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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
(Mark one)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2004
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transaction period from _______ to _________
Commission file number 1-100
CROFF ENTERPRISES, INC.
(Exact name of registrant as specified in its charter)
Utah 87-0233535
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
3773 Cherry Creek Drive North, Suite 1025 80209
Denver, Colorado (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code (303) 383-1555
Securities registered pursuant to Section 12(b) of the Act
Title of each class Name of each exchange on which registered
---------------------------- -----------------------------------------
Common Stock, $.10 par value None
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
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.
[X] Yes [_] 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. [X]
As of February 22, 2005, the aggregate market value of the common voting
stock held by non-affiliates of the Registrant, computed by reference to the
average of the bid and ask price on such date was: $395,667.
As of February 22, 2005, the Registrant had outstanding 568,900 shares of
common stock ($0.10 par value)(excludes 53,243 common shares held as treasury
stock).
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1
TABLE OF CONTENTS
PART I
Page
ITEM 1 BUSINESS..............................................................3
ITEM 2 PROPERTIES............................................................9
ITEM 3 LEGAL PROCEEDINGS....................................................16
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................16
PART II
ITEM 5 MARKET FOR REGISTRANT'S SECURITIES, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES............................16
ITEM 6 SELECTED FINANCIAL DATA..............................................17
ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS..................................18
ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK...........22
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................22
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURES..............................22
ITEM 9A CONTROLS AND PROCEDURES..............................................22
ITEM 9B OTHER INFORMATION....................................................22
PART III
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT...................23
ITEM 11 EXECUTIVE COMPENSATION...............................................25
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.......................26
ITEM 13 CERTAIN RELATIONSHIP AND RELATED TRANSACTIONS........................27
ITEM 14 PRINCIPAL ACCOUNTANT FEES AND SERVICES...............................27
PART IV
ITEM 15 EXHIBITS AND FINANCIAL STATEMENT SCHEDULES...........................28
SIGNATURES...........................................................28
CERTIFICATIONS PURSUANT TO THE SARBANES-OXLEY ACT OF 2002............29
2
CROFF ENTERPRISES, INC.
Annual Report on Form 10-K
December 31, 2004
PART I
ITEM 1. BUSINESS
General
Croff Enterprises, Inc. ("Croff" or the "Company") is an independent energy
Company engaged in the business of oil and natural gas production, primarily
through ownership of perpetual mineral interests and acquisition of producing
oil and natural gas leases. The Company's principal activity is oil and natural
gas production from non-operated properties. Croff's business strategy is
focused on targeting opportunities that are of lower risk with the potential for
stable cash flow and long asset life while seeking to keep operating costs low.
The Company acquires and owns producing and non-producing leases and perpetual
mineral interests in Alabama, Colorado, Michigan, Montana, New Mexico,
North Dakota, Oklahoma, Texas, Utah and Wyoming. Over the past ten years, the
Company's primary source of revenue has been oil and natural gas production from
leases and producing mineral interests. Other companies operate almost all of
the wells from which Croff receives revenues and Croff has no control over the
factors which determine royalty or working interest revenues, such as markets,
prices and rates of production. Croff participates presently as a working
interest owner in approximately 40 wells or units of several wells. Croff holds
small royalty interests in approximately 250 wells.
Summary of Current Events
During 2004, the Company continued to acquire and renew leases, and develop
its drilling package with the goal of attracting development partners
principally for the Company's Yorktown Re-entry Program in DeWitt County, Texas.
The majority of these leases were acquired in 2003. The existing logs appear to
indicate potential productivity in the Edwards limestone and Wilcox natural gas
producing sands in this area. These leases contain eight existing wellbores, of
which two were drilled to the Edwards formation and six were drilled to the
Wilcox formation. The Company re-entered the Helen Gips #1 well in DeWitt
County, Texas, and re-completed the wellbore to the Wilcox formation during
2004. The Helen Gips #1 well currently, has been perforated, fraced, and
completion efforts are still in process.
In November 2004, the Company signed a Prospect Participation
Agreement ("Agreement") with Tempest Energy Resources, LP
("Tempest") to participate in the development of its Yorktown Re-entry
Program located in Dewitt County, Texas. The Company reported this
Agreement on November 19, 2004, on Form 8-K. Significant portions of
this Agreement are summarized below; and the Agreement is set-out in its
entirety as a Form 8-K exhibit to this filing: The Agreement outlines the
Parties intent to potentially develop an area containing approximately 830
acres with 8 re-entry prospects, as well as potential new drilling locations.
The Program is targeting wells which may produce natural gas and condensate
from either the Edwards limestone or Wilcox formations. The Agreement
provides for the parties to work together in this area of mutual interest
("AMI") for a period of up to 5 years. Under the general terms of the
Agreement, Croff will assign 75% interest in the leases, excluding the
Helen Gips #1 wellbore, to Tempest, subject to all royalties. Tempest will
pay Croff $100 per net acre assigned. Tempest will pay Croff a
participation fee of $50,000 per well re-entry that the Parties agree to
develop. On all re-entry wells the Parties agree to develop, Croff will have
a carried working interest of 15% through the drilling and development
stages of the re-entry wells and Croff can participate on a equal cost
sharing basis for an additional 10% working interest. Management
believes that should both Parties agree to develop the remaining seven re-
entry prospects that it would cost Croff approximately $700,000 to elect to
participate on an equal cost sharing basis for an additional 10% working
interest. On all new wells the Parties agree to develop, Croff can elect to
participate on an equal cost sharing basis for up to 25% of the working
interest. Tempest or its designee will assume operating control and shall
become the operator of record for all wells covered by this Agreement.
The Parties agreed to the following with respect to the Helen Gips #1 well,
which Croff previously had begun to develop. Croff agreed to assign 60% of the
working interest in the Helen Gips #1 to Tempest. Tempest agreed to pay a
$100,000 participation fee, to reimburse Croff for certain costs incurred on the
Helen Gips #1 prior to closing of the Agreement, and pay the remaining
completion costs and assume operations.
In 2003, the Company acquired a 10% working interest in one oil and natural
gas well in Hardin County, Texas for $30,000 and a 20% working interest in one
oil well in Cheboygan County, Michigan for $70,000. These acquisitions
increased reserves by 34,036 barrels of oil and 91,496 Mcf of natural gas and
increased the present value (PV10%) at December 31, 2003 by approximately
$450,000.
The estimated value of the Company's discounted future net cash flows
increased 26% to $1,583,000 at December 31, 2004 compared to $1,257,000 as of
December 31, 2003. This increase in the estimated value of the Company's
discounted future net cash flows was primarily the result of higher prices at
December 31, 2004 as compared to December 31, 2003. The December 31, 2004
valuation reflected average wellhead prices of $5.30 per Mcf and $41.17 per
barrel, while the December 31, 2003 valuation reflected average wellhead prices
of $4.03 per Mcf and $30.14 per barrel. At December 31, 2004, approximately
54% of the Company reserves were from oil. The Company's oil reserves as of
December 31, 2004 and 2003 were estimated at 80,468 barrels and 84,110 barrels
respectively. During 2004, the Company had production of 8,011 barrels of oil
compared to production of 7,656 barrels during 2003. The Company's natural gas
reserves as of December 31, 2004 and 2003 were estimated at 407,084 Mcf and
531,377 Mcf, respectively. During 2004, the Company had production of 59,959
Mcf of natural gas compared to production of 52,998 Mcf of natural gas during
2003. The Company's December 31, 2004, reserve study included an overall
downward revision in the Company's estimated natural gas reserves which totaled
66,834 Mcf. The natural gas revisions primarily were in Michigan and Utah.
Revenues and net income for 2004 totaled $576,162 and $142,116,
respectively. Cash provided from operations in 2004 totaled $207,727. The
Company's cash flow from operations is highly dependent on oil and natural gas
prices. Capital expenditures for 2004 totaled $311,054 and were primarily
attributable to the acquisition and potential development of non-producing
mineral leases with re-entry wells in DeWitt County, Texas. The Company had no
short-term or long-term debt outstanding at December 31, 2004.
History
The Company was incorporated in Utah in 1907 as Croff Mining Company. The
Company changed its name to Croff Oil Company in 1952, and in 1996 changed its
name to Croff Enterprises, Inc. The Company, however, continues to operate its
oil and natural gas properties as Croff Oil Company.
In 1996, the Company created a class of preferred B stock to which the
perpetual mineral interests and other oil and natural gas assets were pledged.
Thus, the preferred B stock represents the majority of the Company's oil and
natural gas assets, exclusive of the Company's interests in DeWitt County,
Texas. All other assets are represented by the common stock. Each common
shareholder, as of the February 28, 1996 record date, received an equal number
of preferred B shares, one for each common share, at the time of this
restructuring of the capital of the Company. Subsequent to this date the
Company's securities have been separately traded. The Company's common stock
is listed and occasionally traded on the Over the Counter Bulletin Board
(www.otcbb.com) under the symbol "COFF". The preferred B shares also have an
extremely limited market. The Company maintains a clearinghouse for these shares
at its Web site (www.croff.com).
Material Subsequent Events
As of the date of this filing, the Company is not aware of any material
subsequent events.
Available Information
Our Internet address is www.croff.com. We make available through our
website our annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and amendments to those reports filed or furnished pursuant
to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable
after we electronically file such material with, or furnish it to, the
Securities and Exchange Commission.
Major Customers
Customers which accounted for over 10% of oil and natural gas revenues
were as follows for the years ended December 31, 2002, 2003 and 2004:
2002 2003 2004
------ ------ ------
Burlington Resources Oil and Gas Company 10.0% * *
El Paso Production 14.6% * *
Energetics, LTD. 10.0% * *
Jenex Petroleum Corp., a related party 17.2% 23.0% 18.1%
Merit Energy * * 14.4%
Sunoco, Inc.** * * 11.9%
* less than 10%
** Replaced Energetics as the purchaser on the
Scheffler and Sunbelt oil wells in Michigan
Management believes that the loss of any individual purchaser would not
have a long-term material adverse impact on the financial position or results of
operations of the Company.
Financial Information About Industry Segments
The Company's operations presently consist of oil and natural gas
production. During previous years the Company has generated revenues through
the sale or leasing of oil and natural gas leasehold interests; however, no
significant revenues were generated from this source for the last five years.
Government Regulation
The Company's operations are primarily indirectly affected by political
developments and by federal, state and local laws and regulations.
Legislation and administrative regulations relating to the oil and natural
gas industry are periodically changed for a variety of political, economic
and other reasons. Numerous federal, state and local departments and agencies
issue rules and regulations binding on the oil and natural gas industry, some of
which carry substantial penalties and sanctions for failure to comply. The
regulatory burden on the industry increases the cost of doing business,
decreases flexibility in the timing of operations and may adversely affect the
economics of capital projects.
In the past, the federal government has regulated the prices at which oil
and natural gas could be sold. Prices of oil and natural gas sold by the Company
are not currently regulated, but there is no assurance that such regulatory
treatment will continue indefinitely into the future. Congress, or in the case
of certain sales of natural gas by pipeline affiliates over which it retains
jurisdiction, the Federal Energy Regulatory Commission ("FERC") could re-enact
price controls or other regulations in the future.
In recent years, FERC has taken significant steps to increase competition
in the sale, purchase, storage and transportation of natural gas. FERC's
regulatory programs allow more accurate and timely price signals from the
consumer to the producer and, on the whole, have helped natural gas become more
responsive to changing market conditions. To date, the Company believes it has
not experienced any material adverse effect as the result of these initiatives.
Nonetheless, increased competition in natural gas markets can and does add to
price volatility and inter-fuel competition, which increases the pressure on
the Company to manage its exposure to changing conditions and position itself
to take advantage of changing markets. Additional proposals are pending before
Congress and FERC that might affect the oil and natural gas industry. The oil
and natural gas industry has historically been heavily regulated at the federal
level; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by FERC and Congress will continue.
State statutes govern exploration and production operations, conservation
of oil and natural gas resources, protection of the correlative rights of oil
and natural gas owners and environmental standards. State Commissions implement
their authority by establishing rules and regulations requiring permits for
drilling, reclamation of production sites, plugging bonds, reports and other
matters. There can be no assurance that, in the aggregate, these and other
regulatory developments will not increase the cost of operations in the future.
