in LOE, net of general inflation increases, due to
our efforts to decrease LOE in total and on a per MCFE basis;
o A $0.10 decrease in LOE attributable to the decrease in total
workover expense in excess of general cost inflation increases;
o A $0.03 increase in LOE and transportation costs attributable to
property acquisitions and 2002 well additions outside of the
Williston Basin; and
o A $0.09 increase in LOE and transportation costs attributable to
increased activity in the higher cost Williston Basin.
General and Administrative. General and administrative expenses
increased $2.5 million or 22 percent to $14.3 million in 2002 compared to $11.8
million in 2001. On a per MCFE basis these costs increased 18 percent to $0.26
in 2002 from $0.22 in 2001. We experienced an increase in non-compensation
general expenses of $1.0 million due primarily to increased personnel and
general cost inflation. This amount plus a $3.7 million increase in compensation
expense associated with increased personnel and our incentive plans were
partially offset by a $2.2 million increase in COPAS overhead reimbursement from
operations and costs allocated to exploration expense.
Interest Expense. Interest expense increased to $3.9 million in 2002.
This amount reflects accrued interest on our convertible notes. The amount we
accrued and paid in 2002 was affected by a fixed-rate to floating-rate interest
rate swap we entered into in March 2002 and closed at a net gain in December
2002. Without this swap, interest expense for the period ending December 31,
2002, would have been $4.6 million.
Income Taxes. Income tax expense totaled $15.0 million in 2002
resulting in an effective tax rate of 35.3 percent compared to $21.8 million in
2001 at an effective tax rate of 35.0 percent. The effective rate change from
2001 reflects increased accrued state income taxes from marginal rate
adjustments offset by adjustments to valuation allowances against state net
operating loss carryovers. We adjusted the valuation allowance after we
considered a number of factors, including our prior utilization of net operating
losses and carryovers, tax planning strategies for utilizing both federal and
state net operating loss and capital loss carryovers and projections of future
taxable income. We also took into account the reversal of prior temporary timing
differences and the effect that recent acquisitions will have on anticipated
expenditures for intangible drilling costs. Based on the weight of positive and
negative evidence regarding the recoverability of our net deferred tax assets,
we concluded that only a partial valuation allowance was required.
55
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
have been 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. Operating results from the acquired properties
have been included in the consolidated statements of operations only from the
date of closing. See Note 3 of Part IV, Item 15 of this report. See the overview
to liquidity and capital resources for a description of the repurchase of these
shares.
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, 2003, we have recorded a $914,000 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 8 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 for 2003 was
24.5 percent and was a negative 10.0 percent for 2002. 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 2003 plan year, a 0.25 percent decrease in the discount rate
combined with a 1.25 percent decrease in the rate of future compensation
increases caused a $43,000 decrease 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 2003 plan year, a 0.25 percent decrease in the discount rate
combined with a 0.25 percent decrease in the rate of future compensation
increases caused a $227,000 increase in the projected benefit obligation for
this plan. This plan's accumulated benefit obligation was $1.2 million at
December 31, 2003, and was $853,000 at December 31, 2002. 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.
56
We refer you to Note 1 of Part IV, Item 15 of this report for a
detailed discussion regarding the adoption of SFAS No. 141 and SFAS No. 142 and
the reporting issue that has arisen regarding these statements and for a
discussion of recently issued accounting standards. We have addressed this issue
in accordance with the best available information at the time of filing this
report.
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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is provided under the captions
"Interest Rate 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
As previously reported in our current reports on Form 8-K filed with
the SEC on May 30, 2002, and June 5, 2002, we dismissed Arthur Andersen LLP as
our independent accountants on May 23, 2002, and we engaged Deloitte & Touche
LLP as our new independent accountants on June 3, 2002. The St. Mary Audit
Committee and Board of Directors approved this change in accountants.
ITEM 9A. CONTROLS AND PROCEDURES
We maintain a system of disclosure controls and procedures that are
designed for the purposes of ensuring 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 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.
57
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 2004 annual meeting of stockholders to be
filed within 120 days from December 31, 2003. 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 2004 annual meeting of stockholders to be filed within 120
days from December 31, 2003.
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 2004 annual meeting of stockholders to be
filed within 120 days from December 31, 2003.
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 2004
annual meeting of stockholders to be filed within 120 days from December 31,
2003.
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 2004 annual
meeting of stockholders to be filed within 120 days from December 31, 2003.
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 2004 annual meeting of stockholders to
be filed within 120 days from December 31, 2003.
58
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
Reports of Independent Auditors.....................................F-1
Reports of Independent Public Accountants...........................F-2
Consolidated Balance Sheets.........................................F-3
Consolidated Statements of Operations...............................F-4
Consolidated Statements of Stockholders' Equity and
Comprehensive Income.............................................F-5
Consolidated Statements of Cash Flows...............................F-6
Notes to Consolidated Financial Statements..........................F-8
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) Reports on Form 8-K.
St. Mary Land & Exploration Company filed the following current
reports on Form 8-K during the quarter ended December 31, 2003:
On October 8, 2003, we filed a current report on Form 8-K reporting
under Item 12 that we issued a press release providing an update on our
operations for the third quarter 2003.
On October 23, 2003, we filed a current report on Form 8-K reporting
under Item 9 that we issued a press release announcing a regular semi-annual
cash dividend of five cents per share to be paid on November 17, 2003.
On November 6, 2003, we filed a current report on Form 8-K reporting
under Item 12 that we issued a press release announcing the results of
operations for the quarterly period ended September 30, 2003.
On November 6, 2003, we filed a current report on Form 8-K/A amending
the financial highlights attachment filed with the Form 8-K on November 6, 2003.
On December 5, 2003, we filed a current report on Form 8-K reporting
under Item 5 that we will proceed with the development of coalbed methane
reserves in the Hanging Woman Basin and that we sold certain oil and gas
properties for approximately $22 million with an aggregate gain of approximately
$7 million.
59
(c) 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)
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)
60
Exhibit
Number Description
------ -----------
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)
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)
61
Exhibit
Number Description
------ -----------
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)
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)
62
Exhibit
Number Description
------ -----------
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)
63
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
10.42* Net Profits Interest Bonus Plan, As Amended on February 3, 2004
12.1* Computation of Ratios of Earnings to Fixed Charges
14.1* Code of Business Conduct and Ethics
16.1 Letter by Arthur Andersen LLP to the Securities and Exchange
Commission dated May 28, 2002 (filed as Exhibit 16.1 to the
registrant's Current Report on Form 8-K filed on May 30, 2002
and incorporated herein by reference)
21.1* Subsidiaries of Registrant
23.1* Consent of Deloitte & Touche LLP
23.2* Information About Lack of Consent of Arthur Andersen LLP
23.3* Consent of Ryder Scott Company, L.P.
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.
(d) Financial Statement Schedules. See Item 15(a) above.
64
INDEPENDENT AUDITORS' REPORT
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 as of December 31, 2003 and 2002, and
the related consolidated statements of operations, stockholders' equity and
comprehensive income, and cash flows for the years then ended. 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. The Company's consolidated financial statements for the year ended
December 31, 2001, were audited by other auditors who have ceased operations.
Those auditors expressed an unqualified opinion on those consolidated financial
statements in their report dated February 18, 2002, which report included an
explanatory paragraph for the change in method of accounting for derivative
instruments and hedging activities on January 1, 2001.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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 the Company as of December 31, 2003
and 2002, and the results of its operations and its cash flows for the years
then ended 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 Standards No. 143 "Accounting for
Asset Retirement Obligations."
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 26, 2004
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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 (a Delaware corporation) and subsidiaries as of
December 31, 2001 and 2000, 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, 2001. 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 auditing standards generally accepted
in the 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, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of St. Mary Land &
Exploration Company and subsidiaries as of December 31, 2001 and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
As explained in Notes 1 and 10 to the consolidated financial statements, the
Company changed its method of accounting for derivative instruments and hedging
activities on January 1, 2001.
/s/ ARTHUR ANDERSEN LLP
Denver, Colorado,
February 18, 2002.
