RESERVE PETROLEUM CO - Annual Report: 2009 (Form 10-K)
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
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þ
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ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For the
fiscal year ended December 31, 2009
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¨
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TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF
1934
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Commission
File number 0-8157
THE
RESERVE PETROLEUM COMPANY
(Exact
Name of Registrant As Specified In Its Charter)
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DELAWARE
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73-0237060
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(State
or Other Jurisdiction of Incorporation or Organization)
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(I.R.S.
Employer Identification No.)
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6801
N. BROADWAY, SUITE 300
OKLAHOMA
CITY, OKLAHOMA 73116-9092
(405)
848-7551
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(Address
and telephone number, including area code, of registrant’s principal
executive offices)
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Securities
registered under Section 12(b) of the Exchange Act: NONE
Securities
registered under Section 12(g) of the Exchange Act:
COMMON
STOCK ($0.50 PAR VALUE)
(Title of
Class)
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.Yeso No þ
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Exchange Act.
Yes o No þ
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.YesþNoo
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files). Yes o No o
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. þ
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act (Check one):
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Large
accelerated filer o
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting company þ
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange
Act). Yes o No þ
The
aggregate market value of the voting and non-voting common stock of the
registrant held by non-affiliates of the registrant was $32,633,776, as computed
by reference to the last reported sale which was on March 25, 2010.
As of
March 26, 2010, there were 161,665.64 shares of the registrant’s common stock
outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the definitive proxy statement (the “Proxy Statement”) relating to the
registrant’s Annual Meeting of Shareholders to be held on May 18, 2010, which
will be filed within 120 days of the end of the registrant’s fiscal year ended
December 31, 2009, are incorporated by reference into Part III of this Form 10-K
to the extent described therein.
TABLE OF CONTENTS
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Page
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3
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PART
I
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Item
1.
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3
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Item
1A.
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6
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Item
1B.
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6
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Item
2.
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7
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Item
3.
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8
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Item
4.
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8
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PART
II
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Item
5.
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9
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Item
6.
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10
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Item
7.
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10
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Item
7A.
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24
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Item
8.
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24
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Item
9.
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48
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Item
9A.(T).
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48
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Item
9B.
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49
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PART
III
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Item
10.
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49
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Item
11.
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49
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Item
12.
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49
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Item
13.
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50
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Item
14.
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50
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PART
IV
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Item
15.
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50
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Forward-Looking Statements
This
Report on Form 10-K contains forward-looking statements. Actual events and/or
future results of operations may differ materially from those contemplated by
such forward-looking statements. See Item 7, “Management’s Discussion and
Analysis of Financial Condition and Results of Operations” for a summation of
some of the risks and uncertainties inherent in forward-looking statements.
Readers should consider the risks and uncertainties described in connection with
any forward-looking statements that may be made in this Form 10-K. Readers
should carefully review this Form 10-K in its entirety, including but not
limited to the Company's financial statements and the notes thereto and the
risks and uncertainties described herein. Forward-looking statements contained
in this Form 10-K speak only as of the date of this Form 10-K. The Company does
not undertake to update its forward-looking statements.
PART I
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ITEM
1.
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BUSINESS
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Overview
The
Reserve Petroleum Company (the “Company”) is engaged principally in managing its
owned mineral properties and the exploration for and the development of oil and
natural gas properties. Other business segments are not significant factors in
the Company’s operations. The Company is a corporation organized under the laws
of the State of Delaware in 1931.
Oil
and Natural Gas Properties
For a
summary of certain data relating to the Company’s oil and gas properties
including production, undeveloped acreage, producing and dry wells drilled and
recent activity, see Item 2, “Properties.” For a discussion and analysis of
current and prior years’ revenue and related costs of oil and gas operations and
a discussion of liquidity and capital resource requirements, see Item 7,
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations.”
Owned
Mineral Property Management
The
Company owns non-producing mineral interests in 259,314 gross acres equivalent
to 89,440 net acres. These mineral interests are located in nine different
states in the north and south central United States. A total of 63,974 net acres
are located in the States of Oklahoma, South Dakota and Texas, the areas of
concentration for the Company in its present exploration and development
programs.
The
Company has several options relating to the exploration and/or development of
these owned mineral interests. Management continually reviews various industry
reports and other sources for activity (leasing, drilling, significant
discoveries, etc.) in areas where the Company has mineral ownership. Based on
its analysis of any activity and assessment of the potential risk relative to
the particular area, management may negotiate a lease or farmout agreement and
accept a royalty interest, or it may choose to participate as a working interest
owner and pay its proportionate share of any exploration or development drilling
costs.
A
substantial amount of the Company’s oil and gas revenue has resulted from its
owned mineral property management. In 2009, $3,890,699 (44%) of oil and gas
sales was from royalty interests versus $10,406,544 (53%) in 2008. As a result
of its mineral ownership, the Company had royalty interests in 28 gross (.71
net) wells, which were drilled and completed as producing wells in 2009. This
resulted in an average royalty interest of about 2.5% for these 28 new wells.
The Company has very little control over the timing or extent of the operations
conducted on its royalty interest properties. See the following paragraphs for a
discussion of mineral interests in which the Company chooses to participate as a
working interest owner.
Development
Program
Development
drilling by the Company is usually initiated in one of three ways. The Company
may participate as a working interest owner with a third party operator in the
development of non-producing mineral interests which it owns; along with a joint
interest operator, it may participate in drilling additional wells on its
producing leaseholds; or if its exploration program discussed below results in a
successful exploratory well, it may participate in the drilling of additional
wells on the exploratory prospect. In 2009, the Company participated in the
drilling of seventeen development wells with fourteen wells (1.71 net) completed
as producers and three wells (.497 net) in progress. The seven wells (1.14 net)
that were in progress at the end of 2008 were all completed as producing wells
in 2009.
Exploration
Program
The
Company’s exploration program is normally conducted by purchasing interests in
prospects developed by independent third parties; participating in third party
exploration of Company-owned, non-producing minerals; developing its own
exploratory prospects; or a combination of the above.
The
Company normally acquires interests in exploratory prospects from someone in the
industry with whom management has conducted business in the past and/or if
management has confidence in the quality of the geological and geophysical
information presented for evaluation, by Company personnel. If evaluation
indicates the prospect is within the Company’s risk limits, the Company may
negotiate to acquire an interest in the prospect and participate in a
non-operating capacity.
The
Company develops exploratory drilling prospects by identification of an area of
interest, development of geological and geophysical information and purchase of
leaseholds in the area. The Company may then attempt to sell an interest in the
prospect to one or more companies in the petroleum industry with one of the
purchasing companies functioning as operator. In 2009, the Company participated
in the drilling of sixteen exploration wells with seven wells (1.13 net)
completed as producers, six wells (.78 net) completed as dry holes and three
wells (.28 net) in progress. Of the nine wells (.987 net) still drilling at the
end of 2008, six wells (.75 net) were completed as producing wells in 2009 and
three wells (.238 net) were dry holes.
For a
summation of exploratory and development wells drilled in 2009 or planned for in
2010, see Item 7, “Management’s Discussion and Analysis of Financial Condition
and Results of Operations,” subheading “Update of Oil and Gas Exploration and
Development Activity from December 31, 2008.”
Customers
In 2009,
the Company had four customers whose total purchases were greater than 10% of
revenues from oil and gas sales. Redland Resources, Inc. purchases were
$1,929,743, or 22% of total oil and gas sales. ConocoPhillips Company purchases
were $1,161,915, or 13% of total oil and gas sales. Luff Exploration Company
purchases were $1,065,765, or 12% of total oil and gas sales. XTO Energy, Inc.
purchases were $883,673, or 10% of total oil and gas sales. The Company sells
most of its oil and gas under short-term sales contracts that are based on the
spot market price. A minor amount of oil and gas sales are made under fixed
price contracts having terms of more than one year.
Competition
The oil
and gas industry is highly competitive in all of its phases. There are numerous
circumstances within the industry and related market place that are out of the
Company’s control such as cost and availability of alternative fuels, the level
of consumer demand, the extent of other domestic production of oil and gas, the
price and extent of importation of foreign oil and gas, the cost of and
proximity of pipelines and other transportation facilities, the cost and
availability of drilling rigs, regulation by state and Federal authorities and
the cost of complying with applicable environmental regulations.
The
Company is a very minor factor in the industry and must compete with other
persons and companies having far greater financial and other resources. The
Company’s ability to participate in and/or develop viable prospects and secure
the financial participation of other persons or companies in exploratory
drilling on these prospects is limited.