Environmental Matters
The Company's operations are primarily indirectly subject to numerous laws
and regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection.
The Company's operations are primarily indirectly subject to stringent
federal, state and local laws governing the discharge of materials into the
environment or otherwise relating to environmental protection. Numerous
governmental departments such as the federal Environmental Protection Agency
("EPA") issue regulations to implement and enforce such laws, which are often
difficult and costly to comply with and which carry substantial civil and
criminal penalties and sanctions for failure to comply. These laws and
regulations may require the acquisition of a permit before drilling commences,
restrict the types, quantities and concentrations of various substances that
can be released into the environment in connection with drilling, production
and transporting through pipelines, limit or prohibit drilling activities on
certain lands lying within wilderness, wetlands, frontier and other protected
areas, require some form of remedial action to prevent pollution from former
operations such as plugging abandoned wells, and impose substantial liabilities
for pollution resulting from operations. In addition, these laws, rules and
regulations may restrict the rate of production. The regulatory burden on the
oil and natural gas industry increases the cost of doing business and affects
profitability. Changes in environmental laws and regulations occur frequently,
and changes that result in more stringent and costly waste handling, disposal
or clean-up requirements could adversely affect the Company's operations and
financial position, as well as the industry in general.
The Company is not aware of any instance in which it was found to be in
violation of any environmental or employee regulations or laws, and the Company
is not subject to any present litigation or claims concerning such matters.
In some instances the Company could in the future incur liability, even as a
non-operator, for potential environmental waste or damages or employee claims
occurring on oil and natural gas properties or leases in which the Company has
an ownership interest.
Forward-Looking Statements
Certain information included in this report, other materials filed or to be
filed by the Company with the Securities and Exchange Commission ("SEC"), as
well as information included in oral statements or other written statements made
or to be made by the Company contain or incorporate by reference certain
statements (other than statements of historical or present fact) that constitute
"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 or present facts, that address
activities, events, outcomes or developments that the Company plans, expects,
believes, assumes, budgets, predicts, forecasts, estimates, projects, intends or
anticipates (and other similar expressions) will or may occur in the future are
forward-looking statements. These forward-looking statements are based on
management's current belief, based on currently available information, as to the
outcome and timing of future events. When considering forward-looking
statements, you should keep in mind the risk factors and other cautionary
statements in this Form 10-K. Such forward-looking statements appear in a number
of places and include statements with respect to, among other things, such
matters as: future capital, development and exploration expenditures (including
the amount and nature thereof), drilling, deepening or refracing of wells, oil
and natural gas reserve estimates (including estimates of future net revenues
associated with such reserves and the present value of such future net
revenues), estimates of future production of oil and natural gas, expected
results or benefits associated with recent acquisitions, business strategies,
expansion and growth of the Company's operations, cash flow and anticipated
liquidity, grassroots prospects and development and property acquisition,
obtaining financial or industry partners for prospect or program development, or
marketing of oil and natural gas. We caution you that these forward-looking
statements are subject to all of the risks and uncertainties, many of which are
beyond our control, incident to the exploration for and development, production
and sale of oil and natural gas. These risks include but are not limited to:
general economic conditions, the market price of oil and natural gas, the risks
associated with exploration, the Company's ability to find, acquire, market,
develop and produce new properties, operating hazards attendant to the oil and
natural gas business, uncertainties in the estimation of proved reserves and in
the projection of future rates of production and timing of development
expenditures, the strength and financial resources of the Company's competitors,
the Company's ability to find and retain skilled personnel, climatic conditions,
labor relations, availability and cost of material and equipment, environmental
risks, the results of financing efforts, regulatory developments and the other
risks described in this Form 10-K.
Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact way.
The accuracy of any reserve estimate depends on the quality of available data
and the interpretation of that data by geological engineers. In addition, the
results of drilling, testing and production activities may justify revisions of
estimates that were made previously. If significant, these revisions could
change the schedule of any further production and/or development drilling.
Accordingly, reserve estimates are generally different from the quantities of
oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described above or
elsewhere in this Form 10-K occur, or should underlying assumptions prove
incorrect, our actual results and plans could differ materially from those
expressed in any forward-looking statements. We specifically disclaim all
responsibility to publicly update any information contained in a forward-
looking statement or any forward-looking statement in its entirety and
therefore disclaim any resulting liability for potentially related damages.
All forward-looking statements attributable to Croff or its management
are expressly qualified in their entirety by this cautionary statement.
Fluctuations in Profitability of the Oil and Natural Gas Industry
The oil and natural gas industry is highly cyclical and historically
has experienced severe downturns characterized by oversupply and weak demand.
Many factors affect our industry, including general economic conditions,
consumer preferences, personal discretionary spending levels, interest rates
and the availability of credit and capital to pursue new production
opportunities. It is possible that the oil and natural gas industry will
experience sustained periods of decline in the future. Any such decline
could have a material adverse affect on our business.
Competition
The oil and natural gas industry is highly competitive. The Company
encounters competition in all of its operations, including the acquisition of
exploration and development prospects and producing properties. The Company
competes for acquisitions of oil and natural gas properties with numerous
entities, including major oil companies, other independents, and individual
producers and operators. Almost all of these competitors have financial and
other resources substantially greater than those of the Company. The ability
of the Company to increase reserves in the future will be dependent on its
ability to select and successfully acquire suitable producing properties and
prospects for future development and exploration.
Estimates of Oil and Natural Gas Reserves, Production and Replacement
The information on proved oil and natural gas reserves included in this
document are simply estimates. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment, assumptions used regarding quantities of oil and
natural gas in place, recovery rates and future prices for oil and natural gas.
Actual prices, production, development expenditures, operating expenses and
quantities of recoverable oil and natural gas reserves will vary from those
assumed in our estimates, and such variances may be significant. If the
assumptions used to estimate reserves later prove incorrect, the actual
quantity of reserves and future net cash flow could be materially different
from the estimates used herein. In addition, results of drilling, testing and
production along with changes in oil and natural gas prices may result in
substantial upward or downward revisions.
Corporate Offices and Employees
The corporate offices are located at 3773 Cherry Creek Drive North, Suite
1025, Denver, Colorado 80209. The Company is not a party to any lease, but
during 2004 paid Jenex Petroleum Corporation, which is owned by the Company's
President, for office space and all office services, including rent, phone,
office supplies, secretarial, land, and accounting. The Company's expenses for
these services were $24,000, $30,000 and $48,000 for the years ended 2002, 2003
and 2004, respectively. Although these transactions were not a result of "arms
length" negotiations, the Company's Board of Directors believes the transactions
are reasonable.
The Company currently has five (5) directors. The Company has one
employee, the President, and three part-time contract workers. The contract
workers are provided to the Company as part of its office lease and overhead
agreement. The President and the contract workers work from the Company's
corporate offices. None of the Croff staff is represented by a union.
Foreign Operations and Subsidiaries
The Company has no foreign operations, exports, or subsidiaries.
ITEM 2. PROPERTIES
Present Activities
The Company remains focused on finding lower risk oil and natural gas
opportunities. During 2004, the Company continued to acquire and renew
leases, and develop its drilling package with the goal of attracting
development partners principally for the Company's Yorktown Re-entry Program
in DeWitt County, Texas. The majority of these leases were acquired in 2003,
after the Company's management reviewed the existing logs as to the potential
size and productivity of the Edwards limestone and Wilcox natural gas
producing sands in this area. These leases contain eight existing wellbores,
of which two were drilled to the Edwards formation and six were drilled to the
Wilcox formation.
In November 2004, the Company signed a Prospect Participation
Agreement ("Agreement") with Tempest Energy Resources, LP
("Tempest") to participate in the development of its Yorktown Re-entry
Program located in Dewitt County, Texas. The Company reported this
Agreement on November 19, 2004, on Form 8-K. Significant portions of
this Agreement are summarized below; and the Agreement is set-out in its
as a Form 8-K exhibit to this filing: The Agreement outlines the Parties
intent to potentially develop an area containing approximately 830 acres
with 8 re-entry prospects, as well as potential new drilling locations. The
Program is targeting wells which may produce natural gas and condensate
from either the Edwards limestone or Wilcox formations. The Agreement
provides for the parties to work together in this area of mutual interest
("AMI") for a period of up to 5 years. Under the general terms of the
Agreement, Croff will assign 75% interest in the leases, excluding the
Helen Gips #1 wellbore, to Tempest, subject to all royalties. Tempest will
pay Croff $100 per net acre assigned. Tempest will pay Croff a
participation fee of $50,000 per well re-entry that the Parties agree to
develop. On all re-entry wells the Parties agree to develop, Croff will have
a carried working interest of 15% through the drilling and development
stages of the re-entry wells and Croff can participate on a equal cost
sharing basis for an additional 10% working interest. Management
believes that should both Parties agree to develop the remaining seven re-
entry prospects that it would cost Croff approximately $700,000 to elect to
participate on an equal cost sharing basis for an additional 10% working
interest. On all new wells the Parties agree to develop, Croff can elect to
participate on an equal cost sharing basis for up to 25% of the working
interest. Tempest or its designee will assume operating control and shall
become the operator of record for all wells covered by this Agreement.
The Parties agreed to the following with respect to the Helen Gips #1 well,
which Croff previously had begun to develop. Croff agreed to assign 60% of the
working interest in the Helen Gips #1 to Tempest. Tempest agreed to pay a
$100,000 participation fee, to reimburse Croff for certain costs incurred on the
Helen Gips #1 prior to closing of the Agreement, and pay the remaining
completion costs, and assume operations.
In 2003, the Company acquired a 10% working interest in one oil and natural
gas well in Hardin County, Texas for $30,000 and a 20% working interest in one
oil well in Cheboygan County, Michigan for $70,000. These acquisitions
increased reserves by 34,036 barrels of oil and 91,496 Mcf of natural gas and
increased the present value (PV10%) at December 31, 2003 by approximately
$450,000.
Drilling Activities
The Company re-entered the Helen Gips #1 well in DeWitt County, Texas, and
re-completed the wellbore to the Wilcox formation during 2004. The Helen
Gips #1 well currently, has been perforated, fraced, and completion efforts are
still in process. Under the successful efforts method of accounting the Company
has capitalized $65,213 as of December 31, 2004, for costs incurred on this
unevaluated exploratory well. The capitalized costs associated with this
unevaluated exploratory well have been excluded from depletion and depreciation
during the 2004.
Delivery Commitments
For the year ended December 31, 2004, the Company had no delivery
commitments with respect to the production of oil and natural gas. The
Company is unaware of any arrangements pertaining to any delivery commitments
on royalty wells.
General
The Company's "Developed acreage" consists of leased acreage spaced or
assignable to production on wells having been drilled or completed to a point
that would permit production of commercial quantities of oil or natural gas.
The Company's "Gross acreage" is defined as total acres in which the Company has
an interest; "Net acreage" is the actual number of mineral acres owned by the
Company. Most developed acreage is held by production. The remaining acreage
leases expire in 1 to 3 years. The acreage is concentrated in Alabama,
Michigan, New Mexico, Oklahoma, Texas, and Utah and is widely dispersed in
Colorado, Montana, North Dakota, and Wyoming.
During 2004, the Company's production averaged 168 Mcf of natural gas and
22 Bbl of oil per day. The Company's average daily production during 2003 was
145 Mcf of natural gas and 21 Bbl of oil. "Proved developed" oil and natural
gas reserves are reserves expected to be recovered from existing wells with
existing equipment and operating methods. "Proved undeveloped" oil and natural
gas reserves are reserves that are expected to be recovered from new wells on
undrilled acreage, or from existing wells where a relative major expenditure is
required for re-completion.
The quantities and values in the tables that follow are based on average
prices for the year 2004 which averaged $38.81 per barrel of oil and $4.87 per
Mcf of natural gas or in some cases constant prices in effect at December 31,
2004. These average prices are lower than the December 31, 2004 prices used in
the Company's 2004 reserve study. Higher prices increase reserve values by
raising the future net revenues attributable to the reserves and increasing the
quantities of reserves that are recoverable on an economic basis. Price
decreases have the opposite effect. A decline in the prices of oil or natural
gas could have a material adverse effect on the Company's financial condition
and results of operations.