NOTE: This Report of Independent Public Accountants dated February 18, 2002 by
Arthur Andersen LLP is a copy of the report previously issued by Arthur Andersen
LLP and included with Arthur Andersen LLP's consent in the Annual Report on Form
10-K for the year ended December 31, 2001 filed with the SEC on March 19, 2002
and the Annual Report on Form 10-K/A for the year ended December 31, 2001 filed
with the SEC on March 25, 2002. Such report has not been reissued by Arthur
Andersen LLP for inclusion with this Annual Report on Form 10-K for the year
ended December 31, 2002. After reasonable efforts, St. Mary Land &
Exploration Company has been unable to obtain a reissued report of Arthur
Andersen LLP for inclusion with this Form 10-K, and in reliance on Rule 2-02(e)
of Regulation S-X promulgated by the SEC is including a copy of the previously
issued report with this Form 10-K.
F-2
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
December 31,
-------------------------------
ASSETS 2003 2002
------------- -------------
Current assets:
Cash and cash equivalents $ 14,827 $ 11,154
Short-term investments 12,509 1,933
Accounts receivable 65,084 35,399
Prepaid expenses and other 6,020 6,510
Deferred income taxes 8,872 3,520
Other 611 1,031
------------- -------------
Total current assets 107,923 59,547
------------- -------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 858,246 683,752
Less - accumulated depletion, depreciation and amortization (312,719) (263,436)
Unproved oil and gas properties, net of impairment allowance
of $10,776 in 2003 and $8,865 in 2002 61,484 47,984
Other property and equipment, net of accumulated depreciation
of $4,656 in 2003 and $3,586 in 2002 4,276 3,639
------------- -------------
611,287 471,939
------------- -------------
Noncurrent assets:
Restricted cash subject to Section 1031 Exchange 10,353 -
Other noncurrent assets 6,291 5,653
------------- -------------
Total noncurrent assets 16,644 5,653
------------- -------------
Total Assets $ 735,854 $ 537,139
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 81,217 $ 48,790
Accrued derivative liability 23,605 8,707
------------- -------------
Total current liabilities 104,822 57,497
------------- -------------
Noncurrent liabilities:
Long-term credit facility 11,000 14,000
Convertible notes 99,696 99,601
Deferred income taxes 90,947 60,156
Asset retirement obligation 25,485 -
Other noncurrent liabilities and minority interest 13,251 6,372
------------- -------------
Total noncurrent liabilities 240,379 180,129
------------- -------------
Commitments and contingencies (Note 6)
Temporary equity (Note 3):
Common stock subject to put and call options, $0.01 par value; issued
and outstanding - 3,380,818 shares in 2003 and -0- shares in 2002 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 - 29,245,123 shares in 2003 and 28,983,110 shares in 2002;
outstanding, net of treasury shares - 28,242,423 shares in 2003
and 27,973,210 shares in 2002 292 290
Additional paid-in capital 146,362 140,688
Treasury stock - at cost: 1,002,700 shares in 2003 and 1,009,900 shares in 2002 (16,057) (16,210)
Retained earnings 274,937 182,512
Accumulated other comprehensive loss (14,881) (7,767)
------------- -------------
Total stockholders' equity 390,653 299,513
------------- -------------
Total Liabilities and Stockholders' Equity $ 735,854 $ 537,139
============= =============
The accompanying notes are an integral part
of these concolidated financial statements.
F-3
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Years Ended December 31,
-------------------------------------------------
2003 2002 2001
-------------- -------------- --------------
Operating revenues:
Oil and gas production $ 365,114 $ 185,670 $ 203,973
Gain (loss) on sale of proved properties 7,278 (2,633) 367
Marketed gas revenue 13,438 8,399 420
Other oil and gas revenue 3,538 682 2,166
Derivative gain - 3,188 -
Other revenues 4,566 1,088 543
-------------- -------------- --------------
Total operating revenues 393,934 196,394 207,469
-------------- -------------- --------------
Operating expenses:
Oil and gas production 88,509 50,839 55,000
Depletion, depreciation, amortization
and abandonment liability accretion 81,960 54,432 51,346
Exploration 26,653 19,501 19,518
Impairment of proved properties 185 - 820
Abandonment and impairment of unproved properties 3,796 2,446 3,865
General and administrative 25,179 14,299 11,762
Derivative loss 310 - 1,573
Marketed gas system operating expense 12,229 7,982 420
Minority interest and other 1,802 1,206 1,253
-------------- -------------- --------------
Total operating expenses 240,623 150,705 145,557
-------------- -------------- --------------
Income from operations 153,311 45,689 61,912
Interest income 717 758 466
Interest expense (7,958) (3,868) (90)
Income before income taxes and cumulative
effect of change in accounting principle 146,070 42,579 62,288
Income tax expense (55,930) (15,019) (21,829)
-------------- -------------- --------------
Income before cumulative effect of change in accounting principle 90,140 27,560 40,459
Cumulative effect of change in accounting principal, net of income tax 5,435 - -
-------------- -------------- --------------
Net income $ 95,575 $ 27,560 $ 40,459
============== ============== ==============
Basic weighted average common shares outstanding 31,233 27,856 27,973
Diluted weighted average common shares outstanding 35,534 28,391 28,555
Basic earnings per common share:
- --------------------------------
Income before cumulative effect
of change in accounting principle $ 2.89 $ 0.99 $ 1.45
Cumulative effect of change in accounting principle 0.17 - -
-------------- -------------- --------------
Basic net income per common share $ 3.06 $ 0.99 $ 1.45
============== ============== ==============
Diluted earnings per common share:
- ----------------------------------
Income before cumulative effect
of change in accounting principle $ 2.65 $ 0.97 $ 1.42
Cumulative effect of change in accounting principle 0.15 - -
-------------- -------------- --------------
Diluted net income per common share $ 2.80 $ 0.97 $ 1.42
============== ============== ==============
Cash dividends declared and paid per common share $ 0.10 $ 0.10 $ 0.10
============== ============== ==============
The accompanying notes are an integral part
of these concolidated financial statements.
F-4
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(In thousands, except share amounts)
Accumulated
Additional Other Total
Common Stock Paid-in Treasury Stock Retained Comprehensive Stockholders'
--------------------- --------------------
Shares Amount Capital Shares Amount Earnings Income (Loss) Equity
------------ --------------------- ---------- --------- ----------- -------------------------
Balances, December 31, 2000 28,553,826 $ 286 $ 132,973 (395,600) $ (3,339) $ 120,075 $ 141 $ 250,136
Comprehensive income:
Net income - - - - - 40,459 - 40,459
Unrealized net loss on marketable
equity securities
available-for-sale - - - - - - (132) (132)
Adoption of SFAS No. 133 (28,587) (28,587)
Change in derivative instrument
fair value - - - - - - 21,102 21,102
Reclass to earnings - - - - - - 14,392 14,392
------------
Total comprehensive income 47,234
------------
Cash dividends, $ 0.10 per share - - - - - (2,795) - (2,795)
Treasury stock purchases - - - (614,300) (12,871) - - (12,871)
Issuance for Employee Stock Purchase
Plan 29,772 - 575 - - - - 575
Sale of common stock, including income
tax benefit of stock option
exercises 187,810 2 3,598 - - - - 3,600
Directors' stock compensation 8,400 - 238 - - - - 238
------------ --------------------- ---------- --------- ----------- ------------ ------------
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)
Reclass to earnings - - - - - - 1,447 1,447
Minimum pension liability adjustment - - - - - - (761) (761)
------------
Total comprehensive income 12,877
------------
Cash dividends, $ 0.10 per share - - - - - (2,787) - (2,787)
Issuance for 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 vesing of retiring
director option - - 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)
Reclass to earnings - - - - - - 13,846 13,846
Minimum pension liability adjustment - - - - - - 197 197
------------
Total comprehensive income 88,461
------------
Cash dividends, $ 0.10 per share - - - - - (3,150) - (3,150)
Issuance for Employee Stock Purchase
Plan 16,994 - 375 - - - - 375
Value of option rights granted to
Flying J - - 995 - - - - 995
Sale of common st ck, 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
============ ===================== ========== ========= =========== ============ ============
The accompanying notes are an integral part
of these concolidated financial statements.