Regulation
The
Company’s operations are affected in varying degrees by political developments
and Federal and state laws and regulations. Although released from Federal price
controls, interstate sales of natural gas are subject to regulation by the
Federal Energy Regulatory Commission (FERC). Oil and gas operations are affected
by environmental laws and other laws relating to the petroleum industry, and
both are affected by constantly changing administrative regulations. Rates of
production of oil and gas have, for many years, been subject to a variety of
conservation laws and regulations, and the petroleum industry is frequently
affected by changes in the Federal tax laws.
Generally,
the respective state regulatory agencies supervise various aspects of oil and
gas operations within the state and transportation of oil and gas sold
intrastate.
Environmental
Protection and Climate Change
The
operation of the various producing properties, in which the Company has an
interest, is subject to Federal, state and local provisions regulating discharge
of materials into the environment, the storage of oil and gas products and the
contamination of subsurface formations. The Company’s lease operations and
exploratory activity have been and will continue to be affected by existing
regulations in future periods. However, the known effect to date has not been
material as to capital expenditures, earnings or industry competitive position.
Environmental compliance expenditures produce no increase in productive capacity
or revenue and require more of management’s time and attention, a cost which
cannot be estimated with any assurance of certainty.
In 2009,
the EPA officially published its findings that greenhouse
gas emissions present an endangerment to human health and the environment.
According to the EPA, these emissions are contributing to global warming and
climate change. These findings will allow the EPA to adopt and implement
regulations to restrict these emissions under existing provisions of the Federal
Clean Air Act. In addition, the United States Congress has been considering
legislation that would establish an economy-wide cap-and-trade program to control or
reduce U.S. emissions of greenhouse gases.
The
Company may be, directly and indirectly, subject to the effects of climate
change and may, directly or indirectly, be affected by government laws and
regulations related to climate change. The Company cannot predict with any
degree of certainty what effect, if any, climate change and government laws and
regulations related to climate change will have on the Company and its business,
whether directly or indirectly. While we believe that it is difficult to assess
the timing and effect of climate change and pending legislation and regulation
related to climate change on the Company's business, we believe that climate
change and government laws and regulations related to climate change may affect,
directly or indirectly, (i) the costs associated with drilling and production
operations in which we participate, (ii) the demand for oil and natural gas,
(iii) insurance premiums, deductibles and the availability of coverage and (iv)
the cost of utilities paid by the Company. In addition, climate change may
increase the likelihood of property damage and the disruption of operations of
wells in which we participate. As a result, our financial condition could be
negatively impacted, but we are unable to determine at this time whether that
impact would be material.
Other
Business
See Item
7, “Management’s Discussion and Analysis of Financial Condition and Results of
Operations,” subheading “Equity Investments” and Item 8, Notes 2 and 7 to the
accompanying financial statements for a discussion of other business including
guarantees.
Employees
At
December 31, 2009, the Company had eight employees, including officers. See the
Proxy Statement for additional information. During 2009, all the Company’s
employees devoted a portion of their time to duties with affiliated companies,
and the Company was reimbursed for the affiliates’ share of compensation
directly from those companies. See Item 7, “Management’s Discussion and Analysis
of Financial Condition and Results of Operations,” subheading “Certain
Relationships and Related Transactions” and Item 8, Note 12 to the accompanying
financial statements for additional information.
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ITEM 1A.
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RISK
FACTORS
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Smaller
reporting companies are not required to provide the information required by this
Item.
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ITEM 1B.
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UNRESOLVED
STAFF COMMENTS
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Smaller
reporting companies are not required to provide the information required by this
Item.
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ITEM 2.
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PROPERTIES
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The
Company’s principal properties are oil and natural gas properties. The Company
has interests in approximately 610 producing properties with one-third of them
being working interest properties, and the remaining two-thirds being royalty
interest properties. About 87% of these properties are located in Oklahoma and
Texas and account for approximately 78.8% of the Company’s annual oil and gas
sales. About 7% of the properties are located in Kansas and South Dakota and
account for approximately 20.6% of the Company’s annual oil and gas sales. The
remaining 6% of these properties are located in Colorado, Arkansas and Montana
and account for less than 1% of the Company’s annual oil and gas sales. No
individual property provides more than 7% of the Company’s annual oil and gas
sales. See discussion of revenues from Robertson County, Texas, royalty interest
properties in Item 7, “Operating Revenues” for additional information about
significant properties.
OIL
AND NATURAL GAS OPERATIONS
Oil
and Gas Reserves
Reference
is made to the Unaudited Supplemental Financial Information beginning on Page 43
for working interest reserve quantity information.
Since
January 1, 2009, the Company has not filed any reports with any Federal
authority or agency which included estimates of total proved net oil or gas
reserves, except for its 2008 annual report on Form 10-K and Federal income tax
return for the year ended December 31, 2008. Those reserve estimates were
identical.
Production
The
average sales price of oil and gas produced and, for the Company’s working
interests, the average production cost (lifting cost) per equivalent thousand
cubic feet (MCF) of gas production is presented in the table below for the years
ended December 31, 2009, 2008 and 2007. Equivalent MCF was developed using
approximate relative energy content.
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Royalties
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Working Interests
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Sales Price
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Sales Price
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Average
Production
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Oil
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Gas
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Oil
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Gas
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Cost
per
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Per Bbl
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Per MCF
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Per Bbl
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Per MCF
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Equivalent MCF
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2009
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$ | 53.43 | $ | 3.40 | $ | 51.25 | $ | 3.51 | $ | 1.68 | ||||||||||
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2008
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$ | 96.80 | $ | 8.41 | $ | 91.10 | $ | 7.95 | $ | 2.10 | ||||||||||
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2007
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$ | 67.35 | $ | 6.19 | $ | 65.71 | $ | 6.63 | $ | 1.65 | ||||||||||
At
December 31, 2009, the Company had working interests in 147 gross (17.88 net)
wells producing primarily gas and had working interests in 125 gross (11.34 net)
wells producing primarily oil. These interests were in 55,481 gross (6,933 net)
producing acres. These wells include 51 gross (1.00 net) wells associated with
secondary recovery projects.
Seven
percent or 5,444 barrels of the Company’s oil production during 2009 was derived
from royalty interests in mature West Texas water-floods.
Undeveloped
Acreage
The
Company’s undeveloped acreage consists of non-producing mineral interests and
undeveloped leaseholds. The following table summarizes the Company’s gross and
net acres in each at December 31, 2009.
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Acreage
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Gross
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Net
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Non-producing
Mineral Interests
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259,314 | 89,440 | ||||||
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Undeveloped
Leaseholds
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83,282 | 12,232 | ||||||
Net
Productive and Dry Wells Drilled
The
following table summarizes the net wells drilled in which the Company had a
working interest for the years ended December 31, 2007 and thereafter, as to net
productive and dry exploratory wells drilled and net productive and dry
development wells drilled. Net exploratory and development totals for 2009
include the sixteen wells still drilling at the end of 2008. As indicated in the
“Development Program” and “Exploration Program” on Page 4, three development
wells and three exploratory wells were still in process at the time of this Form
10-K.
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Number of Net Working Interest Wells
Drilled
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Exploratory
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Development
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Productive
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Dry
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Productive
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Dry
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2009
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1.88 | 1.02 | 2.85 | --- | ||||||||||||
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2008
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1.23 | .11 | 2.69 | --- | ||||||||||||
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2007
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--- | .20 | 1.95 | --- | ||||||||||||
Recent
Activities
See Item
7, under the subheading “Update of Oil and Gas Exploration and Development
Activity from December 31, 2008,” for a summary of recent activities related to
oil and natural gas operations.
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ITEM 3.
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LEGAL
PROCEEDINGS
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There are
no material legal proceedings pending affecting the Company or any of its
properties.
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ITEM 4.
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(REMOVED
AND RESERVED)
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PART II
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ITEM
5.
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MARKET
FOR REGISTRANT’S COMMON EQUITY, RELATED STOCK-HOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY
SECURITIES
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The
Company’s stock is dually traded in the Pink Sheet Electronic Quotation Service
and the OTC Bulletin Board under the symbol “RSRV.” The following high and low
bid information was quoted on the Pink Sheets OTC Market Report. Prices reflect
inter-dealer prices without retail markup, markdown or commission and may not
reflect actual transactions.
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Quarterly Ranges
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Quarter Ending
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High Bid
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Low Bid
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03/31/08
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$ | 325 | $ | 260 | ||||
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06/30/08
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$ | 440 | $ | 315 | ||||
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09/30/08
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$ | 412 | $ | 330 | ||||
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12/31/08
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$ | 360 | $ | 225 | ||||
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03/31/09
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$ | 231 | $ | 202 | ||||
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06/30/09
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$ | 250 | $ | 205 | ||||
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09/30/09
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$ | 237 | $ | 205 | ||||
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12/31/09
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$ | 241 | $ | 210 | ||||
There was
limited public trading in the Company’s common stock in 2009 and 2008. In 2009,
there were 15 brokered trades appearing in the Company’s transfer ledger versus
36 in 2008.