Future prices received from production and future production costs may
vary, perhaps significantly, from the prices and costs assumed for purposes
of these estimates. There can be no assurance that the proved reserves will
be developed within the periods indicated or that the prices and costs will
remain constant. There can be no assurance that actual production will
equal the estimated amounts used in the preparation of reserve projections.
The present values shown should not be construed as the current market
value of the reserves. The quantities and values shown in the tables that
follow are based on oil and natural gas prices in effect on December 31,
2003. The value of the Company's assets is in part dependent on the prices
the Company receives for oil and natural gas, and a decline in the price of
oil or natural gas could have a material adverse effect on the Company's
financial condition and results of operations. The 10% discount factor used to
calculate present value, which is specified by the Securities and Exchange
Commission (the "SEC"), is not necessarily the most appropriate discount rate,
and present value, no matter what discount rate is used, is materially affected
by assumptions as to timing of future production, which may prove to be
inaccurate. The calculation of estimated future net revenues does not take into
account the effect of various cash outlays, including, among other things,
general and administrative costs.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. The data in the tables that follow represent
estimates only. Oil and natural gas reserve engineering is a subjective process
of estimating underground accumulations of oil and natural gas that cannot be
measured in an exact way. The accuracy of any reserve estimate is a function
of the quality of available data and engineering and geological interpretation
and judgment. Results of drilling, testing and production after the date of
the estimate may justify revisions. Accordingly, reserve estimates are often
materially different from the quantities of oil and natural gas that are
ultimately recovered.
Independent petroleum engineering firms compiled the proved oil and
natural gas reserves and future revenues as of December 31, 2002, 2003 and
2004 for the Company's most significant wells. Management completed the
2002, 2003 and 2004 reserve reports from these base studies. Since
December 31, 2004, the Company has not filed any estimates of its oil and
natural gas reserves with, nor was any such estimates included in
any reports to, any state or federal authority or agency, other than the
Securities and Exchange Commission.
For additional information concerning oil and natural gas reserves, see
Supplemental Information - Disclosures about Oil and Natural Gas Producing
Activities - Unaudited, included with the Financial Statements filed as a
part of this report.
The following table sets forth summary information with respect to
estimated proved reserves at December 31, 2004.
ESTIMATED PROVED RESERVES
As of December 31, 2004
Net Oil Net Natural Gas Pre-Tax Present
Area (Bbls) (Mcf) Value 10%
------------------- ----------- ----------- -------------------
Alabama - 977 $ 2,700
Colorado 300 46,446 143,000
Michigan 48,979 37,729 575,200
Montana 2,556 - 17,800
New Mexico 1,460 80,532 210,100
North Dakota 2,663 1,330 54,100
Oklahoma 1,252 120,529 237,300
Texas 1,407 20,472 70,500
Utah 8,894 22,233 224,000
Wyoming 4,751 22,726 108,300
------ ------- ----------
Total 72,262 352,974 $1,643,000
The following table sets forth summary information with respect to
oil and natural gas production for the year ended December 31, 2004.
STATE GEOGRAPHIC DISTRIBUTION OF NET PRODUCTION
Net Oil Net Natural Gas
State (Bbls) (Mcf)
-------------------- ----------- -----------
Alabama - 190
Colorado 66 9,253
Michigan 4,553 4,625
Montana 219 -
New Mexico 38 9,387
North Dakota 570 1,348
Oklahoma 376 23,134
Texas 194 4,817
Utah 1,367 3,583
Wyoming 628 3,622
----- ------
Total 8,011 59,959
The following table sets forth summary information with respect to the
Company's estimated number of productive wells as of December 31, 2004.
PRODUCTIVE WELLS AND ACREAGE (1)(2)(3)
As of December 31, 2004
Net Acreage
Gross Oil Gross Gas Net Oil Net Gass with
Area Wells(2) Wells(2) Wells Wells Production
- --------------- ---------- ---------- ---------- ---------- ------------
Alabama - 2 - .01 10
Colorado 1 13 .04 .02 40
Michigan 3 33 .98 .19 188
Montana 1 - .05 - 5
New Mexico - 57(3) .01 .03 55
North Dakota 10 6 .12 .12 38
Oklahoma 3 8 .25 1.28 173
Texas 5 7 .08 .08 349
Utah 116 29 .20 .13 650
Wyoming 5 7 .14 .12 120
--- --- ---- ---- -----
Total 144 162 1.87 1.98 1,628
The Company's "Gross Wells" are defined as total number of wells in
which the Company has any interest in; "Net Wells" are defined as the
Company's total aggregate percentage of ownership interest from wells
in which the Company has an ownership interest in a defined area;
"Net acreage" are the actual number of mineral acres owned by the Company.
(1) This chart contains estimates associated with small mineral interests
and small leases.
(2) Wells included twice if it produces both oil and gas.
(3) These natural gas wells in New Mexico also produce some condensate.
The following table sets forth summary information with respect to the
Company's undeveloped acreage as of December 31, 2004.
UNDEVELOPED ACREAGE
As of December 31, 2004
Total Undeveloped Acreage
----------------------------------------------------
Area Proven Unproven
------------------- ------------------------ ------------------------
Gross Acres Net Acres Gross Acres Net Acres
----------- ----------- ----------- -----------
Colorado 80 7 600 40
Montana - - 3,800 250
Texas 351 281 829 207
Utah 8,000 140 102,000 3,300
Oil and Natural Gas Mineral Interests and Royalties
The Company owns perpetual mineral interests which total approximately
4,600 net mineral acres, of which approximately 1,100 net acres are producing.
The mineral interests are located in 110,000 gross acres primarily in Duchesne,
Uintah and Wasatch Counties in Utah, and approximately 40 net mineral acres in
La Plata County, Colorado, and San Juan County, New Mexico.
The Company continues to execute a few new leases or renewals on its
perpetual mineral interests. Overall, however, the amount of new leasing
activity during 2003 and 2004 was not significant. In November 2004, the
Company leased 93.5722 net acres to Petroglyph, for mineral interests in Uintah
County, Utah. In December 2004, the Company leased 50.2374 net acres in
Duchesne County, Utah to Flying J. During 2003, the Company leased 22 acres of
gross mineral interest in Duchesne County, Utah to Berry Corp.
As of December 31, 2004, the Company was receiving royalties from
approximately 250 producing wells, primarily in the Bluebell-Altamont field in
Duchesne and Uintah Counties, Utah and from coal bed methane wells in the four
corners region of Colorado and New Mexico. Royalties also were received from
scattered interests in Alabama, Texas, and Wyoming. Other significant royalties
were paid from the four corners region.
Oil and Natural Gas Working Interests
The Company has sought to increase its production of oil and natural gas
through the purchase of producing leases. The Company believes, in general,
that it is able to purchase working interests at a more reasonable price than
royalty interests. A working interest requires the owner to pay its
proportionate share of the costs of producing the well, while a royalty is
paid out of the revenues without a deduction for the operating costs of the
well. When oil or natural gas prices drop, the proportion of the revenues
going to pay the expense of operating the well increases, and when oil and
natural gas prices are rising, expenses decrease as a percentage of total
revenues. The Company's purchases of working interests are intended to
increase oil and natural gas production over time. Earlier than 1985, the
Company participated in new wells drilled as a royalty owner. A royalty
owner generally receives a smaller interest, but does not share in the
expense of drilling or operating the wells. Since 1985, the Company primarily
participates as a working interest owner in drilled wells.
AVERAGE SALES PRICES AND PRODUCTION COST
The following table sets forth summary information with respect to the
Company's approximate average sales price per barrel (oil) and Mcf (1000 cubic
feet of natural gas), together with approximate average production costs for
units of production for the Company's production revenues by geographic area
for the last three years.
AVERAGE SALES PRICES AND PRODUCTION COST
Past Three Years by Geographic Area
Average Sales Price* Average Production Cost*
--------------------------------------------- --------------------------------------------
2004 2003 2002 2004(1) 2003(1) 2002(1)
------------- ------------- ------------- ------------- ------------- ------------
Geographic Area Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas
- --------------- | ------ ------ | ------ ------ | ------ ------ | ------ ------ | ------ ------ | ------ ------ |
| | | | | | |
| | | | | | |
Alabama | $ - $ 6.10 | $ - $ 4.18 | $ - $ 2.96 | $ n/a $ 2.24 | $ n/a $ 1.12 | $ n/a $ 0.79 |
Colorado | $36.01 $ 5.05 | $31.54 $ 3.85 | $21.28 $ 1.75 | $ 6.64 $ 1.11 | $12.58 $ 0.07 | $ 8.49 $ 0.03 |
Michigan | $38.80 $ 6.10 | $28.50 $ 4.39 | $25.96 $ 3.15 | $16.91 $ 2.82 | $ 5.78 $ 1.17 | $ 5.27 $ 0.84 |
Montana | $40.45 $ - | $27.97 $ - | $20.58 $ - | $24.30 $ - | $14.31 $ n/a | $10.53 $ n/a |
New Mexico | $40.26 $ 4.73 | - $ 4.42 | $27.14 $ 3.10 | $ 3.12 $ .52 | $ n/a $ 0.27 | $ 2.34 $ 0.19 |
North Dakota | $39.25 $ 2.12 | $28.43 $ 1.93 | $23.49 $ 1.64 | $10.60 $ 1.63 | $ 8.42 $ 1.19 | $ 6.96 $ 1.01 |
Oklahoma | $38.20 $ 4.66 | $26.42 $ 4.28 | $22.88 $ 2.18 | $10.46 $ 1.74 | $14.14 $ 2.75 | $12.25 $ 1.40 |
Texas | $39.58 $ 5.33 | $28.01 $ 4.18 | $25.43 $ 2.89 | $ 7.27 $ 1.21 | $11.51 $ 2.23 | $10.45 $ 1.54 |
Utah | $40.42 $ 5.07 | $29.15 $ 2.99 | $22.55 $ 1.49 | $ 6.70 $ 1.12 | $ 3.92 $ 0.04 | $ 3.03 $ 0.02 |
Wyoming | $34.73 $ 4.64 | $24.50 $ 4.05 | $16.38 $ 2.36 | $10.03 $ 1.67 | $ 8.96 $ 1.05 | $ 5.99 $ 0.61 |
* Oil is per Bbl and Gas is per Mcf.
(1) States with higher production from Croff's royalty interests such as
New Mexico and Utah, reflect a lower cost per barrel or Mcf
ITEM 3. LEGAL PROCEEDINGS
The Company is not a party to any legal actions.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On December 3, 2004, the annual meeting of shareholders was held. The
shareholders elected the five board members listed under Item 10, and
ratified Causey Demgen & Moore, Inc. as independent auditors of the Company.
PART II
ITEM 5. MARKET FOR REGISTRANT'S SECURITIES, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
The Company's common stock is listed and occassionally traded on the Over
The Counter Bulletin Board (www.otcbb.com) under symbol "COFF". The Company has
authorized 20,000,000 shares of common stock, of which only 568,900 shares are
outstanding to 1,168 shareholders. The preferred B shares also have an
extremely limited market, but are traded from time to time through a
Clearinghouse held by the Company. The Company acts as its own transfer agent
with respect to these preferred B shares. The Company maintains a clearinghouse
for its shares at (www.croff.com). Bids and offers can be posted for both
preferred B shares and common shares on this Web site. In addition the Company
posts its recent SEC filings on the Web site.
The trading range for 2002 through 2004 is shown for common shares and
preferred shares as a guide to as to what transactions have either taken place
or of which the Company is aware of the bid or ask price.
COMMON SHARES - 568,900 SHARES OUTSTANDING FOR 2004 - (The following data is
generated from limited trades from the Company's website, the
over-the-counter bulletin board including purchases by the
Company's management.)
BID RANGE
Calendar Quarter Bid Asked
---------------- ------ ------
2002: First Quarter $ .90 $1.00
Second Quarter $ .90 $1.00
Third Quarter $ .90 $1.00
Fourth Quarter $ .90 $1.00
2003: First Quarter $ .90 $1.00
Second Quarter $ .90 $1.00
Third Quarter $ .90 $1.00
Fourth Quarter $ .90 $1.25
2004: First Quarter $ .55 $1.10
Second Quarter $ .25 $1.60
Third Quarter $1.75 $1.80
Fourth Quarter $1.01 $2.20
As of December 31, 2004, there were 1,168 holders of record of the
Company's common stock. The Company has never paid a dividend and has no
present plan to pay any dividend.