F-5
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
--------------------------------------------
2003 2002 2001
--------- --------- ---------
Reconciliation of net income to net cash provided
by operating activities:
Net income $ 95,575 $ 27,560 $ 40,459
Adjustments to reconcile net income to net
cash provided by operating activities:
(Gain) loss on sale of proved properties (7,278) 2,633 (367)
Depletion, depreciation, amortization and abandonment liability accretion 81,960 54,432 51,346
Impairment of proved properties 185 - 820
Abandonment and impairment of unproved properties 3,796 2,446 3,865
Unrealized derivative loss 310 373 1,573
Mark to market of long-term net profit plans 5,317 846 -
Deferred income taxes 21,687 14,633 23,726
Exploratory dry hole expense 8,482 7,677 9,028
Minority interest and other 2,088 (1,642) (1,327)
Cumulative effect of change in accounting principle (5,435) - -
--------- --------- ---------
206,687 108,958 129,123
Changes in current assets and liabilities:
Accounts receivable (29,685) 11,085 (629)
Prepaid expenses and other 490 (4,173) (664)
Income taxes 6,785 10,030 (11,061)
Accounts payable and accrued expenses 19,666 15,992 10,752
Current deferred income taxes 376 (183) (29)
--------- --------- ---------
Net cash provided by operating activities 204,319 141,709 127,492
--------- --------- ---------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 23,497 1,624 4,771
Capital expenditures (123,823) (97,257) (131,680)
Acquisition of oil and gas properties (76,413) (87,466) (39,124)
Deposits to short-term investments available-for-sale (12,529) (13,523) -
Receipts from short-term investments available-for-sale 2,450 12,538 -
Receipts from restricted cash 11,500 - -
Deposits to restricted cash (21,853) - -
Other 232 3,153 6,958
--------- --------- ---------
Net cash used in investing activities (196,939) (180,931) (159,075)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from credit facility 140,933 37,400 147,050
Repayment of credit facility (145,020) (87,400) (105,050)
Proceeds from convertible debt - 96,657 -
Proceeds from sale of common stock 3,530 2,390 2,746
Repurchase of common stock - - (12,871)
Dividends paid (3,150) (2,787) (2,795)
--------- --------- ---------
Net cash provided by (used in) financing activities (3,707) 46,260 29,080
Net change in cash and cash equivalents 3,673 7,038 (2,503)
Cash and cash equivalents at beginning of period 11,154 4,116 6,619
--------- --------- ---------
Cash and cash equivalents at end of period $ 14,827 $ 11,154 $ 4,116
========= ========= =========
The accompanying notes are an integral part
of these concolidated financial statements.
F-6
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
Supplemental schedule of additional cash flow information and noncash
activities:
For the Years Ended December 31,
----------------------------------------
2003 2002 2001
---------- ------------ ----------
(in thousands)
Cash paid for interest, including amounts capitalized $ 7,555 $ 2,498 $ 764
Cash paid (refunded) for income taxes 28,858 (550) 11,205
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.
In January 2001 the Company issued 8,400 shares of common stock to its
directors and recorded compensation expense of $237,852.
The accompanying notes are an integral part
of these concolidated financial statements.
F-7
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2003
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, 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. All significant intercompany
accounts and transactions have been eliminated.
Cash and Cash Equivalents
The Company considers all liquid investments purchased with an initial
maturity of three months or less to be cash equivalents. The carrying value of
cash and cash equivalents approximates fair value due to the short-term nature
of these instruments.
Short-term Investments
The Company's short-term investments consist primarily of equity
securities and investment-grade marketable debt, which are classified as
available-for-sale or held-to-maturity. Securities that have been categorized as
available-for-sale are stated at fair value based on quoted market prices. Debt
securities that are categorized as held-to-maturity are carried at amortized
cost when the Company has the ability and intent to hold the securities until
maturity.
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 within many companies, collectability is dependent
upon the general economic conditions of the industry. The receivables are not
collateralized. However, to date the Company has had minimal bad debts.
The Company has accounts with separate banks in Denver, Colorado;
Shreveport, Louisiana; Tulsa, Oklahoma; Lafayette, Louisiana; and Billings,
Montana. At December 31, 2003, 2002 and 2001, the Company had $23.5 million,
$4.9 million and $6.6 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
sheet as of December 31, 2003, 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
F-8
included in cash flows from investing activities within the consolidated
statements of cash flows. The costs of development wells are capitalized whether
productive or nonproductive.
Geological and geophysical costs and the costs of carrying and
retaining unproved properties are expensed as incurred. An impairment allowance
is provided on a property-by-property basis when the Company determines that the
unproved property will not be developed. 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. 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).
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 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
15% discount rate and escalated prices. When the net capitalized costs exceed
the undiscounted future net revenue of a property, the cost of the property is
written down to fair value, which is determined using discounted future net
revenues. During 2003, 2002 and 2001 the Company recorded impairment charges for
proved properties of $185,000, $-0- and $820,000, respectively.
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill
and Other Intangible Assets", to companies in the extractive industries,
including oil and gas companies. The issue is whether the Financial Accounting
Standards Board ("FASB") intended to require companies to classify the costs of
mineral rights held under lease or other contractual arrangements associated
with extracting oil and gas as intangible assets in the balance sheet, apart
from other capitalized oil and gas property costs, and provide specific footnote
disclosures. Historically, St. Mary has included the costs of such mineral
rights associated with extracting oil and gas as a component of oil and gas
properties. If it is ultimately determined by the FASB that SFAS No. 142 was
intended to require oil and gas companies to classify costs of mineral rights
held under lease or other contractual arrangements associated with extracting
oil and gas as a separate intangible assets line item on the balance sheet, the
balance sheet would display the following items based on the unaudited pro forma
presentation:
Unaudited Pro Forma Presentation December 31,
---------------------------------------------
2003 2002
------------- --------------
(In thousands)
Total current assets $ 107,923 $ 59,547
Property and equipment
Proved oil and gas properties 514,919 389,777
Less-accumulated depletion, depreciation
and amortization (198,717) (174,691)
Unproved oil and gas properties, net of
Impairment allowance 24,691 18,998
Other property and equipment, net of
accumulated depreciation 4,276 3,639
------------- --------------
345,169 237,723
Restricted cash subject to Section 1031 Exchange 10,353 -
Intangible leasehold, net 266,117 234,216
Other noncurrent assets 6,292 5,653
------------- --------------
Total Assets $ 735,854 $ 537,139
============= ==============
F-9
St. Mary's cash flows and results of operations would not be affected
by the classification of leasehold costs as intangible since these items would
continue to be depleted and assessed for impairment on the same basis as
currently required by SFAS No. 19, "Financial Accounting and Reporting by Oil
and Gas Producing Companies." Further, St. Mary does not believe the
classification of the costs of mineral rights associated with extracting oil and
gas as intangible assets would have any impact on compliance with covenants
under its debt agreements.
Impairment of Nonproducing Properties
An impairment allowance is provided on unproved property when the
Company determines that the property will not be developed.
Sales of Producing and Nonproducing 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 unit-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. Gains and losses on
dispositions of other property and equipment are included in the results of
operations.
Restricted Cash
Proceeds from certain sales of oil and gas producing properties are
held in escrow and restricted for future acquisitions under a tax-free exchange
agreement. These funds are invested in money market funds consisting of
corporate commercial paper, repurchase agreements and U.S. Treasury obligations
and are carried at cost, which approximates market.
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 $1.2 million at December 31, 2003, and $898,000 at
December 31, 2002, 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 $500,000 at December
31, 2003, and $531,000 at December 31, 2002, are included in other noncurrent
liabilities in the accompanying consolidated balance sheets. The Company's
remaining overproduced and underproduced gas balancing positions are considered
in the Company's proved oil and gas reserves (see Note 11 - Disclosures about
Oil and Gas Producing Activities).
Derivative Financial Instruments
The Company seeks to protect its rate of return on acquisitions of
producing properties, drilling prospects and other production by hedging cash
flows when the economic criteria from its evaluation and pricing model indicate
it would be appropriate. The Company intends for these derivative instruments
used for this purpose to be designated as and qualify as cash flow hedging
F-10
instruments under SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," and related pronouncements. Management reviews these
hedging parameters on a quarterly basis. The Company generally limits its
aggregate hedge position to no more than 50% 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 revolving credit facility's recorded value 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 5 - Long-Term Debt
and Revolving Credit Facility. The Company's 5.75% Senior Convertible Notes Due
2022 are recorded at cost, and the fair value is disclosed in Note 5. 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.
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.
Earnings Per Share
Basic net income per common share of stock is calculated by dividing
net income by the weighted average number 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 (see Note 3 - Acquisitions and
Divestitures). These shares are considered outstanding for purposes of
calculating basic and diluted net income per common share and are weighted
accordingly in the calculation of common shares outstanding. However, the shares
are included in the temporary equity section of the accompanying consolidated
balance sheets as of December 31, 2003. Following is a reconciliation of total
shares outstanding as of December 31, 2003.