At March
26, 2010, the Company had approximately 1,500 record holders of its common
stock. The Company paid dividends on its common stock in the amount of $10.00
per share in the second quarter of 2009, and $10.00 per share in the second
quarter and $30.00 per share in the third quarter of 2008. See the “Financing
Activities” section of Item 7 below for more information about dividends paid.
Management will review the amount of the annual dividend to be paid in 2010 with
the Board of Directors for its approval.
ISSUER
PURCHASES OF EQUITY SECURITIES
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Period
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Total Number of Shares
Purchased
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Average Price Paid Per
Share
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Total Number of Shares Purchased as Part of
Publicly Announced Plans or Programs1
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Approximate Dollar Value of Shares that May Yet Be
Purchased Under the Plans or Programs1
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Oct
1, 2009 to Oct
31, 2009
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5 | $ | 184.00 | - | - | |||||||||||
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Nov
1, 2009 to Nov
30, 2009
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8 | $ | 160.00 | - | - | |||||||||||
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Dec
1, 2009 to Dec
31, 2009
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159 | $ | 198.00 | - | - | |||||||||||
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Total
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172 | $ | 195.83 | - | - | |||||||||||
1The
Company has no formal equity security purchase program or plan. The Company acts
as its own transfer agent and most purchases result from requests made by
shareholders receiving small, odd lot share quantities as the result of probate
transfers.
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ITEM 6.
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SELECTED
FINANCIAL DATA
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Smaller
reporting companies are not required to provide the information required by this
Item.
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ITEM 7.
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MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
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Please
refer to the financial statements and related notes in Item 8 of this Form 10-K
to supplement this discussion and analysis.
Forward-Looking
Statements
In
addition to historical information, from time to time the Company may publish
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.
Forward-looking statements provide the reader with management’s current
expectations of future events. They include statements relating to such matters
as anticipated financial performance, business prospects such as drilling of oil
and gas wells, technological development and similar matters.
Although
management believes that the expectations reflected in such forward-looking
statements are based on reasonable assumptions, a variety of factors could cause
the Company’s actual results and experience to differ materially from the
anticipated results or other expectations expressed in the Company’s
forward-looking statements. The risks and uncertainties that may affect the
operations, performance, development and results of the Company’s business
include, but are not limited to, the following:
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·
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The
Company’s future operating results will depend upon management’s ability
to employ and retain quality employees, generate revenues and control
expenses. Any decline in operating revenues, without corresponding
reduction in operating expenses, could have a material adverse effect on
the Company’s business, results of operations and financial
condition.
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·
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The
Company has no significant long-term sales contracts for either oil or
gas. For the most part, the price the Company receives for its product is
based upon the spot market price, which in the past has experienced
significant fluctuations. Management anticipates such price fluctuations
will continue in the future, making any attempt at estimating future
prices subject to significant uncertainty.
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·
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Exploration
costs have been a significant component of the Company’s capital
expenditures in the past and are expected to remain so, to a somewhat
lesser degree, in the near term. Under the successful efforts method of
accounting for oil and gas properties, which the Company uses, these costs
are capitalized, if the prospect is successful, or charged to operating
costs and expenses, if unsuccessful. Estimating the amount of such future
costs, which may relate to successful or unsuccessful prospects, is
extremely imprecise at best.
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·
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The
Company has equity investments in organizations over which the Company has
limited or no control. The management of these entities could at any time
make decisions in their own best interests, which could affect the
Company’s net income or the value of the Company’s investments. See
“Equity Investments” below in this Item 7 for information regarding these
equity investments.
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The
Company does not undertake any obligation to publicly revise forward-looking
statements to reflect events or circumstances that arise after the date hereof.
Readers should carefully review the information described in other documents the
Company files from time to time with the Securities and Exchange Commission,
including the Quarterly Reports on Form 10-Q to be filed by the Company in 2010
and any Current Reports on Form 8-K filed by the Company.
Critical
Accounting Estimates
|
·
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Estimates
of future revenues from oil and gas sales are derived from a combination
of factors, which are subject to significant fluctuation over any given
period of time. Reserve estimates, by their nature, are subject to
revision in the short-term. The evaluating engineer considers production
performance data, reservoir data and geological data available to the
Company, as well as makes estimates of production costs, sale prices and
the time period the property can be produced at a profit. A change in any
of the above factors can significantly change the timing and amount of net
revenues from a property. The Company’s producing properties are composed
of many small working interest and royalty interest properties. As a
non-operating owner, the Company has limited access to the underlying data
from which working interest reserve estimates are calculated, and
estimates of royalty interest reserves are not made because the
information required for the estimation is not available to the Company.
While reserve estimates are not accounting estimates, they are the basis
for depreciation, depletion and amortization described below.
Additionally, the estimated economic life for each producing property from
the reserve estimates is used in the calculation of asset retirement
obligations.
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·
|
The
provisions for depreciation, depletion and amortization of oil and gas
properties all constitute critical accounting estimates. Non-producing
leaseholds are amortized, over the life of the leasehold, using a straight
line method; however, when leaseholds are impaired or condemned, an
appropriate adjustment to the provision is made at that
time.
|
||
|
·
|
The
provision for impairment of long-lived assets is determined by review of
the estimated future cash flows from the individual properties. A
significant, unforeseen downward adjustment in future prices and/or
potential reserves could result in a material change in estimated
long-lived assets impairment.
|
||
|
·
|
Depletion
and depreciation of oil and gas properties are computed using the
units-of-production method. A significant, unanticipated change in volume
of production or estimated reserves would result in a material, unexpected
change in the estimated depletion and depreciation
provisions.
|
||
|
·
|
The
Company has significant obligations to remove tangible equipment and
facilities associated with oil and gas wells and to restore land at the
end of oil and gas production operations. Removal and restoration
obligations are most often associated with plugging and abandoning wells.
Estimating the future restoration and removal costs is difficult and
requires estimates and judgments because most of the removal obligations
will take effect in the future. Additionally, these operations are subject
to private contracts and government regulations that often have vague
descriptions of what is required. Asset removal technologies and costs are
constantly changing, as are regulatory, political, environmental and
safety considerations. Inherent in the present value calculations are
numerous assumptions and judgments, including the ultimate removal cost
amounts, inflation factors and discount rate.
|
|
·
|
Oil
and natural gas sales revenue accrual is another critical accounting
estimate. The Company does not operate any of its oil and natural gas
properties. Timely obtaining production data on all wells from the
operators is not feasible; therefore, the Company utilizes past production
receipts and estimated sales price information to estimate its accrual of
revenue on all wells each quarter. The oil and natural gas sales revenue
accrual can be impacted by many variables, including rapid production
decline rates, production curtailments by operators and rapidly changing
market prices for oil and natural gas. These variables could lead to an
over or under accrual of oil and natural gas sales at the end of any
particular quarter. Based on past history, the Company’s estimated accrual
has been materially accurate.
|
||
|
·
|
The
estimation of the amounts of income tax to be recorded by the Company
involves interpretation of complex tax laws and regulations as well as the
completion of complex calculations, including the determination of the
Company’s percentage depletion deduction, if any. To calculate the exact
excess percentage depletion allowance, a well-by-well calculation is, and
can only be, performed at the end of each fiscal year. During interim
periods, a high-level estimate is made taking into account historical data
and current pricing. Although the Company’s management believes its tax
accruals are adequate, differences may occur in the future depending on
the resolution of pending and new tax matters.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS
The
Company is affiliated by common management and ownership with Mesquite Minerals,
Inc., (Mesquite), Mid-American Oil Company (Mid-American), Lochbuie Limited
Partnership (LLTD) and Lochbuie Holding Company (LHC). The Company also owns
interests in certain producing and non-producing oil and gas properties as
tenants in common with Mesquite, Mid-American and LLTD.
Mason
McLain, an officer and director of the Company, is an officer and director of
Mesquite and Mid-American. Robert T. McLain and Jerry Crow, Directors of the
Company, are directors of Mesquite and Mid-American. Kyle McLain and Cameron R.
McLain are sons of Mason McLain, who owns more than 5% of the Company, and are
officers and directors of the Company. Kyle McLain and Cameron McLain are
officers and directors of Mesquite and Mid-American. Mason McLain and Robert T.
McLain, who are brothers, each own an approximate 32% limited partner interest
in LLTD, and Mason McLain is president of LHC, the general partner of LLTD.