PREFERRED "B" SHARES - 540,659 SHARES OUTSTANDING - (The following data is
generated solely from private transactions or internal
purchases by the Company)
BID RANGE
Calendar Quarter Bid Asked
---------------- ------ ------
2002: First Quarter No Trading No Trading
Second Quarter No Trading No Trading
Third Quarter No Trading No Trading
Fourth Quarter No Trading No Trading
2003: First Quarter No Trading No Trading
Second Quarter No Trading No Trading
Third Quarter No Trading No Trading
Fourth Quarter No Trading No Trading
2004: First Quarter $1.05 $1.05
Second Quarter No Trading No Trading
Third Quarter No Trading No Trading
Fourth Quarter No Trading No Trading
Historical Events of Interest
In November 1991, Croff reverse-split the common stock on a ratio of 1
share of common stock for every 10 shares previously held. A trading range
of approximately $1.00 to $1.10 per bid was established and prevailed for
approximately four years.
On February 28, 1996, the shareholders approved the issuance of the
preferred B stock to be issued to each common shareholder on the basis of one
share preferred B for each share of common stock. The Company issued all of
the preferred shares and delivered the preferred B shares to each of the
shareholders for which it had a current address.
In June 2000, the Company approved the increase in the authorized Class B
Preferred stock to 1,000,000 shares.
During 2001, the Board determined that the cash of the Company, which had
been building during a period of high oil prices, should be formally allocated
between the common stock and the preferred B stock. The Board decided to
allocate $250,000 cash to the common stock and the balance of cash remaining
with the preferred B stock. The Board then determined that future oil and gas
cash flow from the preferred B assets would be accumulated for preferred B
shareholders. The Company established separate investment accounts for the
preferred B and common stock investments.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected historical financial data of the
Company for the five-year period ended December 31, 2004. Future results may
differ substantially from historical results because of changes in oil and
natural gas prices, production increases or declines and other factors. This
information should be read in conjunction with the Financial Statements, and
notes thereto, and Management's Discussion and Analysis of Financial Condition
and Results of Operations, presented elsewhere herein.
STATEMENT OF OPERATIONS DATA
Fiscal Year Ended December 31:
2000 2001 2002 2003 2004
-------- -------- -------- -------- --------
STATEMENT OF OPERATIONS DATA
Operations
Oil and Natural Gas $368,022 $332,573 $286,602 $392,564 $ 608,132
Other Revenues $ 1,347 $ 32,652 $ 28,726 $ 23,362 $ (31,970)
Expenses $237,701 $303,690 $216,416 $321,817 $ 434,046
Net Income $131,668 $ 61,535 $ 98,912 $ 94,109 $ 142,116
Per Common Share (1) $ .01(1) $ .06(1) $ .04(1) $ .01(1) $ (.13)(1)
Working capital $273,295 $385,816 $419,475 $336,471 $ 330,243
Dividends per share NONE NONE NONE NONE NONE
BALANCE SHEET DATA
Total assets $628,172 $695,124 $753,212 $898,221 $1,088,553
Long-term debt** NONE NONE NONE NONE NONE
Stockholders' equity $611,966 $672,085 $736,408 $866,112 $1,051,438
** There were no long-term obligations from 2000-2004.
(1) The Company allocates its net income between preferred B shares and common
shares; accordingly, net income (loss) applicable to common shares varies
from a fixed ratio to net income.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND
RESULTS OF OPERATIONS
Critical Accounting Policies and Estimates
The Company's discussion and analysis of its financial
condition and results of operation are based upon Financial
Statements, which have been prepared in accordance with
accounting principles generally accepted in the United States of
America. The preparation of these Financial Statements requires
the Company to make estimates and judgments that affect the
reported amounts of assets and liabilities and disclosures of
contingent assets and liabilities at the date of the Financial
Statements and the reported amounts of revenues and expenses
during the year. The Company analyzes its estimates, including
those related to oil and natural gas revenues, oil and natural gas
properties, marketable securities, income taxes and contingencies.
The Company bases its estimates on historical experience and
various other assumptions that are believed to be reasonable under
the circumstances. Actual results may differ from these estimates
under different assumptions or conditions.
The Company believes the following critical accounting policies
affect its more significant judgments and estimates used in the preparation
of its Financial Statements and the uncertainties that it could impact our
results of operations, financial condition and cash flows. The Company
follows the "successful efforts" method of accounting for its oil and gas
properties. Under this method, all property acquisition costs and costs of
exploratory and development wells are capitalized when incurred, pending
determination of whether the well has proven reserves. If an exploratory
well does not result in reserves, the capitalized costs of drilling the well,
net of any salvage, are charged to expense. The costs of development wells
are capitalized, whether the well is productive or nonproductive.
Impairments are recorded when management believes that a property's net
book value is not recoverable based on current estimates of expected future
cash flows. The Company provides for depreciation and depletion of its
investment in producing oil and natural gas properties on the unit-of-
production method, based upon estimates of recoverable oil and natural gas
reserves from the property. The Company designated its marketable equity
securities as "securities available for sale"
Liquidity and Capital Resources
At December 31, 2004, the Company had assets of $1,088,553.
At December 31, 2004, the Company's current assets totaled $367,358
compared to current liabilities of $37,115. Working capital at December
31, 2004 totaled $330,243, a decrease of 2% compared to $336,471 at
December 31, 2003. The Company had a current ratio at December 31,
2004 of approximately 10:1. During 2004, net cash provided by
operations totaled $207,727, as compared to $140,003 for 2003. The
Company's cash flow from operations is highly dependent on oil and
natural gas prices; which were at historic highs in 2004. The Company
had no short-term or long-term debt outstanding at December 31, 2004.
At December 31, 2004, there were several contingent
commitments for capital expenditures under the Prospect
Participation Agreement with Tempest. Capital expenditures for
2004 totaled $311,054 and were primarily attributable to the
acquisition and potential development of non-producing mineral
leases with re-entry wells in DeWitt County, Texas. The majority
of those properties are now part of the area of mutual interest
under the Prospect Participation Agreement with Tempest. The
Company estimates its 2005 capital budget to be approximately
$600,000. The Company believes that borrowings from financial
institutions, projected operating cash flows and the cash on hand will be
sufficient to cover its working capital requirements for the next 12
months.
While certain costs are affected by the general level of inflation,
factors unique to the oil and natural gas industry result in independent
price fluctuations. Over the past five years, significant fluctuations have
occurred in oil and natural gas prices. Although it is particularly difficult
to estimate future prices of oil and natural gas, price fluctuations have
had, and will continue to have, a material effect on the Company.
Overall, it is management's belief that inflation is generally favorable to
the Company since it does not have significant operating expenses.
Results of Operations
Revenues for 2004 totaled $576,162, an increase of 39% from
2003. Net income for 2004 totaled $142,116 compared to $94,109 for
2003. The increase in revenue was due primarily to increases in oil and
natural gas prices as well as a 5% increase in oil production and a 16%
increase in natural gas production. The average sale price of oil in 2004
for the Company was $38.81 compared to $28.32 in 2003. The average
sale price of natural gas in 2004 for the Company was $4.87 per Mcf,
compared to $4.09 per Mcf in 2003. The Company realized a net loss
during 2004 of $7,599 related to its 2003 purchase of natural gas "put"
contracts which had a strike price of $4.75 per Mcf. The Company
realized a net loss on the sale of marketable equity securities totaling
$38,166. Other income, which is composed primarily of interest and
dividend income as well as lease bonus payments, increased
approximately 58% during 2004 to $6,196 from $3,912 in 2003.
Revenues for 2003 totaled $415,926, an increase of 32% from
2002. Net income for 2003 totaled $94,109 compared to $98,912 in
2002. The increase in revenue was due primarily to increases in oil and
natural gas prices as well as a 25% increase in oil production, which
more than offset an 8% decrease in natural gas production. The average
sale price of oil in 2003 for the Company was $28.32 compared to
$22.62 in 2002. The average sale price of natural gas in 2003 for the
Company was $4.09 per Mcf, compared to $2.56 per Mcf in 2002.
Production of oil increased approximately 25% in 2003, while
production of natural gas decreased 8% compared to 2002 production
levels. Oil production increased primarily due to the acquisition of
certain oil producing properties in 2002. The Company realized a gain
on the sale of marketable equity securities totaling $19,450 and $23,026
for the years ended December 31, 2003 and 2002, respectively. Other
income, which is composed primarily of interest and dividend income,
decreased approximately 31% during 2003 to $3,912 from $5,700 in
2002. Net income for 2003 decreased slightly from 2002 primarily as a
result of a realized a loss incurred of $45,022 during 2003, related to the
purchase of natural gas "put" contracts which had a strike price of $4.75
per Mcf.
Lease operating expense for 2004, which includes all production
related taxes, totaled $192,187 compared to $130,793 for 2003. The
Company began paying lease operating expenses during 2004 on the
State Forest well in Michigan which totaled $7,000 and on the PICA well
in Texas which totaled $2,400. The Company paid $5,400 in lease
operating expenses on the four wells it acquired and now operates in
DeWitt County, Texas. In addition, the Company paid higher production
related taxes associated with the increases in oil and natural gas prices.
Lease operating expense, which includes all production related
taxes, increased by approximately $54,000 in 2003 to $130,793
compared to $77,065 in 2002. Lease operating expenses increased
primarily due to the acquisition of certain working interests in 2002, as
well as increases associated with higher production related taxes
associated with the increases in oil and natural gas prices.
In 2004, the Company incurred $30,825 in costs related to its
Yorktown Re-entry Program in DeWitt County, Texas. These costs
included professional fees, travel expenses and insurance premiums
associated with the acquisition and potential development of these leases
in DeWitt County, Texas. In November 2004, the Company entered into
a Prospect Participation Agreement with Tempest related to this
program.
During 2003, the Company incurred $13,780 in costs related to
its proposed Yorktown Re-entry Program in DeWitt County, Texas. In
November 2004, the Company entered into a Prospect Participation
Agreement with Tempest related to this program.
General and administrative expense, including rent for 2004,
totaled $160,157 which was $27,913 higher than 2003 which totaled
$132,244. This increase was primarily attributable to approximately
$18,000 in additional overhead costs incurred due to higher workload on
the Yorktown Re-entry Program, in DeWitt County, Texas, which were
paid to a related party and $7,000 in additional depletion and
depreciation costs.
General and administrative expense, including rent for 2003,
totaled $132,244 which is $24,893 higher than 2002 which totaled
$107,351. This increase was primarily attributable to approximately
$15,000 in additional costs incurred related to the preparation of the
Company's Annual Report and compliance with the Sarbanes-Oxley Act
of 2002. In addition, the Company incurred approximately $10,000 in
additional general and administrative expenses associated with the
development of its proposed drilling fund.
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") 123R,
"Share-Based Payment." This revised standard addresses the accounting for
share- based payment transactions in which a company receives employee
services in exchange for either equity instruments of the company or
liabilities that are based on the fair value of the company's equity
instruments or that may be settled by the issuance of such equity
instruments. Under the new standard, companies will no longer be able to
account for share-based compensation transactions using the intrinsic
method in accordance with APB 25. Instead, companies will be required to
account for such transactions using a fair-value method and recognize the
expense in the statements of operations. SFAS 123R will be effective for
all interim or annual periods beginning after June 15, 2005. The adoption
of this announcement in July 2005, is not expected to have a material
impact on the Company's financial condition or results of operations as
the Company currently receive employee services in exchange for either
equity instruments of the company or liabilities that are based on the
fair value of the company's equity instruments or that may be settled by
the issuance of such equity instruments.
In December 2004, the FASB issued SFAS No. 153, "Exchanges of
Nonmonetary Assets - an amendment of APB Opinion No. 29". This standard
requires exchanges of productive assets to be accounted for at fair value,
rather than at carryover basis, unless (1) neither the asset received nor
the asset surrendered has a fair value that is determinable within
reasonable limits or (2) the transactions lack commercial substance. The
Statement is effective for non-monetary asset exchanges occurring in fiscal
periods beginning after June 15, 2005. The Company has not entered into
these types of nonmonetary asset exchanges during the last five years.