Common shares outstanding in Stockholders'
equity, net of treasury shares 28,242,423
Restricted common shares outstanding in Temporary equity 3,380,818
-------------
Total common shares outstanding 31,623,241
=============
Subsequent to December 31, 2003, St. Mary repurchased and canceled the
3,380,818 shares described above (see Note 13 - Subsequent Events).
F-11
The following table sets forth the calculation of basic and diluted
earnings per share:
Years Ended December31,
------------------------------------------------
2003 2002 2001
-------------- ------------- --------------
(In thousands, except per share amounts)
Income before cumulative effect of change in accounting
principle $ 90,140 $ 27,560 $ 40,459
Cumulative effect of change in accounting principle, net
of income tax 5,435 - -
-------------- ------------- --------------
Net income 95,575 27,560 40,459
-------------- ------------- --------------
Adjustments to net income for dilution:
Add: interest expense avoided if Convertible Notes
converted 6,337 - -
Less: charitable contributions of 1% of net income (63) - -
Less: tax effect of dilution items (2,403) - -
-------------- ------------- --------------
Net income adjusted for the effect of dilution $ 99,446 $ 27,560 $ 40,459
============== ============= ==============
Basic weighted average common shares outstanding
in period 31,233 27,856 27,973
Add: dilutive effects of stock option 455 535 582
Add: dilutive effect of Convertible Notes using if-
converted method 3,846 - -
-------------- ------------- --------------
Diluted weighted average common shares outstanding
in period 35,534 28,391 28,555
============== ============= ==============
Basic earnings per common share:
Income before cumulative effect of change in
accounting principle $ 2.89 $ 0.99 $ 1.45
Gain from change in accounting principle 0.17 - -
-------------- ------------- --------------
Total $ 3.06 $ 0.99 $ 1.45
============== ============= ==============
Diluted earnings per common share:
Income before cumulative effect of change in
accounting principle $ 2.65 $ 0.97 $ 1.42
Gain from change in accounting principle 0.15 - -
-------------- ------------- --------------
Total $ 2.80 $ 0.97 $ 1.42
============== ============= ==============
Diluted net income per common share of stock is calculated by dividing
adjusted net income by the weighted average of common shares outstanding and
other dilutive securities. Adjusted net income is used for the if-converted
method discussed below and is derived by adding interest expense paid on the
Company's 5.75% Senior Convertible Notes due 2022 (the "Convertible Notes") back
to net income and then adjusting for nondiscretionary items including the
related income tax effect. Potentially dilutive securities of the Company
consist of in-the-money outstanding options to purchase the Company's common
stock and shares into which the Convertible Notes may be converted.
F-12
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,
----------------------------------------------------
2003 2002 2001
---------------- --------------- ---------------
Dilutive 455,055 534,610 582,313
Anti-dilutive 713,382 1,539,227 625,492
Shares associated with the conversion feature of the Convertible Notes
are accounted for using the if-converted method. Under the if-converted method,
income used to calculate diluted earnings per share is adjusted for the interest
charges and nondiscretionary adjustments based on income that would have changed
had the Convertible Notes been converted at the beginning of the period.
Potentially dilutive shares of 3,846,153 related to the Convertible Notes were
included in the 2003 calculation of diluted net income per share. Potentially
dilutive shares of 3,076,922 related to the Convertible Notes were excluded from
the 2002 calculation of diluted net income per share because they were
anti-dilutive. The Convertible Notes were issued in March 2002.
Stock-Based Compensation
At December 31, 2003, the Company had stock-based employee compensation
plans that include 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
stock-based employee compensation expense is reflected in net income as all
options granted under those plans had an exercise price equal to the market
value of the underlying common stock on the date of grant. The following table
illustrates the 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-13
For The Years Ended December 31,
----------------------------------------------------
2003 2002 2001
--------------- -------------- ---------------
(In thousands, except per share amounts)
Net income -
As reported: $ 95,575 $ 27,560 $ 40,459
Add: Stock-based employee compensation
expense included in reported net income,
net of related tax effects - - -
Less: Stock-based employee compensation
expense determined under fair value
based method for all awards, net of
related income tax effects 5,853 4,666 2,890
--------------- -------------- ---------------
Pro forma $ 89,722 $ 22,894 $ 37,569
=============== ============== ===============
Basic earnings per share -
As reported:
Income before cumulative effect of change in
accounting principle $ 2.89 $ 0.99 $ 1.45
Gain from change in accounting principle 0.17 - -
--------------- -------------- ---------------
Total $ 3.06 $ 0.99 $ 1.45
=============== ============== ===============
Pro forma:
Income before cumulative effect of change in
accounting principle $ 2.70 $ 0.82 $ 1.34
Gain from change in accounting principle 0.17 - -
--------------- -------------- ---------------
Total $ 2.87 $ 0.82 $ 1.34
=============== ============== ===============
Diluted earnings per share -
As reported:
Income before cumulative effect of change in
accounting principle $ 2.65 $ 0.97 $ 1.42
Gain from change in accounting principle 0.15 - -
--------------- -------------- ---------------
Total $ 2.80 $ 0.97 $ 1.42
=============== ============== ===============
Pro forma:
Income before cumulative effect of change in
accounting principle $ 2.48 $ 0.81 $ 1.32
Gain from change in accounting principle 0.15 - -
--------------- -------------- ---------------
Total $ 2.63 $ 0.81 $ 1.32
=============== ============== ===============
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. The Company is considering alternatives
other than stock option grants for the equity portion of its compensation
program.
Comprehensive Income
Comprehensive income consists of net income, and unrealized gains and
losses on marketable equity securities held for sale, the effective component 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-14
The balances of after-tax components comprising other comprehensive
income (loss) are presented in the following table:
As of December 31,
------------------------------------------------
2003 2002 2001
------------- -------------- -------------
(In thousands)
Minimum pension liability $ (564) $ (761) $ -
Unrealized gain (loss) on marketable equity securities - (716) 9
Unrealized hedge loss (14,317) (6,290) 6,907
------------- -------------- -------------
Total accumulated other comprehensive income (loss) $ (14,881) $ (7,767) $ 6,916
============= ============== =============
Major Customers
During 2003 three customers individually accounted for 13.6%, 13.1% and
11.4% of the Company's total oil and gas production revenue. During 2002 no
customer individually accounted for more than 10% of the Company's total oil and
gas production revenue. During 2001 two customers individually accounted for
12.0% and 11.3% of the Company's total oil and gas production revenue.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration,
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.
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.
Recently Issued Accounting Standards
In May 2003 FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity." This Statement
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity and
requires that such financial instruments be classified as a liability (or as an
asset in certain circumstances). SFAS No. 150 is effective for all freestanding
instruments entered into or modified after May 31, 2003. Otherwise, it became
effective for us as of July 1, 2003. The Company has no financial instruments
that fall within the scope of this statement.
F-15
2. Accounts Receivable and Accounts Payable
Accounts receivable are composed of the following:
December 31,
-------------------------------------------
2003 2002
------------------ -----------------
(In thousands)
Accrued oil and gas sales $ 48,925 $ 25,962
Due from joint interest owners 12,554 8,920
Other 3,605 517
------------------ -----------------
Total accounts receivable $ 65,084 $ 35,399
================== =================
Accounts payable and accrued expenses are composed of the following:
December 31,
-------------------------------------------
2003 2002
------------------ -----------------
(In thousands)
Accrued drilling costs $ 22,201 $ 11,188
Revenue payable 16,215 7,187
Accrued lease operating expense 12,195 6,409
Accrued cash bonus and net profit payments 8,026 3,522
Trade payables 6,247 6,369
Other 16,333 14,115
------------------ -----------------
Total account payable and accrued expenses $ 81,217 $ 48,790
================== =================
3. Acquisitions and Divestitures
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% 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.
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 $72.4 million. The
allocation of the purchase price for the net assets acquired was $72.3 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.