Robert T. McLain is not an employee of any of the above entities and devotes
only a small amount of time conducting their business.
The above
named officers, directors and employees, as a group, beneficially own
approximately 29% of the common stock of the Company, approximately 32% of the
common stock of Mesquite and approximately 17% of the common stock of
Mid-American. These three corporations, each, have only one class of stock
outstanding. See Item 8, Note 12 to the accompanying financial statements for
additional disclosures regarding these relationships.
EQUITY
INVESTMENTS
For most
of 2008 and all of 2009, the Company had investments in four entities, which it
accounted for on the equity method. In using the equity method, the Company
records the original investment in an entity as an asset and adjusts the asset
balance for the Company’s share of any income or loss, as well as any additional
contributions to or distributions from the entity. In June, 2008, the Company
purchased a 10% ownership in Bailey Hilltop Pipeline, LLC. The remaining three
entities include one Oklahoma limited partnership and two Oklahoma limited
liability companies. The Company does not have actual or effective control of
any of the entities. The management of these entities could, at any time, make
decisions in their own best interests that could materially affect the Company’s
net income or the value of the Company’s investments.
The
remaining entities are Broadway Sixty-Eight, Ltd. (33% limited partnership
interest), OKC Industrial Properties, LLC (10% ownership) and JAR Investments,
LLC (25% ownership). These entities, collectively and/or individually, have had
a significant effect, both positively and negatively, on the Company’s net
income in the past and are expected to in the future. Two of these entities have
guarantee arrangements under which the Company is contingently liable. Item 8,
Note 7 to the accompanying financial statements includes related disclosures and
additional information regarding these entities.
LIQUIDITY
AND CAPITAL RESOURCES
To
supplement the following discussion, please refer to the Balance Sheets and the
Statements of Cash Flows included in this Form 10-K.
In 2009,
as in prior years, the Company funded its business activity through the use of
internal sources of capital. For the most part, these internal sources are cash
flows from operations, cash, cash equivalents and available-for-sale securities.
When cash flows from operating activities are in excess of those needed for
other business activities, the remaining balance is used to increase cash, cash
equivalents and/or available-for-sale securities. When cash flows from operating
activities are not adequate to fund other business activities, withdrawals are
made from cash, cash equivalents and/or available-for-sale securities. Cash
equivalents are highly liquid debt instruments purchased with a maturity of
three months or less. Most of the available-for-sale securities are U.S.
Treasury Bills.
In 2009,
net cash provided by operating activities was $5,304,623. Sales, net of
production, exploration, general and administrative costs and income taxes paid
were $4,884,441, which accounted for 92% of net cash provided by operations. The
remaining components provided $420,182 or 8% of cash flow. In 2009, net cash
applied to investing activities was $4,028,723. Net purchases of
available-for-sale securities discussed below and capitalized property additions
(net of disposals) accounted for $4,095,473 of the total net cash applied to
investing activities. Maturing available-for-sale securities provided
$32,944,856 of gross cash flow due to their six-month maturities. However, these
funds, plus $949,902 of excess cash from operations, were re-invested in the
same type of securities.
In 2009,
cash utilized for capitalized property additions (net of disposals) was
$3,145,571. Dividend payments and treasury stock purchases totaled $1,655,591
and accounted for all of the cash applied to financing activities.
Other
than cash, cash equivalents and available-for-sale securities, other significant
changes in working capital include the following:
Trading
securities increased $132,144 (61%) to $350,372 in 2009 from $218,228 in 2008.
Most of the increase is due to a $90,557 increase in unrealized gains, which
represent the change in the fair value of the securities from their original
cost. The remaining increase of $41,587 represents the earnings from the
securities plus the net realized gains for the year. Net realized gains were
reinvested in additional securities.
Receivables
decreased $294,099 (17%) to $1,444,757 in 2009 from $1,738,856 in 2008. The
decrease was due primarily to declines in four components of the receivables
balance as follows: (1) receivables for sales accruals have declined about
$135,500 in 2009 from 2008; (2) a receivable of about $62,100 related to the
sale of producing properties in June, 2008 was collected in June, 2009; (3) a
note receivable declined $50,000 in 2009 from 2008 and (4) accrued interest
receivable declined about $45,000 in 2009 from 2008. Additional information
about the decline in sales for 2009, properties sold in 2008 and the interest
rate decline in 2009 is included in the “Results of Operations” section that
follows. Information about the note receivable is included in Item 8, Note 7 to
the accompanying financial statements.
Refundable
income taxes decreased $685,265 (69%) to $314,308 in 2009 from $999,573 in 2008.
This decrease was due entirely to applying the 2009 current Federal tax
provision of $695,135 to the refundable income taxes balance.
Prepaid
expenses of $197,304 in 2009 were prepaid seismic expenses on the Hodgeman
County, Kansas, prospect discussed in the “Update of Oil and Gas Exploration and
Development Activity from December 31, 2008” in the “Results of Operations”
section below. The seismic survey work was completed in February, 2010. There
were no similar prepaid expenses at December 31, 2008.
Accounts
payable increased $102,402 (49%) to $310,889 in 2009 from $208,487 in 2008. This
increase was primarily due to increased drilling activity at year-end 2009
versus 2008. See the discussion of this activity under “Update of Oil and Gas
Exploration and Development Activity from December 31, 2008” in the “Results of
Operations” section below.
Deferred
income taxes and other decreased $19,472 (9%) to $201,794 in 2009 from $221,266
in 2008. This decrease was primarily due to a decrease of $15,000 in the accrual
for some ad valorem tax bills on several Robertson County, Texas, gas
wells.
The
following is a discussion of material changes in cash flow by activity between
the years ending December 31, 2009 and 2008. Also see the discussion of changes
in operating results under “Results of Operations” below in this Item
7.
Operating
Activities
As noted
above, net cash flows provided by operating activities in 2009 were $5,304,623
which, when compared to the $13,543,730 provided in 2008, represents a decrease
of $8,239,107 or 61%. The decrease was mostly due to a decline in oil and gas
sales cash flows of $11,586,529; a decrease in lease bonuses and coal royalties
of $660,978; a decline in interest income of $271,729 and increased exploration
costs of $879,175. Those decreases in cash flows were partially offset by a
decrease in production costs of $658,499 and a decrease in income taxes paid of
$4,506,861. Additional discussion of the more significant items
follows.
Discussion
of Selected Material Line Items Resulting in a Decrease in Cash Flows.
The $11,586,529 (57%) decrease in cash received from oil and gas sales to
$8,871,090 in 2009 from $20,457,619 in 2008 was the result of a decrease in both
the average oil and gas prices and the volume of oil and gas sales. See “Results
of Operations” below for a price/volume analysis and the related discussion of
oil and gas sales.
Cash
received for lease bonuses and coal royalties declined $660,978 (71%) to
$275,707 in 2009 from to $936,685 in 2008. Most of the decrease is due to a
decrease in cash received for lease bonuses of about $694,000 in 2009 versus
2008. This decrease was offset by an increase in the cash received for coal
royalties of $32,995 to $226,399 in 2009 from $193,404 in 2008.
Cash
received for interest earned on cash equivalents and available-for-sale
securities decreased $271,729 (70%) to $118,477 in 2009 from $390,206 in 2008.
The decrease was the result of a decrease in the average rate of return to 0.73%
in 2009 from 2.41% in 2008.
Cash flow
decreased due to an increase in cash paid for exploration expenses of $879,175
to $891,221 in 2009 from $12,046 in 2008. About $490,000 of the increase was due
to increased geological and geophysical expense in 2009 versus 2008 due partly
to the prepaid seismic balance at 2009 year-end. The remaining increase of about
$389,000 was due to higher dry hole costs in 2009 versus 2008.
Discussion
of Selected Material Line Items Resulting in an Increase in Cash Flows.
Cash paid for production costs decreased $658,499 (29%) to $1,590,437 in 2009
from $2,248,936 in 2008. This decline was due to a $123,053 decrease in lease
operating and handling expenses and a decrease of $521,623 in production taxes
in 2009 versus 2008. Most of the lease operating expense decrease was
attributable to lower workover costs in 2009 versus 2008. The decrease in
production taxes was due to the decline in sales in 2009 versus
2008.
Income
taxes paid decreased $4,506,861 (99%) to $18,476 in 2009 from $4,525,337 in 2008
due to no estimated tax payments in 2009 discussed above and below in “Results
of Operations.”