Accordingly, the adoption of this pronouncement is not expected to have a
material impact on the Company's financial condition or results of
operations.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's major market risk exposure is in the pricing
applicable to its oil and natural gas production. Realized pricing is
primarily driven by the prevailing domestic price for oil and natural gas.
Historically, prices received for oil and natural gas production have been
volatile and unpredictable. Pricing volatility is expected to continue.
Natural gas price realizations during 2004, ranged from a monthly low of
$1.92 per Mcf to a monthly high of $7.87 per Mcf. Oil prices ranged
from a monthly low of $25.79 per barrel to a monthly high of $49.19 per
barrel during 2004. A decline in prices of oil or natural gas could have a
material adverse effect on the Company's financial condition and results
of operations. In 2004, a 10% reduction in oil and natural gas prices
would have reduced revenues by approximately $60,000.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to the Index to Financial Statements on page
F-1 for a listing of the Company's Financial Statements and notes thereto
and for the financial statement schedules contained herein.
Management Responsibility for Financial Statements
The Financial Statements have been prepared by management in
conformity with accounting principles generally accepted in the United
States of America. Management is responsible for the fairness and
reliability of the Financial Statements and other financial data included in
this report. In the preparation of the Financial Statements, it is necessary
to make informed estimates and judgments based on currently available
information on the effects of certain events and transactions. The
Company maintains accounting and other controls which management
believes provide reasonable assurance that financial records are reliable,
assets are safeguarded and transactions are properly recorded.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
The Company has had no disagreements on accounting and financial
disclosure matters with its registered public accounting firm during the
2003, 2004, or from January 1, 2005 through the date of this filing.
ITEM 9A. CONTROLS AND PROCEDURES
The Company's principal executive officer and principal financial
officer have evaluated the effectiveness of Croff's "disclosure controls and
procedures," as such term is defined in Rule 13a-15(e) and 15d-15(c) of the
Securities Exchange Act of 1934, as amended, as of the end of the period
covered by this Annual Report on Form 10-K. Based upon their evaluation,
they have concluded that the Company's disclosure controls and
procedures are effective. There were no significant changes in the
Company's internal controls or in other factors that could significantly
affect these controls, since the date the controls were evaluated.
ITEM 9B. OTHER INFORMATION
The Company is not aware of any previously undisclosed, but required
information from the fourth quarter of 2004.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Identification of Directors, Officers and Significant Employees.
The Croff Board consists of Gerald L. Jensen, Dilworth A.
Nebeker, Richard H. Mandel Jr., Edwin W. Peiker Jr., and Julian D.
Jensen. Each director will serve until the next annual meeting of
shareholders, or until his successor is duly elected and qualified. The
Company has no knowledge of any arrangements or understandings
between directors or any other person pursuant to which any person was
or is to be nominated or elected to the office of director of the Company.
The following is provided with respect to each officer and director of the
Company as of February 25, 2005.
GERALD L. JENSEN, 65, PRESIDENT AND DIRECTOR
President of Croff Oil Company since October 1985. Mr. Jensen
has been an officer and director of Jenex Petroleum Corporation, a
private oil and natural gas company, for over ten years, and an officer
and director of other Jenex companies. In 2000, Mr. Jensen became
Chairman of Provisor Capital Inc., a private finance company. Mr.
Jensen was a director of Pyro Energy Corp., a public company
(N.Y.S.E.) engaged in coal production and oil and natural gas, from 1978
until it was sold in 1989. Mr. Jensen is also an owner of private real
estate, finance, and oil and natural gas companies.
STUART D. KROONENBERG, 36, CHIEF FINANCIAL OFFICER
AND SECRETARY
Mr. Kroonenberg has been the Company's Chief Financial
Officer since May 2001. Mr. Kroonenberg has over eight years
experience as a CPA, including two years as an Assurance Services
Manager, for a large international CPA firm. Mr. Kroonenberg has
extensive experience working with small and mid-size public and
privately held companies. Mr. Kroonenberg is a contract employee of
the company described in Item 13.
RICHARD H. MANDEL, JR., 75, DIRECTOR
Mr. Mandel has been a director of Croff Enterprises, Inc. since
1985. Since 1982, Mr. Mandel has been President and a Board Member
of American Western Group, Inc., an oil and natural gas producing
company in Denver, Colorado. From 1977 to 1984, he was President of
Universal Drilling Co., Denver, Colorado. Prior to 1977, Mr. Mandel
worked for the Superior Oil Co., Honolulu Oil Co., and Signal Oil and
Gas Co. as an engineer and in management.
DILWORTH A. NEBEKER, 64, DIRECTOR
Mr. Nebeker served as President of Croff from September 2,
1983 to June 24, 1985, and has been a director of Croff since December
1981. He is presently a consultant. Mr. Nebeker was a lawyer in private
practice from 1986 to 2001. He was a lawyer employed by Tosco
Corporation, a public corporation, from 1973 to 1978. He was a lawyer
with the Securities and Exchange Commission from 1967 to 1973. Mr.
Nebeker is Chairman of the Croff Audit Committee.
EDWIN W. PEIKER, JR., 73, DIRECTOR
Mr. Peiker currently serves as director of Croff. He was
President of Royal Gold, Inc., from 1988 through 1991, and continues to
be a director. Since 1986, Mr. Peiker has been a Vice President and
Director of Royal Gold, Inc., a public company engaged in gold
exploration and mining activities. Prior thereto he was involved in
private investments in oil and natural gas exploration and production.
Mr. Peiker was employed in responsible positions with AMAX, Inc., a
public corporation, from 1963 to 1983. Mr. Peiker is a member of the
Croff Audit Committee.
JULIAN D. JENSEN, 56, DIRECTOR
Mr. Jensen has been a director of Croff Enterprises, Inc. since
November 1991. Mr. Jensen is the brother of the Company's president
and has served as legal counsel to the Company for the past nine years.
Mr. Jensen has practiced primarily in the areas of corporate and
securities law, in Salt Lake City, Utah, since 1975. Mr. Jensen is
currently associated with the firm of Jensen, Duffin & Dibb, which acts
as legal counsel for the Company.
Compliance with Section 16(a) of the Securities Exchange Act of 1934
Based solely on a review of such forms furnished to the
Company and certain written representations from the Executive Officers
and Directors, the Company believes that all Section 16(a) filing
requirements applicable to its Executive Officers, Directors and greater
than ten percent beneficial owners were complied with on a timely basis
in 2004.
Audit Committee
The Board has established an Audit Committee to assist it in the
discharge of its responsibilities including the presentation and disclosures
of Croff's financial condition and results of operations and disclosure
controls and procedures. The Audit Committee is presently comprised of
Dilworth A. Nebeker and Edwin W. Peiker, Jr. both of whom are
independent directors of Croff. Mr. Nebeker is the Chairman of the
Committee and the "Audit Committee Financial Expert."
During 2004, the Audit Committee selected and recommended the
firm of Causey Demgen & Moore Inc. ("CDM") to act as Croff's auditors
for the year to the full Board of Directors. The Board of Directors and
shareholders approved the retention of CDM. The Audit Committee then
negotiated and executed an agreement between Croff and CDM.
The Audit Committee reviewed each of the quarterly Form 10-Q's
filed with the SEC during the year 2004. Members of the Committee
discussed each of the filings with management of Croff before the filings
were made. The Committee also discussed Croff's disclosure controls and
procedures with management each quarter. The Committee met and
reviewed each of the Form 10-Q's prior to filing with the SEC.
The Audit Committee members have each reviewed this 2004
Form 10-K. Members of the Committee have discussed the Form 10-K
and Financial Statements for the year 2004 with management of Croff.
The Committee has also discussed Croff's disclosure controls and
procedures with management. The Audit Committee met and discussed the
Form 10-K and Financial Statements prior to this filing. The Audit
Committee voted to recommend this 2004 Form 10-K and Financial
Statements to the Board of Directors for filing with the SEC.
A designated member of the Audit Committee has discussed the
audit and financial statements with the appropriate principal of CDM
including those matters required by SAS 61. They also discussed Croff's
disclosure controls and procedures.
The Croff Board of Directors have each received a letter from
CDM that as of February 7, 2005, CDM were independent accountants with
respect to Croff, within the meaning of the Securities Acts administered by
the SEC and the requirements of the Independence Standard Board.
ITEM 11. EXECUTIVE COMPENSATION
Remuneration
During the fiscal year ended December 31, 2003, there were no officers,
employees or directors whose total cash or other remuneration exceeded
$80,000.
Summary Compensation Table
2004 Compensation Gerald L. Jensen, President. (No other executive salaries)
Name and position:
Gerald L. Jensen, President and Chairman
2002 2003 2004
- ---------------------------------------- --------- --------- ---------
Annual Compensation
- -------------------
Salary $54,000 $54,000 $54,000
Bonus $ - $ - $ -
Other Annual Compensation $ - $ - $ -
Long Term Compensation
- ----------------------
Awards
Restricted Stock Awards $ - $ - $ -
Payouts
No. Shares Covered by Option Grant 20,000 - -
Long Term Incentive Plan Payout $ - $ - $ -
All Other Compensation $ 1,620(1) $ 1,620(1) $ 1,620(1)
(1) Company IRA Contribution
Gerald L. Jensen is employed as the President and Chairman of
Croff Enterprises, Inc. Mr. Jensen commits a substantial amount of his
time, but not all, to his duties with the Company. Directors, excluding
the President, are not paid a salary by the Company, but are paid $350
for each half-day board meeting and $500 for each full-day board
meeting. The Chairman of the Company's Audit Committee is paid
$500 per quarter and the other member of the Audit Committee is paid at
the rate of $350 per meeting.
Proposed Remuneration:
During 2005, the Company intends to compensate outside
directors at the rate of $350 for a half day meeting and $500 for a full
day meeting. The Chairman of the Company's Audit Committee will be paid
$500 per quarter and the other member of the Audit Committee will be paid
at the rate of $350 per meeting. Based on the proposed remuneration, for
the fiscal year ending December 31, 2004, no officer or director shall
receive total cash remuneration in excess of $80,000.
Options, Warrants or Rights
The Company had no outstanding stock options, warrants or
rights as of December 31, 2003 or 2004.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
The following table sets forth the beneficial ownership of
common stock and preferred B stock of the Company as of December 31,
2004, by (a) each person who owned of record, or beneficially, more
than five percent (5%) of the Company's $.10 par value common stock,
its common voting securities, and (b) each director and nominee and all
directors and officers as a group.
Shares of Percentage of Shares of Percentage
Owned Common Stock Owned Preferred
Beneficially Stock Beneficially Stock
------------ ------------- ------------ ----------
Gerald L. Jensen 246,988(1) 43.4% 253,191(1) 46.8%
3773 Cherry Creek Drive N, #1025
Denver, Colorado 80209
Edwin W. Peiker, Jr. 4,000 0.7% 4,000 0.7%
550 Ord Drive
Boulder, Colorado 80401
Dilworth A. Nebeker 2,900 0.5% 2,900 0.5%
10823 Palliser Bay Drive
Las Vegas, Nevada 89141
Richard H. Mandel, Jr. 15,100 2.7% 16,202 3.0%
3333 E. Florida #94
Denver, Colorado 80210
Julian D. Jensen 31,663 5.6% 31,663 5.9%
311 South State Street, Suite 380
Salt Lake City, Utah 84111
Directors as a Group 300,651 52.8% 307,956 57.0%
(1) Includes 132,130 shares of Common and 132,130 shares preferred B held by
Jensen Development Company which is wholly owned by Gerald L. Jensen.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company currently has an office sharing arrangement with
Jenex Petroleum Corporation, hereafter "Jenex", which is owned by the
Company's President. The Company is not a party to any lease, but
during 2003 paid Jenex for office space and all office services, including
rent, phone, office supplies, secretarial, land, and accounting. Mr. Stuart
Kroonenberg, the Chief Financial Officer of the Company, is paid by
Jenex pursuant to this arrangement, but serves as an officer of Croff.
These arrangements were entered into to reduce the Company's overhead
and are currently on a month-to-month basis. The Company's expenses
for these services were $48,000, $30,000 and $24,000 for the years
ended 2004, 2003 and 2002, respectively. Although these transactions
were not a result of "arms length" negotiations, the Company's Board of
Directors believes the transactions are reasonable.