F-16
The shares of common stock that were issued in this transaction were
recorded as temporary equity since they are subject to the put option whereby
the Company may be required to repurchase these shares. The shares of common
stock are considered outstanding for basic and diluted earnings per share
calculations. The loan arising from this transaction is considered a
contra-temporary equity item on the consolidated balance sheets, as opposed to
an asset, since the loan is non-recourse to Flying J except with respect to
interest accrued after the first thirty months and is secured by the restricted
common stock issued as part of this transaction. Interest has not accrued for
financial reporting purposes because of the non-recourse nature of the note.
Subsequent to year end, the Company entered into a separately
negotiated transaction with Flying J to repurchase the 3,380,818 restricted
shares issued in the acquisition. See Note 13 - Subsequent Events for a more
detailed discussion of this transaction.
Burlington Resources Acquisition
On December 3, 2002, the Company completed the acquisition of oil and
gas properties located in Montana, North Dakota and Wyoming from Burlington
Resources Oil & Gas Company LP. The Company paid $69.2 million in cash after
normal price adjustments. The Company utilized a portion of its existing credit
facility to fund the acquisition, and the transaction was accounted for as a
purchase.
Sales of Properties
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. For property sales that occurred in the fourth quarter of 2003, the final
proceeds and gain amounts are subject to the resolution of final post-closing
adjustments and settlements. These sold properties were neither individually nor
collectively material with respect to their future production, reserves or
impact on an individual consolidated financial statement line item.
Additionally, the production, reserves, revenues and operating costs associated
with these sales in prior periods were immaterial individually and in total.
4. Income Taxes
The provision for income taxes consists of the following:
For the Years Ended December 31,
-----------------------------------------
2003 2002 2001
------------- ------------- -------------
(In thousands)
Current Taxes:
Federal $ 29,582 $ 719 $ 1,114
State 2,656 569 620
Deferred taxes 23,692 13,731 20,095
------------- ------------- -------------
Total income tax expense $ 55,930 $ 15,019 $ 21,829
============= ============= =============
The above taxes on income before income taxes and cumulative effect of
change in accounting principle are net of alternative fuels credits (Internal
Revenue Code Section 29) of $-0- in 2003, $167,000 in 2002 and $185,000 in 2001.
Current federal tax does not reflect the tax benefit for deductions from stock
option exercises of $1.2 million in 2003, $719,000 in 2002 and $930,000 in 2001
because the benefit is included in additional paid-in capital in the
consolidated balance sheets.
F-17
The components of the net deferred tax liability are as follows:
December 31,
-------------------------------------
2003 2002
------------------- -----------------
(In thousands)
Deferred Tax Liabilities
Oil and gas properties $ 100,103 $ 71,448
Derivative instruments and other 41 62
------------------- -----------------
Total deferred tax liabilities 100,144 71,510
------------------- -----------------
Deferred Tax Assets
Amounts included in accumulated other comprehensive income 9,222 4,181
State tax net operating loss carryforward 2,094 4,042
Federal net operating loss carryforward 2,900 3,142
Deferred capital loss 1,840 1,703
Employee benefits and other 1,853 1,325
State and federal income tax benefit 1,002 775
Charitable contributions carryforward - 218
Alternative minimum tax credit carryforward - 215
------------------- -----------------
Total deferred tax assets 18,911 15,601
Valuation allowance (842) (727)
------------------- -----------------
Net deferred tax assets 18,069 14,874
------------------- -----------------
Total net deferred tax liabilities 82,075 56,636
Current deferred income tax assets 8,872 3,520
------------------- -----------------
Non-current net deferred tax liabilities $ 90,947 $ 60,156
=================== =================
Current federal refundable income tax $ 454 $ 890
=================== =================
Current state refundable income tax $ - $ 141
=================== =================
Current state income tax payable $ 1,334 $ -
=================== =================
At December 31, 2003, the Company had state net operating loss
carryforwards of approximately $28.5 million and state tax credits of $97,000,
which expire between 2004 and 2022. The Company's valuation allowance relates to
those state net operating loss carryforwards that the Company anticipates will
expire before they can be utilized. The net change in valuation allowance in
2003 results from an evaluation of state net operating loss carryforwards that
led to a conclusion by the Company that more of the carryforwards will be offset
by reversing state temporary differences, projections of future taxable income
and individual state tax planning strategies before they expire than was
anticipated in prior years.
F-18
Federal income tax expense differs from the amount that would be
provided by applying the statutory U.S. Federal income tax rate to income before
income taxes for the following reasons:
For the Years Ended December 31,
-------------------------------------------------
2003 2002 2001
--------------- ---------------- ----------------
(In thousands)
Federal statutory taxes $ 49,668 $ 14,477 $ 20,420
Increase (reduction) in taxes resulting from:
State taxes (net of Federal benefit) 5,812 2,092 2,017
Statutory depletion (224) (218) (238)
Alternative fuel credits (Section 29) - (167) (185)
Change in valuation allowance 115 (1,202) 34
Other 559 37 (219)
--------------- ---------------- ----------------
Income tax expense $ 55,930 $ 15,019 $ 21,829
=============== ================ ================
5. Long-term Debt and Revolving Credit Facility
Revolving Credit Facility
In January 2003 the Company replaced its revolving credit facility with
a new long-term revolving credit agreement with a group of banks. The new credit
agreement 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
in favor of the lenders of collateral that includes certain oil and gas
properties and the common stock of the material subsidiaries of the Company. A
borrowing base of $275.0 million was determined by the bank group at the end of
October 2003 under a normal semi-annual determination. The borrowing base
determination process considers the value of St. Mary's oil and gas properties
and other assets, as determined by the bank syndicate. We have elected an
aggregate commitment amount of $150.0 million. The Company must comply with
certain financial and non-financial covenants. Interest and commitment fees are
accrued based on the borrowing base utilization percentage table below.
LIBOR-based borrowings accrue interest at LIBOR plus the applicable margin from
the utilization table, and Alternative Base Rate ("ABR") 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.
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, 2003, the Company's borrowing base utilization
percentage as defined under the credit agreement was 7.3%. The Company had $11.0
million in ABR borrowings outstanding under its revolving credit agreement as of
December 31, 2003. As of February 20, 2004, the Company has repaid the ABR
borrowings and has an outstanding balance of $10.0 million under its LIBOR
alternative.
5.75% Senior Convertible Notes Due 2022
As of December 31, 2003, the Company also had $100.0 million in
outstanding borrowings under the 5.75% Senior Convertible Notes Due 2002 (the
"Convertible Notes"). The Convertible Notes provide for the payment of
contingent interest of up to an additional 0.5% 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
F-19
total rate of 6.25% for 2003. 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, 2003, to March
15, 2004.
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% 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% 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% of market price if 33% or less of the repurchase price is
in shares of our common stock; otherwise, the stock will be discounted at 93% 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 $135.3 million as of December 31, 2003, and
approximatly $131.9 million as of December 31, 2002.
On October 3, 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% 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 six-month LIBOR rate on
December 31, 2003 was 1.16%. The payment dates of the swaps match exactly with
the interest payment dates of the Convertible Notes. The fair value of the swaps
was a liability of $104,000 as of December 31, 2003. Changes in the fair value
of the swaps are recorded to interest expense.
Weighted Average Interest Rate Paid
The weighted average interest rate paid in 2003 was 6.3% including
commitment fees paid on the unused portion of the credit facility aggregate
commitment, amortization of deferred financing costs, and amortization of the
contingent interest embedded derivative. The impact of the commitment fees over
a lower average outstanding balance results in a higher weighted average
interest rate despite lower LIBOR interest rates than in previous periods.
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 $1.3 million, $1.1 million and $839,000 in 2003, 2002 and 2001,
respectively. The Company also leases office equipment under various operating
leases. The Company has a non-cancelable sublease of approximately $1.5 million
through 2012. The annual minimum lease payments for the next five years are
presented below:
Years Ending December 31, (In thousands)
- ---------------------------- -------------------
2004 $ 2,205
2005 1,540
2006 1,452
2007 1,153
2008 1,032
Thereafter 3,158
------------------
Total $ 10,540
==================
F-20
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.
7. Compensation Plans
Cash Bonus Plan
The Company has a cash bonus plan that allows participants to receive
up to 100% 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 $5.4 million for cash bonuses in 2003 that will be paid in 2004, $2.1
million for cash bonuses in 2002 that were paid in 2003, and $170,000 for cash
bonuses in 2001 that were paid in 2002.
Net Profits Interest Bonus Plans
Under the Company's net profits interest bonus plan, oil and gas wells
that are completed or acquired during a year are designated as a 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 recovers net
revenues generated by the pool equal to 100% of its investment in that pool.