Investing
Activities
Net cash
applied to investing activities decreased $3,387,434 (46%) to $4,028,723 in 2009
from $7,416,157 in 2008. In 2009, net cash applied to available-for-sale
securities decreased to $949,902 in 2009 from $2,675,042 in 2008. This decline
was a result of utilizing a smaller portion of the operations cash flow for
financing activities in 2009 as discussed below. Cash flows related to property
acquisitions resulted in a decrease in cash applications to investing activities
in 2009 versus 2008. Cash applied to property acquisitions decreased $1,940,897
(38%) to $3,222,146 in 2009 from $5,163,043 in 2008 due primarily to decreased
exploration and development drilling activity. See the “Update of Oil and Gas
Exploration and Development Activity from December 31, 2008” under the “Results
of Operations” heading below for more information regarding expenditures related
to this drilling activity. Cash flow from property dispositions decreased
$515,344 to $76,575 in 2009 from $591,919 in 2008 resulting in a decrease of the
cash applications to investing activities. Property dispositions in 2008
included proceeds of about $592,000 from the sale of the Company’s ownership
interest in a group of Seminole County, Oklahoma producing properties with no
similar sales in 2009. The decreases in cash applications for investing
activities were offset by an increase in cash distributions from equity
investments of $10,200 (156%) to $16,750 in 2009 from $6,550 in 2008. This
increase is mostly due to a $10,000 distribution in 2009 from the Bailey Hilltop
Pipeline, LLC. There was no similar distribution in 2008.
Financing
Activities
Cash
applied to financing activities decreased $4,273,526 (72%) to $1,655,591 in 2009
from $5,929,117 in 2008. Cash applied to financing activities consist of cash
dividends on common stock and cash used for the purchase of treasury stock. In
2009, cash dividends paid on common stock amounted to $1,565,551 as compared to
$5,857,097 in 2008. The decrease was the result of a decrease in the 2009
dividends per share to $10.00 from $40.00 in 2008. The cash applied to the
purchase of treasury stock was $90,040 in 2009 as compared to $72,020 in 2008.
The increase in treasury stock purchases in 2009 from 2008 is due to a
combination of more shares purchased in 2009 (485 shares) versus 2008 (347
shares), offset by a lower average price paid in 2009 of $186 per share versus
$208 per share in 2008. For additional information about treasury stock
purchases, see Note1
at the end of Item 5, "Market for Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities”
above.
Forward-Looking
Summary
Despite
the current depressed prices being received for crude oil and natural gas sales,
the latest estimate of business to be done in 2010 and beyond indicates the
projected activity can be funded from cash flow from operations and other
internal sources, including net working capital. The Company is engaged in
exploratory drilling. If this drilling is successful, substantial development
drilling may result. Also, should other exploration projects, which fit the
Company’s risk parameters, become available or other investment opportunities
become known, capital requirements may be more than the Company has available.
If so, external sources of financing could be required.
RESULTS
OF OPERATIONS
As
disclosed in the Statements of Operations in Item 8 of this Form 10-K, in 2009,
the Company had net income of $1,607,399 as compared to a net income of
$9,647,693 in 2008. Net income per share, basic and diluted, was $9.92 in 2009,
a decrease of $49.51 per share from $59.43 in 2008. Material line item changes
in the Statements of Operations will be discussed in the following
paragraphs.
Operating
Revenues
Operating
revenues decreased $11,692,777 (56%) to $9,013,233 in 2009 from $20,706,010 in
2008. Oil and gas sales decreased $10,962,411 (56%) to $8,755,031 in 2009 from
$19,717,442 in 2008. Lease bonuses and other revenues decreased $730,366 (74%)
to $258,202 in 2009 from $988,568 in 2008. This decrease was the result of a
decline in lease bonuses of $693,972 due to decreased bonuses from East Texas
and Colorado leases. In addition, coal royalties from North Dakota leases
decreased $36,393 (15%) to $208,894 in 2009 from $245,287 in 2008. The Company
does not anticipate that coal royalties will have a significant impact on its
future results of operations. The decrease in oil and gas sales will be
discussed in the following paragraphs.
The
$10,962,411 decrease in oil and gas sales was the result of a $7,575,320
decrease in gas sales, plus a $3,289,663 decrease in oil sales and a $97,428
decrease in miscellaneous oil and gas product sales. The following price and
volume analysis is presented to help explain the changes in oil and gas sales
from 2008 to 2009. Miscellaneous oil and gas product sales of $192,335 in 2009
and $289,763 in 2008 are not included in the analysis.
|
Variance
|
|
|||||||||||||||
|
Production
|
2009
|
Price
|
Volume
|
2008
|
||||||||||||
|
Gas
–
|
||||||||||||||||
|
MCF
(000 omitted)
|
1,297 | (155) | 1,452 | |||||||||||||
|
$(000
omitted)
|
$ | 4,454 | $ | (6,292) | $ | (1,283) | $ | 12,029 | ||||||||
|
Unit
Price
|
$ | 3.43 | $ | (4.85) | $ | 8.28 | ||||||||||
|
Oil
–
|
||||||||||||||||
|
Bbls
(000 omitted)
|
79 | (1) | 80 | |||||||||||||
|
$(000
omitted)
|
$ | 4,109 | $ | (3,220) | $ | (70) | $ | 7,399 | ||||||||
|
Unit
Price
|
$ | 51.64 | $ | (40.45) | $ | 92.09 | ||||||||||
The
$7,575,320 (63%) decrease in natural gas sales to $4,453,740 in 2009 from
$12,029,060 in 2008 was the result of a decrease in both the average price
received per thousand cubic feet (MCF) and gas sales volumes. The average price
per MCF of natural gas sales decreased $4.85 per MCF to $3.43 in 2009 from $8.28
per MCF in 2008, resulting in a negative gas price variance of $6,291,637. A
negative volume variance of $1,283,683 was the result of a decrease in natural
gas volumes sold of 155,034 MCF to 1,297,334 MCF in 2009 from 1,452,368 MCF in
2008. The decrease in the volume of gas production was the net result of new
2009 production of about 247,400 MCF, offset by declines of 402,434 MCF. These
declines are a combination of normal declines in production from mature
producing properties and some operator curtailments in Robertson County, Texas.
These curtailments are discussed below. As disclosed in Supplemental Schedule 1
of the Unaudited Supplemental Financial Information included in Item 8 below,
working interests in natural gas extensions and discoveries were adequate to
replace working interest reserves produced in 2009 but not in 2008.
The gas
production for 2008 and 2009 includes production from several royalty interest
properties drilled by various operators in Robertson County, Texas. The first of
these wells began producing in late March 2005, and the most recent one began
producing in November 2009. These properties accounted for approximately 845,000
MCF and $7,279,000 of the 2008 gas sales and approximately 729,000 MCF and
$2,504,000 of the 2009 gas sales. The production decline of 116,000 MCF was the
net result of new 2009 gas production of about 128,000 MCF, offset by a decline
in existing gas production of about 244,000 MCF. This decrease was due to a
combination of normal production declines plus operator curtailments due to
depressed natural gas prices in late 2009. This group of royalty interest
properties accounted for about 75% of the 2009 production decline. However,
these same properties accounted for about 56% of the Company’s 2009 gas revenues
and continue to have a significant impact on our operating income. While the
operators are currently drilling and plan more drilling in the future on the
acreage in which the Company holds mineral interests, the Company has no control
over the timing of such activity.
The
$3,289,663 (44%) decrease in crude oil sales to $4,108,956 in 2009 from
$7,398,619 in 2008 was the result of a decrease in both the average price per
barrel (Bbl) and oil sales volumes. The average price received per Bbl of oil
decreased $40.45 to $51.64 in 2009 from $92.09 in 2008, resulting in a negative
oil price variance of $3,219,553. A decrease in oil sales volumes of 761 Bbls to
79,576 Bbls in 2009 from 80,337 Bbls in 2008, resulted in a negative volume
variance of $70,110. The decrease in the oil volume production was the net
result of new 2009 production of about 13,530 Bbls, offset by 14,291 Bbls of
normal decline in production from mature producing properties. Of the new 2009
production, approximately 6,750 Bbls (50%) was from Woods County, Oklahoma. Of
the remaining new production, about 5,950 Bbls (44%) was from new working
interest wells in Kansas and Oklahoma (in counties other than Woods) and about
830 Bbls (6%) was from new royalty interest wells in Texas and Oklahoma. As
disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial
Information included below in Item 8, working interests in oil extensions and
discoveries were not adequate to replace working interest reserves produced in
2009 or 2008.
For both
oil and gas sales, the price change was mostly the result of a change in the
spot market prices upon which most of the Company’s oil and gas sales are based.
These spot market prices have had significant fluctuations in the past and these
fluctuations are expected to continue. Spot market price declines
in 2009 and late 2008 for both crude oil and natural gas provided an excellent
example of the fluctuations that can and do occur and the impact they can have
on operating results. The decline in average spot market prices in 2009 from
2008 accounted for about $9,510,000 (87%) of the $10,962,000 decrease in oil and
gas sales for 2009 from 2008.