The Company retains the legal services of Jensen, Duffin, &
Dibb, LLP. Julian Jensen, a Director of the Company, is part of this
professional firm. Legal fees paid to this law firm for the years ending
2004, 2003, and 2002 were $2,410, $2,256 and $3,109, respectively.
The Company has working interests in five Oklahoma natural
gas wells, which are operated by Jenex, a company solely owed by
Gerald Jensen, the Company's President. As part of the 1998 purchase
agreement, Jenex agreed to rebate to Croff $150 of operating fees per
well, each month, which now totals $750 per month, as long as Jenex
operated the wells and Croff retained its interest.
The Company compensated Richard H. Mandel, Jr., a member of
its Board of Directors, 1,000 and 2,000 shares of common stock during
2003 and 2004, respectively, for consulting services rendered in
connection with the Company's Yorktown Re-entry Program in south
Texas. The common shares were valued at $1.00 per share.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Audit Fees
Causey Demgen & Moore Inc. ("CDM") was recommended by the
Audit Committee of the Board and approved by the Company stockholder's
for reappointment as the registered public accounting firm
for the Company for the fiscal year ended December 31, 2004. CDM is a
member of the SEC Practice Section of the American Institute of Certified
Public Accountants. CDM have been acting as independent accountants
for the Company for fourteen years. Aggregate fees for professional
services rendered by CDM in connection with its audit of the Company's
Financial Statements as of and for the year ended December 31, 2002, and
its limited reviews of the Company's unaudited condensed quarterly
Financial Statements during 2003 totaled $8,580. Aggregate fees for
professional services rendered by CDM in connection with its audit of the
Company's Financial Statements as of and for the year ended December 31,
2003, and its limited reviews of the Company's unaudited condensed
quarterly Financial Statements during 2004 totaled $10,263. During 2003
and 2004, CDM did not perform any additional services for the Company.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements
See index to Financial Statements, financial statement schedules and
supplemental information as referenced in Part II, Item 8, and the
financial index on page F-1 hereof. These reports are attached as
exhibits and are incorporated herein.
Reports on Form 8-K
Form 8-K; August 11, 2004; Item 5
Form 8-K; November 19, 2004; Item 8
Exhibit Index
Index certifications, Financial Statements, and supplemented
information.
REGISTRANT:
CROFF ENTERPRISES, INC.
Date: March 1, 2005 By: /S/Gerald L. Jensen
---------------- ------------------------------
Gerald L. Jensen, President,
Chief Executive Officer
Date: March 1, 2005 By: /s/Stuart D. Kroonenberg
---------------- ------------------------------
Stuart D. Kroonenberg,
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, the
following persons on behalf of the Registrant and in the capacities and on the
date indicated have signed this report below.
Date: March 1, 2005 By: /S/Gerald L. Jensen
---------------- --------------------------------
Gerald L. Jensen, Chairman
Date: March 1, 2005 By: /S/Richard H. Mandel, Jr.
---------------- --------------------------------
Richard H. Mandel, Jr., Director
Date: March 1, 2005 By: /S/Edwin Peiker, Jr.
---------------- --------------------------------
Edwin Peiker, Jr., Director
Date: March 1, 2005 By: /S/Dilworth A. Nebeker
---------------- --------------------------------
Dilworth A. Nebeker, Director
Date: March 1, 2005 By: /S/Julian D. Jensen
---------------- --------------------------------
Julian D. Jensen, Director
Exhibit 31.1
CERTIFICATION PURSUANT TO
SECURITIES EXCHANGE ACT OF 1934: RULES 13a-14, 13a-15, 15d-14, and 15d-15
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Gerald L. Jensen, certify that:
1. I have reviewed this annual report on Form 10-K of Croff Enterprises, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant is made known to us,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the
registrant's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 1, 2005 By: /S/Gerald L. Jensen
---------------- ------------------------------
Gerald L. Jensen, President,
Chief Executive Officer
Exhibit 31.2
CERTIFICATION PURSUANT TO
SECURITIES EXCHANGE ACT OF 1934: RULES 13a-14, 13a-15, 15d-14, and 15d-15
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Stuart D. Kroonenberg, certify that:
1. I have reviewed this annual report on Form 10-K of Croff Enterprises, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant is made known to us,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the
registrant's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 1, 2005 By: /S/Stuart D. Kroonenberg
---------------- ------------------------------
Stuart D. Kroonenberg
Chief Financial Officer
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Croff Enterprises, Inc. (the "Company")
on Form 10-K for the period ending December 31, 2004 as filed with the
Securities and Exchange Commission on the date hereof (the "Report"), I, Gerald
L. Jensen, Chief Executive Officer of the Company, certify, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition and result of operations
of the Company.
Date: March 1, 2005 By: /S/Gerald L. Jensen
---------------- ------------------------------
Gerald L. Jensen, President,
Chief Executive Officer
Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Croff Enterprises, Inc. (the "Company")
on Form 10-K for the period ending December 31, 2004 as filed with the
Securities and Exchange Commission on the date hereof (the "Report"), I, Stuart
D. Krooneberg, Chief Financial Officer of the Company, certify, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition and result of operations
of the Company.
Date: March 1, 2005 By: /S/Stuart D. Kroonenberg
---------------- ------------------------------
Stuart D. Kroonenberg
Chief Financial Officer
CROFF ENTERPRISES, INC.
INDEX TO FINANCIAL STATEMENTS, SCHEDULES
AND SUPPLEMENTAL INFORMATION
Page Number
-----------
I. Financial Statements
Report of Registered Public Accounting Firm........................F-2
Balance Sheets as of December 31, 2003 and 2004....................F-3
Statements of Operations for the years ended December 31,
2002, 2003 and 2004................................................F-4
Statements of Stockholders' Equity for the years ended
December 31, 2002, 2003 and 2004...................................F-5
Statements of Cash Flows for the years ended December 31,
2002, 2003 and 2004................................................F-6
Notes to Financial Statements......................................F-7
II. Supplemental Information - Disclosures About Oil and
Gas Producing Activities - Unaudited..........................F-15
F-1
REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Croff Enterprises, Inc.
We have audited the balance sheets of Croff Enterprises, Inc. at
December 31, 2003 and 2004, and the related statements of
operations, stockholders' equity and cash flows for each of the three
years in the period ended December 31, 2004. These financial
statements are the responsibility of management. Our responsibility
is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Croff Enterprises,
Inc. as of December 31, 2003 and 2004, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 2004, in conformity with U.S. generally accepted accounting
principles.
Denver, Colorado
February 26, 2005 CAUSEY DEMGEN & MOORE INC.
F-2
CROFF ENTERPRISES, INC.
BALANCE SHEETS
December 31, 2003 and 2004
2003 2004
---------- ----------
ASSETS
Current assets:
Cash and cash equivalents $ 154,490 $ 257,667
Investments
Marketable equity securities, available for sale 48,470 -
Mutual funds 77,429 -
Natural gas "put" contracts, at fair value 7,660 -
Accounts receivable 80,531 109,691
---------- ----------
368,580 367,358
---------- ----------
Oil and gas properties, at cost, successful efforts method:
Proved properties 769,389 952,571
Unproved properties 216,176 266,548
---------- ----------
985,565 1,219,119
Accumulated depletion and depreciation (455,924) (497,924)
---------- ----------
529,641 721,195
---------- ----------
Total assets $ 898,221 $1,088,553
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 21,383 $ 28,410
Accrued liabilities 10,726 8,705
---------- ----------
32,109 37,115
---------- ----------
Stockholders' equity:
Class A Preferred stock, no par value
5,000,000 shares authorized, none issued - -
Class B Preferred stock, no par value; 1,000,000
shares authorized, 540,659 shares
issued and outstanding 559,295 772,929
Common stock, $.10 par value; 20,000,000 shares
authorized, 620,143 and 622,143 shares issued
and outstanding at December 31, 2003 and 2004,
respectively 62,014 62,214
Capital in excess of par value 369,761 157,927
Treasury stock, at cost, 63,083 shares
issued and outstanding (83,151) (83,151)
Accumulated other comprehensive loss (41,210) -
Retained earnings (deficit) (597) 141,519
---------- ----------
866,112 1,051,438
---------- ----------
Total liabilities and stockholders' equity $ 898,221 $1,088,553
========== ==========
See accompanying notes to the financial statements.
F-3
CROFF ENTERPRISES, INC.
STATEMENTS OF OPERATIONS
For the years ended December 31, 2002, 2003 and 2004
2002 2003 2004
---------- ---------- ----------
Revenues
Oil and natural gas sales $ 286,602 $ 437,586 $ 615,731
Loss on natural gas "put" contracts - (45,022) (7,599)
Gain (loss) on sale of marketable
equity securities 23,026 19,450 (38,166)
Other income 5,700 3,912 6,196
---------- ---------- ----------
315,328 415,926 576,162
---------- ---------- ----------
Expenses
Lease operating expense including
production taxes 77,065 130,793 192,187
Proposed drilling program - 13,780 30,825
General and administrative 83,351 102,244 112,157
Overhead expense, related party 24,000 30,000 48,000
Depletion and depreciation 32,000 35,000 42,000
---------- ---------- ----------
216,416 311,817 425,169
---------- ---------- ----------
Pretax income 98,912 104,109 150,993
Provision for income taxes - 10,000 8,877
---------- ---------- ----------
Net income 98,912 94,109 142,116
Net income applicable to
preferred B shares 73,825 88,385 213,634
---------- ---------- ----------
Net income (loss) applicable to
common shares $ 25,087 $ 5,724 $ (71,518)
========== ========== ==========
Basic and diluted net income
(loss) per common share $ .04 $ .01 $ (.13)
========== ========== ==========
See accompanying notes to the financial statements.
F-4
CROFF ENTERPRISES, INC.
STATEMENTS OF STOCKHOLDERS' EQUITY
For the years ended December 31, 2002, 2003 and 2004
Accumulated
Preferred B stock Common stock Capital in other Retained
------------------ ------------------ excess of Treasury comprehensive earnings
Shares Amount Shares Amount par value stock loss (deficit)
-------- -------- -------- -------- ---------- -------- ------------- -----------
Balance at December 31, 2001 540,659 $397,085 629,143 $ 62,914 $ 530,071 $(83,151) $ (1,150) $ (193,618)
Net unrealized loss on marketable
equity securities - - - - - - (64,055) -
Net income for the year ended
December 31, 2002 - - - - - - - 98,912
Preferred stock reallocation - 73,825 - - (73,825) - - -
-------- -------- -------- -------- ---------- -------- ------------- -----------
Balance at December 31, 2002 540,659 470,910 629,143 62,914 456,246 (83,151) (65,205) (94,706)
Net unrealized gain on marketable
equity securities - - - - - - 23,995 -
Net income for the year ended
December 31, 2003 - - - - - - - 94,109
Common stock issued for services - - 1,000 100 900 - - -
Cancellation of treasury stock - - (10,000) (1,000) 1,000 - - -
Preferred stock reallocation - 88,385 - - (88,385) - - -
-------- -------- -------- -------- ---------- -------- ------------- -----------
Balance at December 31, 2003 540,659 $559,295 620,143 $ 62,014 $ 369,761 $(83,151) $ (41,210) $ (597)
Realization of net loss on
marketable equity securities - - - - - - 41,210 -
Net income for the year ended
December 31, 2004 - - - - - - - 142,116
Common stock issued for services - - 2,000 200 1,800 - - -
Preferred stock reallocation - 213,634 - - (213,634) - - -
-------- -------- -------- -------- ---------- -------- ------------- -----------
Balance at December 31, 2004 540,659 $772,929 622,143 $ 62,214 $ 157,927 $(83,151) $ - $ 141,519
======== ======== ======== ======== ========== ======== ============= ===========
See accompanying notes to the financial statements.
F-5
CROFF ENTERPRISES, INC.