Thereafter, an amount generally equal to 10% of net profits generated by the
pool will be allocated among the participants and paid at least annually. The
percentage of net profits from the pool to be split among the participants
increases to 20% after the Company recovers net revenues equal to 200% of its
investment including payments made under the plan.
In calculating the mark-to-market long-term liability, the Company
records changes in the estimated fair value of future payment under the plan as
compensation expense based on a number of assumptions including estimates of oil
and gas production, oil and gas prices, recurring and workover lease operating
expense and present value discount factors. The estimates the Company uses will
change from year-to-year based on new information and any change in estimated
compensation will be recorded in the period that information becomes available.
The Company recorded total estimated compensation expense of $14.2
million in 2003, $5.6 million in 2002 and $5.3 million in 2001 relating to the
net profits interest bonus plan.
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% of their base
salaries. The Company matches each employee's contributions up to 6% 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 $746,000,
$621,000, and $559,000 for the years ended December 31, 2003, 2002 and 2001,
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% of eligible
compensation. The purchase price of the stock is 85% 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. 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. In 2003, 2002 and 2001 shares issued under the ESPP
totaled 16,994, 18,217, and 29,772, respectively. Total proceeds to the Company
F-21
for the issuance of these shares were $375,000, $344,000, and $575,000 in 2003,
2002 and 2001, respectively. The Company recorded compensation expense of $-0-,
$21,000, and $20,000 in 2003, 2002 and 2001, respectively, due to nonqualified
dispositions of stock acquired by employees under the ESPP.
Stock Option Plans
The Company established 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. In 2003
the stockholders approved an increase in the number of shares of the Company's
common stock reserved for issuance under the Option Plans from 4,300,000 shares
to 5,600,000 shares. 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 839,934 shares available
for grant under the Option Plans as of December 31, 2003.
F-22
A summary of activity associated with the Company's Option Plans,
during the last three years follows:
For the Years Ended December 31,
--------------------------------------------------------------------------------
2003 2002 2001
------------------------- ------------------------- ---------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------------- ----------- ------------ ------------ ------------- ------------
Outstanding, start of year 3,061,566 $ 21.34 2,151,675 $ 19.42 1,986,124 $ 18.95
Granted 858,431 26.70 1,109,541 23.55 397,009 18.86
Exercised (245,019) 12.88 (177,085) 11.44 (187,810) 11.57
Forfeited (149,850) 24.00 (22,565) 25.08 (43,648) 26.00
------------- ------------ -------------
Outstanding, end of year 3,525,128 23.12 3,061,566 21.34 2,151,675 19.42
============= ============ =============
Exercisable, end of year 2,441,246 22.36 1,944,382 19.79 1,418,404 17.09
============= ============ =============
Weighted average fair
value of options granted
during the year $ 12.28 $ 10.77 $ 8.36
============= ============ =============
A summary of additional information related to the options outstanding
as of December 31, 2003 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 - $ 9.99 170,439 5.0 years $ 9.25 170,439 $ 9.25
10.00 - 13.33 454,256 5.0 years 12.03 454,256 12.03
13.34 - 16.66 185,759 6.9 years 15.69 147,301 15.63
16.67 - 19.99 87,689 4.0 years 17.50 87,689 17.50
20.00 - 23.33 640,258 8.2 years 22.16 354,111 21.76
23.34 - 26.66 911,292 9.1 years 24.73 452,938 24.57
26.67 - 29.99 463,963 9.8 years 27.83 163,040 27.66
30.00 - 33.31 611,472 6.9 years 33.31 611,472 33.31
--------------- -------------
Total 3,525,128 7.7 years 23.12 2,441,246 22.36
=============== =============
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 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 employee
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 information is
prominently disclosed in Note 1-Summary of Significant Accounting Policies.
F-23
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 in 2003,
2002 and 2001 were estimated using the following weighted-average assumptions:
2003 2002 2001
--------------- -------------- --------------
Risk free interest rate 3.6% 3.8% 4.4%
Dividend yield 0.4% 0.4% 0.5%
Volatility factor of the expected
market price of the Company's
common stock 39.9% 47.5% 49.8%
Expected life of the options (in years) 7.0 5.9 4.8
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. As the Company's employee stock options have characteristics
significantly 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 existing models do not necessarily provide a
reliable single measure of the fair value of St Mary's employee stock options.
In December 2002 the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure: an amendment of FASB
Statement No. 123." This statement provided for transition methods for adopting
the fair value model of accounting for the issuance of stock options. The
statement provides for three alternative adoption methods: (1) the retroactive
method - where all prior periods are restated to reflect the expensing of all
options granted on a retroactive basis, (2) the modified-prospective
method-where a company begins expensing all prior and current option grants in
the current year, and (3) the prospective method-where a company begins
expensing all current period option grants in the current year. St. Mary is
continuing to evaluate these adoption alternatives and ongoing FASB discussions.
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, 2003, no shares
have been issued under this plan.
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-24
Obligations and Funded Status
For the Years Ended December 31,
-------------------------------------------------
2003 2002 2001
------------- -------------- -------------
(In thousands)
Change in benefit obligations:
Projected benefit obligation at beginning of year $ 6,330 $ 5,098 $ 3,054
Service cost 963 442 323
Interest cost 428 358 317
Amendments - (46) -
Actuarial loss 620 503 1,485
Benefits paid (293) (25) (81)
------------- -------------- -------------
Projected benefit obligation at end of year $ 8,048 $ 6,330 $ 5,098
============= ============== =============
Change in plan assets:
Fair value of plan assets at beginning of year $ 2,478 $ 2,042 $ 1,775
Actual return on plan assets 608 (255) (13)
Employer contribution 901 716 361
Benefits paid (293) (25) (81)
------------- -------------- -------------
Fair value of plan assets at end of year $ 3,694 $ 2,478 $ 2,042
============= ============== =============
Funded status: $ (4,354) $ (3,758) $ (3,056)
Unrecognized net actuarial loss 2,874 2,925 2,326
Unrecognized prior service cost (15) (41) (20)
------------- -------------- -------------
Accrued benefit cost $ (1,495) $ (874) $ (750)
============= ============== =============
Amounts recognized in the consolidated balance sheet
As of December 31,
----------------------------------------------
2003 2002
--------------------- ---------------------
(In thousands)
Prepaid benefit cost $ - $ 140
Accrued benefit cost (1,495) (1,015)
Accumulated other comprehensive income (914) (1,188)
--------------------- ---------------------
Net amount recognized $ (2,409) $ (2,063)
===================== =====================
Information for pension plans with an accumulated benefit obligation in
excess of plan assets
As of December 31,
-----------------------------------------
2003 2002
------------------- -----------------
(In thousands)
Projected benefit obligation $ 8,048 $ 6,330
Accumulated benefit obligation $ 6,058 $ 4,436
Fair value of plan assets $ 3,694 $ 2,478
The Company's accumulated benefit obligation for the Qualified Pension
Plan was $4.8 million at December 31, 2003 and $3.6 million at December 31,
2002. The accumulated benefit obligation exceeds plan assets by $1.2 million.
The tax-adjusted liability of $564,000 was recorded in other comprehensive
income at December 31, 2003.
F-25
The Company's accumulated benefit obligation for the Nonqualified
Pension Plan was $1.2 million at December 31, 2003, and $853,000 at December 31,
2002. 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,
---------------------------------------------------------
2003 2002 2001
--------------- ------------------ --------------
(In thousands)
Components of net periodic benefit cost:
Service cost $ 963 $ 442 $ 323
Interest cost 428 358 317
Expected return on plan assets (172) (146) (129)
Amortization of prior service cost (25) (25) (8)
Amortization of net actuarial loss 329 211 188
--------------- ------------------ --------------
Net periodic benefit cost $ 1,523 $ 840 $ 691
=============== ================== ==============
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% 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
For the Years Ended December 31,
----------------------------------------------
2003 2002
--------------------- ---------------------
(In thousands)
Increase (decrease) in minimum liability included
in other comprehensive income, net of taxes $ (197) $ 761
Assumptions
Weighted average assumptions used in the measurement of the Company's
projected benefit obligation and net periodic benefit cost are as follows:
As of December 31,
--------------------------------------
2003 2002
---------------- ----------------
Projected benefit obligation
Discount rate 6.3% 6.5%
Expected return on plan assets 8.0% 8.0%
Rate of compensation increase 3.5% 4.8%
Net periodic benefit cost
Discount rate 6.5% 7.3%
Expected return on plan assets 8.0% 8.0%
Rate of compensation increase 3.8% 4.8%
F-26
Plan Assets
The Company's weighted-average asset allocation for the Qualified Plan
is as follows:
Target As of December 31,
-----------------------------------
Asset Category 2004 2003 2002
- ------------------------- ---------------- ---------------- ---------------
Equity securities 60% 61.4% 51.3%
Debt securities 40% 38.0% 48.7%
Other 0% 0.6% 0.0%
---------------- ---------------
Total 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.