Operating
Costs and Expenses
Operating
costs and expenses decreased $706,218 (9%) to $7,471,313 in 2009 from $8,177,531
in 2008, primarily due to decreases in production costs and depreciation,
depletion and amortization, offset by an increase in exploration expense. The
material components of operating costs and expenses are discussed
below.
Production
Costs. Production costs decreased $663,232 (29%) to $1,608,992 in 2009
from $2,272,224 in 2008. The decrease was the result of a $521,623 (58%) decline
in gross production tax (net of production tax refunds) to $381,601 in 2009 from
$903,224 in 2008, plus a decrease in lease operating and handling expense of
$141,609 (10%) to $1,227,391 in 2009 from $1,369,000 in 2008. Most of the
decrease in lease operating and handling expense was due to a decrease in
handling expense of $85,455 (21%) to $321,438 in 2009 from $406,893 in 2008.
Most of the handling expense decline was due to the decreased gas sales from the
Robertson County, Texas royalty interest properties. Handling expense is
comprised of gas gathering, treating, transportation and compression costs.
Gross production taxes are state taxes, which are calculated as a percentage of
gross proceeds from the sale of products from each producing oil and gas
property; therefore, they fluctuate with the change in the dollar amount of
revenues from oil and gas sales. Most of the gross production tax refunds relate
to the Robertson County, Texas properties and are due to a Texas program used as
an incentive to encourage operators to drill deep or tight sands gas wells.
These refunds are not permanent but are for a limited number of months of
production.
Exploration
and Development Costs. Under the successful efforts method of accounting
used by the Company, geological and geophysical costs are expensed as incurred
as are the costs of unsuccessful exploratory drilling. The costs of successful
exploratory drilling and all development costs are capitalized. Total costs of
exploration and development, excluding asset retirement obligations but
inclusive of geological and geophysical costs, were $3,693,128 in 2009 and
$4,827,352 in 2008. See Item 8, Note 8 to the accompanying financial statements
for additional information regarding a breakdown of these costs. Costs charged
to operations were $987,088 in 2009 and $142,550 in 2008, inclusive of
geological and geophysical costs of $292,326 in 2009 and $120,446 in
2008.
Update of
Oil and Gas Exploration and Development Activity from December 31, 2008.
For the twelve months ended December 31, 2009, the Company participated in the
drilling of sixteen gross exploratory and seventeen gross development working
interest wells with working interests ranging from a high of 18.0% to a low of
2.7%. Of the sixteen exploratory wells, seven were completed as producing wells,
six as dry holes and three were in progress. Of the seventeen development wells,
fourteen were completed as producing wells and three were in progress. In
management’s opinion, the exploratory drilling summarized above has produced
some possible development drilling opportunities.
The
following is a summary as of March 3, 2010, updating both exploration and
development activity from December 31, 2008.
|
The
Company participated with its 18% working interest in the drilling of two
development wells on a Barber County, Kansas prospect. Both wells were
drilled in October 2009 and completed in January 2010. Both appear to be
commercial oil wells. Capitalized costs as of December 31, 2009, were
$141,576, including $34,423 in prepaid drilling costs.
|
||
|
The
Company participated with its 18% working interest in the drilling of two
step-out wells on a Barber County, Kansas prospect. Both wells were
started in November 2008 and completed in July 2009 as commercial oil and
gas producers. Total capitalized costs were $199,778 at December 31,
2009.
|
||
|
The
Company participated in the drilling of three exploratory wells on a Grady
County, Oklahoma prospect in which it has a 10% interest. The first well
was started in July 2008 and completed in March 2009 as a commercial gas
and condensate producer. The second well was started in August 2008 and
completed in April 2009, flowing gas and condensate at a commercial rate.
Sales commenced in June 2009. The third well, a re-entry and sidetrack of
a 2007 exploratory dry hole, was started in December 2008 and completed in
January 2009 as a dry hole. The Company also participated in a step-out
well, which was started in September 2009 and completed in December 2009
as a commercial gas and condensate producer. In July 2009, the Company
participated in the acquisition of additional 3-D seismic data over a
portion of the prospect. Potential drilling locations have been identified
and acreage is currently being acquired. Total capitalized costs for the
period ended December 31, 2009, were $191,403, including $32,860 in
prepaid drilling costs. Dry hole costs of $125,874 and seismic costs of
$45,811 were expensed as of December 31, 2009.
|
||
|
The
Company participated with its 16.2% working interest in the drilling of an
exploratory well on a Comanche County, Kansas prospect. The well was
started in November 2008 and completed in March 2009 as a marginal oil and
gas producer. It has subsequently been re-completed in another zone but
remains a marginal well. Total capitalized costs as of December 31, 2009,
were $120,511.
|
||
|
The
Company participated with its 18% working interest in the drilling of an
exploratory well on a Kiowa County, Kansas prospect. The well was started
in November 2008 and completed in February 2009 as a commercial oil and
gas producer. The Company also participated in the drilling of two
exploratory step-out wells. The first was started in October 2009 and
completed in December 2009. The well was non-commercial and will be
plugged. The second was drilled in November 2009 and completed as a dry
hole. Total capitalized costs were $156,680 at December 31, 2009,
including $31,239 in prepaid drilling costs. Total dry hole costs were
$101,063 for the same period.
|
|
The
Company participated with its 18% working interest in the drilling of two
exploratory wells on a Comanche County, Kansas prospect. The first was
started in April 2009 and completed in June 2009 as a commercial oil and
gas well. The second was drilled in April 2009 and completed as a dry
hole. The Company also participated in the drilling of two step-out wells.
The first was started in November 2009 and completed in February 2010. It
appears to be a marginal well. The second was started in November 2009 and
a completion attempt is currently in progress. As of December 31, 2009,
capitalized costs were $269,519, including prepaid drilling costs of
$109,001, and dry hole costs were $31,477.
|
||
|
The
Company participated with its 18% working interest in the drilling of an
exploratory well on a Comanche County, Kansas prospect. The well was
started in May 2009 and completed in July 2009 as a marginal oil and gas
producer. Capitalized costs at December 31, 2009, were
$98,023.
|
||
|
The
Company participated with its 18% working interest in the drilling of two
exploratory wells on a Comanche County, Kansas prospect. One was drilled
in May 2009 and the other in June 2009. Both were completed in October
2009, the first as a marginal oil and gas well and the second as a
commercial gas well. Capitalized costs at December 31, 2009, were
$185,184, including $39,595 in prepaid drilling costs.
|
||
|
The
Company participated with its 16% working interest in the drilling of two
step-out wells on a Harper County, Kansas prospect. Both wells were
started in June 2009 and completed in October 2009 as commercial oil and
gas wells. Two additional wells, one exploratory and one a step-out, will
be drilled starting in March 2010. Total capitalized costs at December 31,
2009, were $155,663.
|
||
|
The
Company participated with an 18% interest in the development of a McClain
County, Oklahoma prospect. Acreage has been acquired and an exploratory
well will be drilled in 2010. Leasehold costs at December 31, 2009, were
$10,606.
|
||
|
The
Company participated with a 50% interest in the development of another
McClain County, Oklahoma prospect. Acreage was acquired and agreements
negotiated to sell part of the Company’s interest and to obtain access to
a 3-D seismic survey which covered the prospect area. The Company retained
a 16% interest in the prospect acreage. An exploratory well was started in
December 2009 and a completion attempt is currently in progress.
Capitalized costs at December 31, 2009, were $105,019, including leasehold
costs of $31,382 and prepaid drilling costs of $38,369.
|
||
|
The
Company is participating with a 21% interest in the development of a
Lincoln County, Oklahoma prospect. Acreage has been acquired and the
prospect is under evaluation for the possible drilling of an exploratory
horizontal well in 2010. Leasehold costs were $44,124 as of December 31,
2009.
|
||
|
The
Company participated with a 12% working interest in the drilling of two
step-out wells on a Woods County, Oklahoma prospect. Both wells were
started in June 2009. The first well was completed in July 2009 and the
second well in August 2009. Both are commercial oil and gas wells. The
Company participated with a 14% working interest in the drilling of two
additional step-out wells. Both were started in February 2010 and are
currently awaiting completion attempts. Capitalized costs as of December
31, 2009, were $129,600, including $19,761 in prepaid drilling
costs.
|
|
The
Company participated with its 10.5% working interest in the drilling of
two exploratory wells on a Woods County, Oklahoma prospect. Both wells
were started in November 2008. The first was completed in March 2009 as a
commercial oil well. The second was completed in April 2009 as a
commercial oil and gas well, although it also produces large quantities of
water. The Company also participated in the drilling of three step-out
wells. Two were started in November 2009 and completed in February 2010.