STATEMENTS OF CASH FLOWS
For the years ended December 31, 2002, 2003 and 2004
2002 2003 2004
---------- ---------- ----------
Cash flows from operating activities:
Net income $ 98,912 $ 94,109 $ 142,116
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depletion and depreciation 32,000 35,000 42,000
Realized (gain) loss on marketable
equity securities (23,026) (19,450) 38,116
Loss on natural gas "put" contracts - 45,022 7,599
Other items, net - 1,000 2,000
Changes in operating assets and
liabilities:
Accounts receivable 278 (31,583) (29,160)
Accrued interest on notes receivable (1,852) 600 -
Accounts payable (2,087) 5,902 7,027
Accrued liabilities (4,148) 9,403 (2,021)
---------- ---------- ----------
Net cash provided by operating
activities 100,077 140,003 207,727
---------- ---------- ----------
Cash flows from investing activities:
Purchase of natural gas "put" contracts - (58,041) -
Proceeds from natural gas "put" contracts - 5,359 61
Purchase of investments (286,669) (77,429) -
Proceeds from sale of investments 188,700 56,515 128,943
Payments from notes receivable 8,159 9,318 -
Net participation fees received - - 77,500
Additions to oil and gas properties (62,664) (247,708) (311,054)
---------- ---------- ----------
Net cash used in investing activities (152,474) (311,986) (104,550)
---------- ---------- ----------
Cash flows from financing activities:
Payments on notes receivable
from directors 30,000 10,000 -
---------- ---------- ----------
Net cash provided by
financing activities 30,000 10,000 -
---------- ---------- ----------
Net increase (decrease) in cash and
cash equivalents (22,397) (161,983) 103,177
Cash and cash equivalents
at beginning of year 338,870 316,473 154,490
---------- ---------- ----------
Cash and cash equivalents
at end of year $ 316,473 $ 154,490 $ 257,667
========== ========== ==========
Supplemental disclosure of non-cash investing and financing activities:
During the years ended December 31, 2002, and 2003, the
Company had unrealized gains (losses) on available for sale securities in
the amount of $(64,055) and $23,995 respectively. During the years ended
December 31, 2003, and 2004, the Company issued 1,000 and 2,000 shares
of its common stock to a Director for services rendered valued at $1,000
and $2,000 respectively.
See accompanying notes to the financial statements.
F-6
CROFF ENTERPRISES, INC.
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2002, 2003 and 2004
1. ORGANIZATIONS AND NATURE OF BUSINESS
Croff Enterprises, Inc. (the Company) is engaged in the business of oil
and gas exploration and production, primarily through ownership of perpetual
mineral interests and acquisition of producing oil and gas leases. The
Company's principal activity is oil and natural gas production from
non-operated properties. The Company also acquires, owns, and sells,
producing and non-producing leases and perpetual mineral interests in Alabama,
Colorado, Michigan, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah,
and Wyoming. Over the past ten years, the Company's primary source of revenue
has been oil and gas production from leases and producing mineral interests.
Croff participates as a working interest owner in approximately 50 wells.
Croff holds small royalty interests in approximately 200 wells.
The Company was incorporated in Utah in 1907 as Croff Mining Company.
The Company changed its name to Croff Oil Company in 1952, and in 1996 changed
its name to Croff Enterprises, Inc. The Company, however, continues to operate
its oil and gas properties as Croff Oil Company.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Producing activities
The Company follows the "successful efforts" method of
accounting for its oil and gas properties. Under this method, all
property acquisition costs and costs of exploratory and development
wells are capitalized when incurred, pending determination of
whether the well has proven reserves. If an exploratory well does not
result in reserves, the capitalized costs of drilling the well, net of any
salvage, are charged to expense. The costs of development wells are
capitalized, whether the well is productive or nonproductive.
The Company re-entered the Helen Gips #1 well in DeWitt County, Texas, and
re-completed the wellbore to the Wilcox formation during 2004. The Helen
Gips #1 well currently, has been perforated, fraced, and completion efforts are
still in process. Under the successful efforts method of accounting the Company
has capitalized $65,213 as of December 31, 2004, for costs incurred on this
unevaluated exploratory well. The capitalized costs associated with this
unevaluated exploratory well have been excluded from depletion and depreciation
during the 2004.
Maintenance and repairs are charged to expense; betterments
of property are capitalized and depreciated as described below.
Lease bonuses
The Company defers bonuses received from leasing minerals
in which unrecovered costs remain by recording the bonuses as a
reduction of the unrecovered costs. Bonuses received from leasing
mineral interests previously expensed are taken into income. For
federal income tax purposes, lease bonuses are regarded as advance
royalties (ordinary income). The Company received lease bonuses
totaling $150, $1,101 and $3,743, for the years ended December 31,
2002, 2003, and 2004, respectively, which were included in other
income.
F-7
CROFF ENTERPRISES, INC.
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2002, 2003 and 2004
Depreciation and depletion
The Company provides for depreciation and depletion of
its investment in producing oil and gas properties on the unit-of-
production method, based upon estimates of recoverable oil and
gas reserves from the property.
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") 123R,
"Share-Based Payment." This revised standard addresses the accounting for
share- based payment transactions in which a company receives employee
services in exchange for either equity instruments of the company or
liabilities that are based on the fair value of the company's equity
instruments or that may be settled by the issuance of such equity
instruments. Under the new standard, companies will no longer be able to
account for share-based compensation transactions using the intrinsic
method in accordance with APB 25. Instead, companies will be required to
account for such transactions using a fair-value method and recognize the
expense in the statements of operations. SFAS 123R will be effective for
all interim or annual periods beginning after June 15, 2005. The adoption
of this announcement in July 2005, is not expected to have a material
impact on the Company's financial condition or results of operations as
the Company currently receive employee services in exchange for either
equity instruments of the company or liabilities that are based on the
fair value of the company's equity instruments or that may be settled by
the issuance of such equity instruments.
In December 2004, the FASB issued SFAS No. 153, "Exchanges of
Nonmonetary Assets - an amendment of APB Opinion No. 29". This standard
requires exchanges of productive assets to be accounted for at fair value,
rather than at carryover basis, unless (1) neither the asset received nor
the asset surrendered has a fair value that is determinable within
reasonable limits or (2) the transactions lack commercial substance. The
Statement is effective for non-monetary asset exchanges occurring in fiscal
periods beginning after June 15, 2005. The Company has not entered into
these types of nonmonetary asset exchanges during the last five years.
Accordingly, the adoption of this pronouncement is not expected to have a
material impact on the Company's financial condition or results of
operations.
Revenue recognition
Oil and gas revenues are accounted for using the sales
method. Under this method, revenue is recognized based on the
cash received rather than the Company's proportionate share of the
oil and gas produced. Oil and gas imbalances and related value at
December 31, 2002, 2003 and 2004 were insignificant.
F-8
CROFF ENTERPRISES, INC.
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2002, 2003 and 2004
Risks and uncertainties
Historically, oil and gas prices have experienced
significant fluctuations and have been particularly volatile in recent
years. Price fluctuations can result from variations in weather,
levels of regional or national production and demand, availability
of transportation capacity to other regions of the country and
various other factors. Increases or decreases in prices received
could have a significant impact on future results.
Comprehensive Income
The Company follows the provisions of SFAS No. 130,
"Reporting Comprehensive Income," which establishes standards
for reporting comprehensive income. In addition to net income,
comprehensive income includes all changes in equity during a
period, except those resulting from investments and distributions to
the owners of the Company. The components of other
comprehensive income net of the related tax effects for the twelve
months ended December 31, 2002 and 2003 totaled $(64,055) and
$23,995, respectively, and were related to net unrealized gains
(losses) on the Company's marketable equity securities, which
were available for sale. The Company liquidated its marketable
equity securities and recognized a net realized loss of $38,166 for
the year ended December 31, 2004.
Fair value of financial instruments
The carrying amounts of financial instruments including
cash and cash equivalents, marketable equity securities, accounts
receivable, notes receivable, accounts payable and accrued
liabilities approximate fair value as of December 31, 2003 and
2004.
Concentrations of credit risk
Financial instruments, which potentially subject the
Company to concentrations of credit risk, consist principally of
cash, cash equivalents and accounts receivable. The Company
places its cash with high quality financial institutions. At times
during the year, the balance at any one financial institution may
exceed FDIC limits.
Derivative instruments and hedging activities
On March 21, 2003, the Company purchased a series of put
contracts for 10,000 MMBTU's per month of natural gas
beginning in June 2003 and ending May 2004 at the strike price of
$4.75. The Company paid $58,044 for these twelve contracts. The
Company realized a loss during 2003 and 2004 of $45,022 and
$7,599, respectively, related to its purchase of these natural gas
"put" contracts. During the years ended December 31, 2002 and
2004, the Company did not enter into commodity derivative
contracts or fixed-price physical contracts to manage its exposure
to oil and gas price volatility.
F-9
CROFF ENTERPRISES, INC.
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2002, 2003 and 2004
Stock options and warrants
The Company has adopted the disclosure-only provisions
of Statement of Financial Accounting Standards No. 123
"Accounting for Stock-Based Compensation" related to its stock
options and warrants. Since December 2001, the Company has
had no outstanding stock options or warrants.
Reclassifications
Certain reclassifications have been made to amounts
reported in previous years to conform to the 2004 presentation.
Cash equivalents
For purposes of the statement of cash flows, the Company
considers all highly liquid debt instruments purchased with
maturity of three months or less to be cash equivalents.
Marketable equity securities
The Company has designated its marketable equity
securities as "securities available for sale" pursuant to Statement of
Financial Accounting Standards No. 115, Accounting for Certain
Investments in Debt and Equity Securities. The net unrealized
gains (losses) related to these securities before taxes for December
31, 2002, 2003, and 2004 was $(65,205), $23,995, and $0
respectively and is reflected as accumulated other comprehensive
loss. During 2002, 2003 and 2004, a portion of the available-for-
sale securities were sold for $188,700, $56,515, and $128,943
respectively, resulting in a net gain (loss) before taxes of $23,026,
$19,450, $(38,166) respectively, based upon historical cost.
Accounts receivable
The Company considers accounts receivable to be fully
collectible; accordingly, no allowance for doubtful accounts is
required. If amounts become un-collectible, they will be charged to
operations when that determination is made.
Income taxes
The provision for income taxes is based on earnings
reported in the financial statements. Deferred income taxes are
provided using a liability approach based upon enacted tax laws
and rates applicable to the periods in which the taxes become
payable.
F-10
CROFF ENTERPRISES, INC.
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2002, 2003 and 2004
Net income per common share
In accordance with the provisions of SFAS No. 128,
"Earnings per Share," basic income per common share amounts
were computed by dividing net income after deduction of the net
income attributable to the preferred B shares by the weighted
average number of common shares outstanding during the period.
Diluted income per common share assumes the conversion of all
securities that are exercisable or convertible into either preferred B
or common shares that would dilute the basic earnings per
common share during the period.
Use of estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of 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.
3. RELATED PARTY TRANSACTIONS
The Company retains the services of a law firm in which a
partner of the firm is a director of the Company. Legal fees paid to
this firm for the years ended December 31, 2002, 2003 and 2004
amounted to $3,109, $2,256 and $2,410, respectively.
The Company currently has an office sharing arrangement
with Jenex Petroleum Corporation, hereafter "Jenex", which is
owned by the Company's President. The Company is not a party
to any lease, but paid Jenex for office space and all office services,
including rent, phone, office supplies, secretarial, land, and
accounting. The Company's expenses for these services were
$24,000, $30,000, and $48,000 for the years ended 2002, 2003 and
2004, respectively. Although these transactions were not a result
of "arms length" negotiations, the Company's Board of Directors
believes the transactions are reasonable.
The Company has working interests in five Oklahoma
natural gas wells, which are operated by Jenex, a company solely
owed by Gerald Jensen, the Company's President. As part of the
1998 purchase agreement, Jenex agreed to rebate to Croff $150 of
operating fees per well, each month, which now totals $750 per
month, as long as Jenex operated the wells and Croff retained its
interest. During the years ending December 31, 2002, 2003 and
2004, $10,050, $9,000, and $9,000 respectively, have been offset
against lease operating expense, in this manner. Total trade
accounts receivable from Jenex as of December 31, 2003 and
2004, totaled $26,490 and $21,750, respectively.
F-11
CROFF ENTERPRISES, INC.