Contributions
The Company contributed $901,000, $716,000 and $361,000 to the pension
plans in the years ended December 31, 2003, 2002 and 2001, respectively. St.
Mary expects to contribute approximately $987,000 to the pension plans in 2004.
Benefit Payments
The Company made actual benefit payments of $293,000, $25,000 and
$81,000 in the years ended December 31, 2003, 2002 and 2001, respectively.
9. Asset Retirement Obligations
Effective 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 costs associated with the abandonment of its oil and
gas properties.
As of January 1, 2003, the Company recognized the future cost to
abandon oil and gas properties over the estimated economic life of the oil and
gas properties in accordance with the provisions of SFAS No. 143. A liability
for the fair value of an asset retirement obligation with 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 & gas property costs and
recognizes accretion expense in connection with the discounted liability over
the remaining life 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 of approximately
7.25%. 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
F-27
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). The Company
depletes the amount added to 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.
As of December 31, 2003, the Company's capitalized proved oil and gas
properties included $41.1 million of estimated salvage value, which is excluded
from the Company's DD&A calculation.
A reconciliation of the Company's liability for the year ended December
31, 2003, is as follows (in thousands).
Year Ended December 31, 2003
-------------------------------------
Beginning asset retirement obligation $ -
Liability from SFAS 143 adoption 21,403
Liabilities incurred 4,395
Liabilities settled (3,169)
Accretion expense 1,719
Revision to estimated cash flows 1,137
-------------------------------------
Ending asset retirement obligation $ 25,485
=====================================
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 and 2001,
respectively. 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 2001
------------------------------- -------------------------------
Asset retirement obligation liability $ 21,829 $ 20,761
Years Ended December 31,
-----------------------------------------------------------------
2002 2001
----------------------------- -------------------------------
Net Income
As reported $ 27,560 $ 40,459
Pro forma $ 26,622 $ 39,563
Basic EPS
As reported $ 0.99 $ 1.45
Pro forma $ 0.96 $ 1.41
Diluted EPS
As reported $ 0.97 $ 1.42
Pro forma $ 0.94 $ 1.39
10.Derivative Financial Instruments
The Company realized a net loss of $22.8 million from its derivative
contracts for the year ended December 31, 2003, a net gain of $878,000 for the
year ended December 31, 2002, and a net loss of $22.7 million for the year ended
December 31, 2001.
F-28
Oil and Gas Commodity Hedges
As of December 31, 2003, the Company has the following commodity swap
contracts in place to hedge cash flow and reduce the impact of oil and gas price
fluctuations:
Gas (per MMBtu) Oil (per Bbl)
---------------------------------------- ---------------------------------------------
Weighted Weighted
Contract Average Average
Month Volumes Contract Price Volumes Contract Price
- -----
----------------- ------------------- ----------------- -----------------------
2004
----------------- ------------------- ----------------- -----------------------
January 1,544,500 $ 4.61 157,500 $ 23.71
February 1,298,300 4.56 153,500 23.71
March 1,293,000 4.57 174,800 24.48
April 738,900 3.72 178,000 24.66
May 731,600 3.72 174,800 24.67
June 725,500 3.73 173,000 24.67
July 722,700 3.73 172,500 24.65
August 716,600 3.74 170,900 24.65
September 712,400 3.74 169,300 24.64
October 710,300 3.74 167,700 24.64
November 620,000 3.83 165,200 24.64
December 617,000 3.83 163,100 24.64
----------------- ------------------- ----------------- -----------------------
Total 2004 10,430,800 4.08 2,020,300 24.49
----------------- ------------------- ----------------- -----------------------
2005
January - - 27,000 29.20
February - - 27,000 29.20
March - - 5,900 29.20
----------------- ------------------- ----------------- -----------------------
Total 2005 - - 59,900 29.20
----------------- ------------------- ----------------- -----------------------
----------------- ------------------- ----------------- -----------------------
All Contracts 10,430,800 $ 4.08 2,080,200 $ 24.63
================= =================== ================= =======================
Oil and gas production operating revenue in the consolidated statements
of operations for the year ended December 31, 2002, includes a non-cash gain of
$1.7 million related to amortization of other comprehensive income from
derivative contracts that lost effectiveness due to counterparty default.
Derivative loss in the consolidated statements of operations for the
year ended December 31, 2003, includes a loss of $246,000 from ineffectiveness
related to these hedge contracts. On December 31, 2003, the estimated fair value
of contracts designated and qualifying as cash flow hedges under SFAS No. 133
was a net liability of $23.3 million. The Company will reclassify this amount to
gains or losses included in oil and gas production operating revenues as the
hedged production quantity is produced. Based on December 31, 2003, prices the
net amount of existing unrealized after-tax loss as of December 31, 2003, to be
reclassified from accumulated other comprehensive income to oil and gas
production operating revenues in the next twelve months would be $14.7 million,
net of deferred income taxes. The Company anticipates that all original
forecasted transactions will occur by the end of the originally specified
periods.
Interest Rate Swaps
In March 2002 the Company entered into a fixed-to-floating interest
rate swap 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, resulting in a net realized
gain of $3.6 million included in derivative gain in the consolidated statements
of operations for the year ended December 31, 2002.
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% and will
pay a variable interest rate of 235 basis points above the six-month LIBOR rate
F-29
as determined on the semi-annual settlement date. The six-month LIBOR rate on
October 3, 2003 was 1.16%. The payment dates of the swaps match with the
interest payment dates of the Convertible Notes.
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 and $75,000 have been
amortized through interest expense for the years ended December 31, 2003 and
2002, respectively. Derivative loss in the consolidated statements of operations
for the year ended December 31, 2003, and derivative gain for the year ended
December 31, 2002, include a $40,000 net gain and a $341,000 net loss,
respectively, from mark-to-market adjustments for this derivative.
Summary
The following table summarizes derivative instrument gain (loss)
activity.
Years Ended December 31,
------------------------------------------------------------
2003 2002 2001
-------------------- ------------------ -------------------
Derivative contract settlements included
in oil and gas production revenues $ (22,439,000) $ (2,235,000) $ (21,102,000)
Ineffective portion of hedges qualifying
for hedge accounting included in
derivative gain(loss) (246,000) (32,000) 45,000
Non-qualified derivative contracts included
in derivative gain (loss) (64,000) 3,220,000 (1,618,000)
Amortization of contingent interest derivative
through interest expense (95,000) (75,000) -
-------------------- ------------------ -------------------
Total $ (22,844,000) $ 878,000 $ (22,675,000)
==================== ================== ===================
See also Derivative Financial Instruments in Note 1 - Summary of
Significant Accounting Policies.
11.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:
For the Years Ended December 31,
-----------------------------------------------------
2003 2002 2001
--------------- --------------- ---------------
(In thousands)
Development costs $ 111,908 $ 74,376 $ 98,617
Exploration 34,631 22,778 24,506
Acquisitions:
Proved 77,398 87,706 41,188
Unproved 7,480 8,128 18,552
--------------- --------------- ---------------
Total before asset retirement obligation $ 231,417 $ 192,988 $ 182,863
=============== =============== ===============
Total including asset retirement obligation $ 236,949 $ 192,988 $ 182,863
=============== =============== ===============
F-30
Oil and Gas Reserve Quantities (Unaudited):
The reserve information as of December 31, 2003, 2002, and 2001 was
prepared by Ryder Scott Company and St. Mary. For all years presented the
reserve information for greater than 80 percent of the PV-10 value was prepared
by Ryder Scott Company and St. Mary prepared the remainder. 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.
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.