The third, in which the Company has a reduced interest (2.7%), was started
in November 2009 and completed in January 2010. All three appear to be
commercial oil and gas wells. Total capitalized costs were $366,060 at
December 31, 2009, including $578 in prepaid drilling
costs.
|
||
|
The
Company participated with its 8% working interest in the drilling of a
step-out well on a Woods County, Oklahoma prospect. The well was started
in December 2008 and completed in March 2009 as a commercial oil and gas
producer. Total capitalized costs were $58,804 at December 31,
2009.
|
||
|
The
Company participated in the drilling of two development wells (18% and
13.7% working interests) on a Woods County, Oklahoma prospect. The first
well was started in December 2009 and completed in February 2010 as a
commercial oil and gas producer. The second well was started in December
2009 and a completion attempt is currently in progress. Capitalized costs
as of December 31, 2009, were $152,001, including $82,402 in prepaid
drilling costs.
|
||
|
In
January 2009, the Company purchased a 16% interest in 18,343 net acres of
leasehold on a Ford County, Kansas prospect for $176,094. A 3-D seismic
survey of the prospect acreage was conducted. An exploratory well was
started in August 2009 and completed in September 2009 as a commercial oil
well. A step-out well and a second exploratory well were started in
December 2009 and completed in February 2010. Both appear to be commercial
oil wells. Two additional exploratory wells will be drilled starting in
March 2010. Capitalized costs as of December 31, 2009, were $185,984,
including $79,622 in prepaid drilling costs. Seismic costs were
$219,429.
|
||
|
In
March 2009, the Company purchased a 7% interest in 3,262 net acres of
leasehold on a Williams and Defiance Counties, Ohio prospect for $15,702,
including $3,889 expensed for seismic. Two exploratory wells were drilled
starting in April 2009. Completion attempts on both wells were
unsuccessful and the operator has recommended that both be plugged. Costs
expensed to dry hole were $59,208 for the period ended December 31,
2009.
|
||
|
The
Company participated with a fee mineral interest in the drilling of two
step-out horizontal wells in Van Buren County, Arkansas. The Company has a
9.3% interest in the wells, one of which was started in October 2009 and
the other in November 2009. Both were completed in January 2010 as
commercial gas wells. Total capitalized costs as of December 31, 2009,
were $520,206, including $416,543 in prepaid drilling
costs.
|
||
|
In
June 2009, the Company purchased a 10% interest in 315 net acres of
leasehold on a Grayson County, Texas prospect for $7,875. An exploratory
well was drilled and completed in September 2009 as a dry hole. No
additional drilling is planned. Dry hole expenses were
$67,478.
|
||
|
In
July 2009, the Company purchased a 6% interest in 10,142 net acres of
leasehold on a Ford and Kiowa Counties, Kansas prospect for $18,255. An
exploratory horizontal well was started in July 2009 and completed in
October 2009. In August and September 2009, an old dry hole was
re-entered, washed down, deepened and completed as a salt water disposal
well. A second exploratory horizontal well was started in September 2009
and completed in December 2009. Testing of both wells has failed to
indicate commercial production and both are currently shut in. The
prospect is being re-evaluated. Total capitalized costs as of December 31,
2009, were $247,083, including $65,762 in prepaid drilling costs. An
impairment provision of $217,083 has been made as of December 31,
2009.
|
|
In
November 2009, the Company purchased a 16% interest in 20,928 net acres of
leasehold on a Hodgeman County, Kansas prospect for $200,904 and paid
$219,947 in estimated seismic costs. A 3-D seismic survey was conducted in
January and February 2010. The data set is currently being processed,
after which, it will be evaluated to find exploratory drilling
locations.
|
||
|
In
November 2009, four wells in Harding County, South Dakota, in which the
Company had working interests of 10.9%, 25%, 14.6% and 18.8%, were
unitized into a secondary recovery unit. The Company has an 8.3% working
interest in the unit. Two of the nine unit wells have been converted from
oil producers to water injectors. Two additional water injection wells
will be drilled in 2010. Total capitalized costs for the unit for the
period ended December 31, 2009, were $83,669.
|
||
|
In
November 2009, the Company agreed to participate with its 4.8% working
interest in the drilling of a horizontal development well on a Dewey
County, Oklahoma prospect. The well will be drilled in the second quarter
of 2010.
|
Depreciation,
Depletion, Amortization and Valuation Provisions (DD&A). Major
components are the provision for impairment of undeveloped leaseholds, provision
for impairment of long-lived assets, depletion of producing leaseholds and
depreciation of tangible and intangible lease and well costs. Undeveloped
leaseholds are amortized over the life of the leasehold (most are 3 years) using
a straight line method, except when the leasehold is impaired or condemned by
drilling and/or geological interpretation of seismic data; if so, an adjustment
to the provision is made at the time of impairment. The provision for impairment
of undeveloped leaseholds was $369,915 in 2009 and $140,562 in 2008. The
increase in the provision for impairment is directly related to the exploration
activity discussed under “Exploration and Development Costs,” above. Of the 2009
provision, $327,528 was due to the annual amortization of undeveloped leaseholds
and $42,387 was due to specific leasehold impairments. The 2008 provision was
entirely due to the annual amortization of undeveloped leaseholds with none due
to specific leasehold impairments.
As
discussed in Item 8, Note 10 to the accompanying financial statements,
accounting principles require the recognition of an impairment loss on
long-lived assets used in operations when indicators of impairment are present
and the undiscounted cash flows estimated to be generated by those assets are
less than the assets’ carrying amounts. Evaluation for impairment was performed
in both 2009 and 2008. The 2009 impairment loss of $1,353,020 and the 2008
impairment loss of $1,924,219 were partly the result of reserve adjustments on
wells which first produced in 2006, 2007 and 2008 and partly due to wells
completed in 2009, 2008, 2007 and 2006 for which the estimated fair value of
future production was less than the Company’s carrying amount in the well. The
depressed oil and natural gas prices at 2008 year-end and the average prices for
2009 had a significant impact on the fair value of future production, and
accordingly, the impairment loss for both 2009 and 2008.
The
depletion and depreciation of oil and gas properties are computed by the
units-of-production method. The amount expensed in any year will fluctuate with
the change in estimated reserves of oil and gas, a change in the rate of
production or a change in the basis of the assets. The provision for depletion
and depreciation totaled $1,700,964 in 2009 and $2,204,069 in 2008. Most of the
decrease of $503,105 is due to lower oil and gas property additions in 2009 and
changes in reserve estimates. It also includes $80,636 for 2009 and $99,116 for
2008 for the amortization of the Asset Retirement Obligation. See Item 8, Note 2
to the accompanying financial statements for additional information regarding
the Asset Retirement Obligation.
General,
Administrative and Other Expenses (G&A). G&A decreased $25,061
(2%) to $1,434,068 in 2009 from $1,459,130 in 2008. The decrease was primarily
due to a decrease in real estate taxes, offset partly by an increase in
accounting and legal fees.
Equity
Income in Investees. The following is an analysis of equity income in
investees by entity for the years ended December 31, 2009 and 2008. See Item 8,
Note 7 to the accompanying financial statements for more information about these
investments.
|
Net Income
|
2009
Income
|
|||||||||||
|
2009
|
2008
|
Over/(Under) 2008
|
||||||||||
|
Broadway
Sixty-Eight, Ltd.
|
$ | 27,482 | $ | 73,030 | $ | (45,548 | ) | |||||
|
OKC
Industrial Properties, LLC
|
1,518 | 3,043 | (1,525 | ) | ||||||||
|
Bailey
Hilltop Pipeline, LLC
|
18,962 | 9,692 | 9,270 | |||||||||
|
JAR
Investment, LLC
|
7,514 | 8,450 | (936 | ) | ||||||||
|
Total
|
$ | 55,476 | $ | 94,215 | $ | (38,739 | ) | |||||
Other
Income (Loss), Net. See Item 8, Note 11 to the accompanying financial
statements for an analysis of the components of this line item for the years
ended December 31, 2009 and 2008. Other income, net declined $450,882 (67%) to
$223,978 in 2009 from $674,860 in 2008.
Net
realized and unrealized gains (losses) on trading securities increased $250,040
to a net gain of $129,441 in 2009 from a net loss of $(120,599) in 2008.
Realized gains or losses result when a trading security is sold. Unrealized
gains or losses result from adjusting the Company’s carrying amount in trading
securities owned at the reporting date to estimated fair value. In 2009, the
Company had realized gains of $38,884 and unrealized gains of $90,557. In 2008,
the Company had realized gains of $43,719 and unrealized losses of
$(164,318).