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2002, 2003 and 2004
The Company compensated Richard H. Mandel, Jr., a
member of its Board of Directors, 1,000 and 2,000 shares of
common stock during 2003 and 2004, respectively, for consulting
services rendered in connection with the Company's Yorktown Re-
entry Program in south Texas. The common shares were valued at
$1.00 per share
4. STOCKHOLDERS' EQUITY
During 2001, the Board determined that the cash of the
Company, which had been building during a period of high oil
prices, should be formally allocated between the common stock
and the preferred B stock. The Board decided to allocate $250,000
cash to the common stock and the balance of cash remaining with
the preferred B stock. The Board then determined that future oil
and gas cash flow from the preferred B assets would be
accumulated for preferred B shareholders. The Company
established separate investment accounts for the preferred B and
common stock investments.
The Company has no outstanding stock options, warrants
or rights as of December 31, 2003 or 2004.
The Class A Preferred stock was authorized for possible
future capitalization and funding purposes of the Company and has
not yet been designated as voting or non-voting. Presently, there
are no plans or intentions to issue these shares.
In 1996, the Company created a class of preferred B stock
to which the perpetual mineral interests and other oil and gas assets
were pledged. Thus, the preferred B stock represents the
current oil and gas assets of the Company, exclusive of the 2004
Edwards-Wilcox Natural Gas Development Program, and all other
assets are represented by the common stock. Each common
shareholder received an equal number of preferred B shares, one
for one, at the time of this restructuring of the capital of the
Company. The Class B Preferred stock has no par value and
limited voting privileges. The Class B Preferred stockholders are
entitled exclusively to all dividends, distributions, and other
income, which are based directly, or indirectly on its oil and
natural gas assets of the Company. In addition, in the event of
liquidation, distribution or sale of the Company, the Class B
Preferred stockholders have an exclusive preference to the net
asset value of the natural gas and oil assets over all other classes of
common and preferred stockholders.
The Class B Preferred shares have an extremely limited
market, but are traded from time to time through a clearinghouse
held by the Company. The Company established a bid and ask
format, whereby any shareholder could submit a bid or ask price
for each Class B Preferred share. The Company is acting as its
own transfer agent, with respect to these Class B Preferred shares
only.
F-12
CROFF ENTERPRISES, INC.
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2002, 2003 and 2004
5. INCOME TAXES
At December 31, 2004, the Company had capital loss carry-forwards
of approximately $60,000. In addition, the Company has a depletion
carryover at December 31, 2004, of approximately $3,000, which has
no expiration date.
The Company did not record an income tax provision for
the year ended December 31, 2002 due to the utilization of
various tax loss carry forwards and general business credits. The
recognized tax benefit of the utilized carry forward was
approximately $40,000 for the year ended December 31, 2002.
The difference in financial statement and tax return loss carryovers
is principally the difference in the timing of deducting intangible
drilling costs as well as from expired and unused tax net operating
losses.
As of December 31, 2003 and 2004, total deferred tax
assets; liabilities and valuation allowance are as follows:
2003 2004
-------- --------
Deferred tax assets resulting
from loss carry forwards $ 135,000 $ -
Valuation allowance (135,000) ( -)
--------- ---------
$ - $ -
========= =========
6. BASIC AND DILUTED INCOME (LOSS) PER COMMON SHARE
Basic income (loss) per common share information is based
on the weighted average number of shares of common stock
outstanding during each year, approximately 566,100, 566,100 and
568,400 shares in 2002, 2003 and 2004 respectively.
F-13
CROFF ENTERPRISES, INC.
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2002, 2003 and 2004
7. MAJOR CUSTOMERS
Customers which accounted for over 10% of oil and natural gas revenues
were as follows for the years ended December 31, 2002, 2003 and 2004:
2002 2003 2004
------ ------ ------
Burlington Resources Oil and Gas Company 13.2% 10.0% *
El Paso Production 10.6% 14.6% *
Energetics, LTD. * 10.0% *
Jenex Petroleum Corp., a related party 24.3% 17.2% 18.1%
Merit Energy * * 14.4%
Sunoco, Inc.** * * 11.9%
* less than 10%
** Replaced Energetics as the purchaser on the
Scheffler and Sunbelt oil wells in Michigan
Management believes that the loss of any individual purchaser would not
have a long-term material adverse impact on the financial position or results
of operations of the Company.
F-14
CROFF ENTERPRISES, INC.
SUPPLEMENTAL INFORMATION - DISCLOSURES
ABOUT OIL AND GAS PRODUCING ACTIVITIES - UNAUDITED
In November, 1982, the Financial Accounting Standards Board
issued and the SEC adopted Statement of Financial Accounting Standards
No. 69 (SFAS 69) "Disclosures about Oil and Gas Producing Activities".
SFAS 69 requires that certain disclosures be made as supplementary
information by oil and gas producers whose financial statements are filed
with the SEC. The Company bases these disclosures upon estimates of
proved reserves and related valuations. Independent petroleum
engineering firms compiled oil and gas reserve and future revenues as of
December 31, 2002, 2003 and 2004 for the Company's most significant
wells. Management completed the 2002, 2003, and 2004 reserve reports
from these studies.
The standardized measure of discounted future net cash flows relating to
proved reserves as computed under SFAS 69 guidelines may not necessarily
represent the fair value of the Company's oil and gas properties in the market
place. Other factors, such as changing prices and costs and the likelihood of
future recoveries differing from current estimates, may have significant effects
upon the amount of recoverable reserves and their present value.
The standardized measure does not include any "probable" and "possible"
reserves, which may exist and may become available through additional drilling
activity.
The standardized measure of discounted future net cash flows is developed
as follows:
1. Estimates are made of quantities of proved reserves and the future periods
during which they are expected to be produced based on year-end economic
conditions.
2. The estimated future production of proved reserves is priced on the basis of
year-end prices except that future prices of gas are increased for fixed and
determinable escalation provisions in contracts (if any).
3. The resulting future gross revenue streams are reduced by estimated future
costs to develop and produce the proved reserves, based on year-end cost and
timing estimates.
4. A provision is made for income taxes based upon year-end statutory rates.
Consideration is made for the tax basis of the property and permanent
differences and tax credits relating to proved reserves. The tax computation
is based upon future net cash inflow of oil and gas production and does not
contemplate a tax effect for interest income and expense or general and
administrative costs.
5. The resulting future net revenue streams are reduced to present value amounts
by applying a 10% discount factor.
F-15
CROFF ENTERPRISES, INC.
SUPPLEMENTAL INFORMATION - DISCLOSURES
ABOUT OIL AND GAS PRODUCING ACTIVITIES - UNAUDITED
Changes in the standardized measure of discounted future net cash flows are
calculated as follows:
1. Acquisition of proved reserves is based upon the standardized measure at the
acquisition date before giving effect to related income taxes.
2. Sales and transfers of oil and gas produced, net of production costs, are
based upon actual sales of products, less associated lifting costs during the
period.
3. Net changes in price and production costs are based upon changes in prices at
the beginning and end of the period and beginning quantities.
4. Extensions and discoveries are calculated based upon the standardized measure
before giving effect to income taxes.
5. Purchase of reserves are calculations based on increases from the Company's
acquisition activities.
6. Revisions of previous quantity estimates are based upon quantity changes and
end of period prices.
7. The accretion of discount represents the anticipated amortization of the
beginning of the period discounted future net cash flows.
8. Net change in income taxes primarily represents the tax effect related to all
other changes described above and tax rate changes during the period.
All of the Company's oil and gas producing activities are in the United
States.
OIL AND GAS PRICES
During the year ended December 31, 2004, crude oil and natural
gas prices remained highly volatile. The average sale price of oil per barrel
in 2004 for the Company was $38.81, compared to $28.32 in 2003. The
average sale price of natural gas per Mcf in 2004 for the Company was
$4.87 per Mcf, compared to $4.09 per Mcf in 2003. The ultimate amount
and duration of oil and gas price fluctuations and their effect on the
recoverability of the carrying value of oil and gas properties and future
operations is not determinable by management at this time.
F-16
CROFF ENTERPRISES, INC.
SUPPLEMENTAL INFORMATION - DISCLOSURES
ABOUT OIL AND GAS PRODUCING ACTIVITIES - UNAUDITED
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
The results of operations for oil and gas producing activities, excluding
capital expenditures, impairment charges, corporate overhead and interest
expense, are as follows for the years ended December 31, 2002, 2003 and 2004:
2002 2003 2004
-------- -------- --------
Revenues
Oil and natural gas sales $286,602 $437,586 $615,731
Loss on natural gas "put" contracts - (45,022) (7,599)
-------- -------- --------
286,602 392,564 608,132
Lease operating costs 61,238 100,563 148,844
Production taxes 15,827 30,230 43,343
Depletion and depreciation 32,000 35,000 42,000
Income tax expense - 10,000 8,877
-------- -------- --------
109,065 175,793 243,064
-------- -------- --------
Results of operations from producing
Activities (excluding capital
expenditures, impairment charges
corporate overhead, and interest
expense) $177,537 $216,771 $365,068
======== ======== ========
F-17
CROFF ENTERPRISES, INC.
SUPPLEMENTAL INFORMATION - DISCLOSURES
ABOUT OIL AND GAS PRODUCING ACTIVITIES - UNAUDITED
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS AND CHANGES THEREIN
RELATING TO PROVED OIL AND GAS RESERVES
Year ended December 31,
-----------------------
2002 2003 2004
---------- ---------- ----------
Future cash inflows $3,019,000 $4,655,000 $5,310,000
Future production and development costs (1,075,000) (2,134,000) (2,331,000)
---------- ---------- ----------
1,944,000 2,521,000 2,979,000
Future income tax expense (274,000) (444,000) (521,000)
---------- ---------- ----------
Future net cash flows 1,670,000 2,077,000 2,458,000
10% annual discount for
estimated timing of cash flows (651,000) (820,000) (875,000)
---------- ---------- ----------
Standardized measure of
discounted future net
cash flows $1,019,000 $1,257,000 $1,583,000
========== ========== ==========
The following are the principal sources of
change in the standardized measure of
discounted future net cash flows:
Beginning balance $ 635,000 $1,019,000 $1,257,000
Evaluation of proved undeveloped
reserves, net of future production
and development costs 8,000 (9,000) -
Purchase of proved reserves 200,000 450,000 7,000
Sales and transfer of oil and gas
produced, net of production costs (210,000) (307,000) (405,000)
Net increase (decrease) in prices
and costs 871,000 385,000 1,022,000
Extensions and discoveries 12,000 - -
Revisions of previous quantity estimates 268,000 58,000 (166,000)
Accretion of discount (701,000) (169,000) (55,000)
Net change in income taxes (64,000) (170,000) (77,000)
Other - - -
---------- ---------- ----------
Ending balance $1,019,000 $1,257,000 $1,583,000
========== ========== ==========
F-18
CROFF ENTERPRISES, INC.
SUPPLEMENTAL INFORMATION - DISCLOSURES
ABOUT OIL AND GAS PRODUCING ACTIVITIES - UNAUDITED
PROVED OIL AND GAS RESERVE QUANTITIES
(All within the United States)
Oil Gas
reserves reserves
(bbls) (mcf)
-------- --------
Balance at December 31, 2001 35,143 397,466
Revisions of previous estimates 14,342 (2,352)
Extensions, discoveries and other additions 19,989 119,932
Production (6,143) (57,526)
-------- --------
Balance at December 31, 2002 63,331 457,520
Revisions of previous estimates (5,601) 35,359
Extensions, discoveries and other additions 34,036 91,496
Production (7,656) (52,998)
-------- --------
Balance at December 31, 2003 84,110 531,377
Revisions of previous estimates 4,119 (66,834)
Extensions, discoveries and other additions 250 2,500
Production (8,011) (59,959)
-------- --------
Balance at December 31, 2003 80,468 407,084
======== ========
Proved developed reserves
December 31, 2002 54,411 448,028
December 31, 2003 75,904 477,267
December 31, 2004 72,262 352,974
Costs incurred in oil and gas producing activities for the years ended
December 31, 2002, 2003, and 2004 are as follows:
2002 2003 2004
-------- -------- --------
Property acquisition, exploration and
development costs capitalized $ 62,664 $247,708 $311,054
Impairment of property - - -
Production costs 77,065 130,793 192,187
Depletion and depreciation 32,000 35,000 42,000
F-19