Presented below is a summary of the changes in estimated reserves of
the Company:
For the Years Ended December 31,
---------------------------------------------------------------------------------------
2003 2002 2001
--------------------------- -------------------------- --------------------------
Oil or Oil or Oil or
Condensate Gas Condensate Gas Condensate Gas
------------ ----------- ----------- ----------- ------------ ----------
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
Developed and undeveloped:
Beginning of year 36,119 274,172 23,669 241,231 20,950 225,975
Revisions of previous
estimate 2,856 3,904 3,611 4,696 (1,334) (16,421)
Discoveries and extensions 3,681 69,189 1,250 32,813 3,131 59,830
Purchases of minerals in
place 11,952 41,335 10,578 38,118 3,774 13,086
Sales of reserves (2,280) (31,913) (174) (4,522) (418) (1,748)
Production (4,541) (49,663) (2,815) (38,164) (2,434) (39,491)
------------ ----------- ----------- ----------- ------------ ----------
End of year (a) 47,787 307,024 36,119 274,172 23,669 241,231
============ =========== =========== =========== ============ ==========
Proved developed reserves:
Beginning of year 33,580 228,973 20,679 205,637 19,006 192,472
============ =========== =========== =========== ============ ==========
End of year 43,693 264,140 33,580 228,973 20,679 205,637
============ =========== =========== =========== ============ ==========
(a) At December 31, 2003, 2002, and 2001, includes approximately
1,119, 1,151 and 869 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 differential, in effect at year-end to the year-end estimated
quantities of oil and gas to be produced in the future. Each property we operate
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% 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-31
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 worth. 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:
2003 2002 2001
----------- ---------- ----------
Gas (per Mcf) $ 5.70 $ 4.21 $ 2.50
Oil (per Bbl) $ 31.01 $ 29.31 $ 18.11
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:
December 31,
------------------------------------------------------
2003 2002 2001
--------------- ---------------- ----------------
(In thousands)
Future cash inflows $ 3,232,605 $ 2,238,513 $ 1,020,948
Future production and development costs (1,065,161) (783,991) (444,608)
Future income taxes (735,947) (429,618) (140,271)
--------------- ---------------- ----------------
Future net cash flows 1,431,497 1,024,904 436,069
10% annual discount (571,541) (443,042) (154,192)
--------------- ---------------- ----------------
Standardized measure of discounted
future net cash flows $ 859,956 $ 581,862 $ 281,877
=============== ================ ================
The principle sources of change in the standardized measure of
discounted future net cash flows are:
For the Years Ended December 31,
-----------------------------------------------------
2003 2002 2001
----------------- -------------- --------------
(In thousands)
Standard measure, beginning of year $ 581,862 $ 281,877 $ 718,484
Sales of oil and gas produced, net of
production costs and hedging (299,044) (137,066) (170,074)
Net changes in prices and production costs 168,661 298,079 (820,253)
Extensions, discoveries and other, net of
production costs 226,181 92,227 71,265
Purchase of minerals in place 178,264 160,089 29,267
Development costs incurred during the year 22,763 23,802 35,736
Changes in estimated future development costs 11,175 4,265 (8,370)
Revisions of previous quantity estimates 45,551 49,892 (17,593)
Accretion of discount 78,869 34,749 109,912
Sales of reserves in place (47,270) (708) (10,548)
Net change in income taxes (211,381) (177,335) 298,717
Changes in timing and other 104,325 (48,009) 45,334
----------------- -------------- --------------
Standardized measure, end of year $ 859,956 $ 581,862 $ 281,877
================= ============== ==============
F-32
12.Quarterly Financial Information (Unaudited)
The Company's quarterly financial information for fiscal 2003 and 2002
is as follows (in thousands, except per share amounts):
First Second Third Fourth
Quarter Quarter Quarter Quarter
------------- -------------- -------------- -------------
Year Ended December 31, 2003
Total revenue $ 101,204 $ 103,704 $ 90,999 $ 98,027
Less: costs and expenses 54,785 61,695 66,688 57,455
------------- -------------- -------------- -------------
Income from operations $ 46,419 $ 42,009 $ 24,311 $ 40,572
Income before income taxes and cumulative
effect of change in 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 0.17 - - -
------------- -------------- -------------- -------------
Basic net income per common share $ 1.07 $ 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 0.15 - - -
------------- -------------- -------------- -------------
Diluted net income per common share $ 0.96 $ 0.71 $ 0.41 $ 0.72
============= ============== ============== =============
Dividends declared and paid per common
share $ - $ 0.05 $ - $ 0.05
============= ============== ============== =============
Year Ended December 31, 2002
Total revenue $ 42,773 $ 50,028 $ 48,335 $ 55,258
Less: costs and expenses 38,991 33,322 35,634 42,758
------------- -------------- -------------- -------------
Income from operations $ 3,782 $ 16,706 $ 12,701 $ 12,500
Income before income taxes $ 3,440 $ 15,858 $ 11,879 $ 11,402
Net income $ 2,318 $ 10,589 $ 7,674 $ 6,979
Basic earnings per common share:
Income before cumulative effect of
change in accounting principle $ 0.08 $ 0.38 $ 0.28 $ 0.25
Cumulative effect of change in
accounting principle - - - -
------------- -------------- -------------- -------------
Basic net income per common share $ 0.08 $ 0.38 $ 0.28 $ 0.25
============= ============== ============== =============
Diluted earnings per common share:
Income before cumulative effect of
change in accounting principle $ 0.08 $ 0.37 $ 0.27 $ 0.25
Cumulative effect of change in
accounting principle - - - -
------------- -------------- -------------- -------------
Diluted net income per common share $ 0.08 $ 0.37 $ 0.27 $ 0.25
============= ============== ============== =============
Dividends declared and paid per common
share $ - $ 0.05 $ - $ 0.05
============= ============== ============== =============
F-33
13.Subsequent Events
On February 9, 2004, the Company repurchased from Flying J 3,380,818
restricted shares of 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 of $71.6
million. Accrued interest, which has not been 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 bank credit facility.
The following table shows the unaudited pro forma effects on the
summarized consolidated balance sheet if the transactions had occurred on
December 31, 2003. The table assumes that the Company would have borrowed the
necessary cash payment from its existing credit facility.
Unaudited
pro forma
December 31, Pro forma December 31,
2003 adjustments 2003
------------- --------------- --------------
(In thousands)
Condensed Balance Sheet:
Current assets $ 107,923 $ 107,923
Property and equipment, net 611,287 611,287
Other noncurrent assets 16,644 16,644
------------- --------------
Total Assets $ 735,854 $ 735,854
============= ==============
Current liabilities $ 104,822 $ 104,822
Debt, including senior debt 110,696 $ 19,406 130,102
Other noncurrent liabilities,
including minority interest 129,683 129,683
------------- --------------
Total Liabilities 345,201 364,607
Restricted common stock held by Flying J 71,594 (71,594) -
Note receivable from Flying J (71,594) 71,594 -
------------- --------------
Total Temporary Equity - -
------------- --------------
Total Equity 390,653 (19,406) 371,247
------------- --------------
Total Liabilities and Stockholders' Equity $ 735,854 $ 735,854
============= ==============
Selected Share Information:
Total common shares outstanding, net of
treasury shares 31,623 (3,381) 28,242
============= ==============
F-34
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 27, 2004 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, 2003, 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 Chairman of the Board
- ------------------------ of Directors, President February 27, 2004
Mark A. Hellerstein and Chief Executive Officer
/s/ DAVID W. HONEYFIELD Vice President-Finance, February 27, 2004
- ------------------------ Secretary and Treasurer
David W. Honeyfield
/s/ GARRY A. WILKENING Vice President-Administration February 26, 2004
- ------------------------ and Controller
Garry A. Wilkening
Signature Title Date
----- ----
/s/BARBARA M. BAUMANN Director February 26, 2004
- ------------------------
Barbara M. Baumann
/s/ LARRY W. BICKLE Director February 26, 2004
- ------------------------
Larry W. Bickle
/s/ RONALD D. BOONE Director February 26, 2004
- ------------------------
Ronald D. Boone
/s/ THOMAS E. CONGDON Director February 26, 2004
- ------------------------
Thomas E. Congdon
/s/ WILLIAM J. GARDINER Director February 26, 2004
- ------------------------
William J. Gardiner
/s/ AREND J. SANDBULTE Director February 26, 2004
- ------------------------
Arend J. Sandbulte
/s/ JOHN M. SEIDL Director February 26, 2004
- ------------------------
John M. Seidl