Interest
income decreased $265,598 (78%) to $73,528 in 2009 from $339,126 in 2008. This
decrease was the result of a decrease in the average rate of return on cash
equivalents and available-for-sale securities from which most of interest income
is derived. The average rate of return decreased 1.68% to 0.73% in 2009 from
2.41% in 2008. An increase of only $62,514 in the average balance outstanding to
$16,281,663 from $16,219,149 in 2008 had almost no impact on the average rate of
return.
Most of
the remaining decrease in this line item was due to the decrease in gains on
asset sales of $439,526 to $12,950 in 2009 from $452,475 in 2008. The decrease
in the gains on asset sales was due primarily to a $449,516 gain on the sale of
the Company’s ownership interest in a group of Seminole County, Oklahoma
producing properties in 2008, most of which were acquired in 2003. There were no
similar sales in 2009.
Provision
for Income Taxes. See Item 8, Note 6 to the accompanying financial
statements for an analysis of the various components of income taxes. In 2009,
the Company had an estimated provision for income taxes of $213,975 as the
result of a current tax provision of $703,741 plus a deferred tax benefit of
$(489,766). In 2008, the Company had an estimated provision for income taxes of
$3,649,861 as the result of a current tax provision of $3,372,669 plus a
deferred tax provision of $277,192.
|
ITEM
7A.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISKS
|
Smaller
reporting companies are not required to provide the information required by this
Item.
|
ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
|
Index
to Financial Statements
|
|
|
Page
|
|
|
Report
of Independent Registered Public Accounting Firms
|
|
|
HoganTaylor
LLP – 2009
|
25
|
|
Eide
Bailly LLP – 2008
|
26
|
|
Balance
Sheets - December 31, 2009 and 2008
|
27
|
|
Statements
of Income - Years Ended December 31, 2009 and 2008
|
29
|
|
Statements
of Stockholders’ Equity – Years Ended December 31, 2008 and
2009
|
30
|
|
Statements
of Cash Flows – Years Ended December 31, 2009 and 2008
|
31
|
|
Notes
to Financial Statements
|
33
|
|
Unaudited
Supplemental Financial Information
|
43
|
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Stockholders
The
Reserve Petroleum Company
We have
audited the accompanying balance sheet of The Reserve Petroleum Company as of
December 31, 2009, and the related statements of income, stockholders’ equity
and cash flows for the year ended December 31, 2009. These financial statements
are the responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements based on our
audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether 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 audit provides 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 The Reserve Petroleum Company as of
December 31, 2009, and the results of its operations and its cash flows for the
year ended December 31, 2009, in conformity with U.S. generally accepted
accounting principles.
We were not engaged to examine
management's assessment of the effectiveness of The Reserve Petroleum Company's
internal control over financial reporting as of December 31, 2009, included in
the accompanying Management's Annual Report on Internal Control Over Financial
Reporting and, accordingly, we do not express an opinion thereon.
/s/ HoganTaylor LLP
/s/ HoganTaylor LLP
Oklahoma
City, Oklahoma
March 31,
2010
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and
Stockholders
of The Reserve Petroleum Company
We have
audited the accompanying balance sheet of The Reserve Petroleum Company as of
December 31, 2008, and the related statements of income, stockholders’ equity
and cash flows for the year ended December
31,
2008. The Reserve Petroleum Company’s management is responsible for these
financial statements. Our responsibility is to express an opinion on these
financial statements based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion of the effectiveness of the Company’s internal control over financial
reporting. Accordingly, we express no such opinion. 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 audit provides 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 The Reserve Petroleum Company as of
December 31, 2008, and the results of its operations and its cash flows for the
year ended December 31, 2008, in conformity with accounting principles generally
accepted in the United States of America.
/s/
Eide Bailly LLP
Greenwood
Village, Colorado
March 29,
2009
THE
RESERVE PETROLEUM COMPANY
BALANCE
SHEETS
ASSETS
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Current
Assets:
|
||||||||
|
Cash
and Cash Equivalents (Note 2)
|
$ | 1,051,141 | $ | 1,430,832 | ||||
|
Available-for-Sale
Securities (Notes 2 & 5)
|
16,070,475 | 15,120,573 | ||||||
|
Trading
Securities (Notes 2 & 5)
|
350,372 | 218,228 | ||||||
|
Refundable
Income Taxes
|
314,308 | 999,573 | ||||||
|
Receivables
(Notes 2 & 7)
|
1,444,757 | 1,738,856 | ||||||
|
Prepaid
Expenses
|
197,304 | ---- | ||||||
| 19,428,357 | 19,508,062 | |||||||
|
Investments:
|
||||||||
|
Equity
Investments (Notes 2 & 7)
|
601,309 | 562,584 | ||||||
|
Other
|
15,298 | 15,298 | ||||||
| 616,607 | 577,882 | |||||||
|
Property,
Plant and Equipment (Notes 2, 8 & 10):
|
||||||||
|
Oil
& Gas Properties, at Cost Based on the
|
||||||||
|
Successful
Efforts Method of Accounting
|
||||||||
|
Unproved
Properties
|
1,391,539 | 1,029,500 | ||||||
|
Proved
Properties
|
23,317,446 | 20,543,660 | ||||||
| 24,708,985 | 21,573,160 | |||||||
|
Less
- Valuation Allowance & Accumulated
|
||||||||
|
Depreciation,
Depletion and Amortization
|
16,305,361 | 12,932,782 | ||||||
| 8,403,624 | 8,640,378 | |||||||
|
Other
Property and Equipment, at Cost
|
376,734 | 375,544 | ||||||
|
Less
- Accumulated Depreciation & Amortization
|
290,044 | 272,779 | ||||||
| 86,690 | 102,765 | |||||||
|
Total
Property, Plant & Equipment
|
8,490,314 | 8,743,143 | ||||||
|
Other
Assets
|
350,389 | 325,744 | ||||||
|
Total
Assets
|
$ | 28,885,667 | $ | 29,154,831 | ||||
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
BALANCE
SHEETS
LIABILITIES AND
STOCKHOLDERS’ EQUITY
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Current
Liabilities:
|
||||||||
|
Accounts
Payable (Note 2)
|
$ | 310,889 | $ | 208,487 | ||||
|
Other
Current Liabilities -
|
||||||||
|
Deferred
Income Taxes and Other
|
201,794 | 221,266 | ||||||
| 512,683 | 429,753 | |||||||
|
Long
Term Liabilities:
|
||||||||
|
Asset
Retirement Obligation (Note 2)
|
699,392 | 516,054 | ||||||
|
Dividends
Payable (Note 3)
|
1,015,095 | 959,319 | ||||||
|
Deferred
Tax Liability (Note 6)
|
1,125,923 | 1,613,163 | ||||||
| 2,840,410 | 3,088,536 | |||||||
|
Total
Liabilities
|
3,353,093 | 3,518,289 | ||||||
|
Commitments
& Contingencies (Notes 2 & 7)
|
||||||||
|
Stockholders’
Equity (Notes 3 & 4):
|
||||||||
|
Common
Stock
|
92,368 | 92,368 | ||||||
|
Additional
Paid-in Capital
|
65,000 | 65,000 | ||||||
|
Retained
Earnings
|
26,100,088 | 26,114,016 | ||||||
| 26,257,456 | 26,271,384 | |||||||
|
Less
- Treasury Stock, at Cost
|
724,882 | 634,842 | ||||||
|
Total
Stockholders’ Equity
|
25,532,574 | 25,636,542 | ||||||
|
Total
Liabilities and Stockholders’ Equity
|
$ | 28,885,667 | $ | 29,154,831 | ||||
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENTS
OF INCOME
|
Year Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Operating
Revenues:
|
||||||||
|
Oil
& Gas Sales
|
$ | 8,755,031 | $ | 19,717,442 | ||||
|
Lease
Bonuses & Other Revenues
|
258,202 | 988,568 | ||||||
| 9,013,233 | 20,706,010 | |||||||
|
Operating
Costs and Expenses:
|
||||||||
|
Production
|
1,608,992 | 2,272,224 | ||||||
|
Exploration
|
987,088 | 142,550 | ||||||
|
Depreciation,
Depletion, Amortization & Valuation Provisions
|
3,441,165 | 4,303,627 | ||||||
|
General,
Administrative and Other
|
1,434,068 | 1,459,130 | ||||||
| 7,471,313 | 8,177,531 | |||||||
|
Income
from Operations
|
1,541,920 | 12,528,479 | ||||||
|
Equity
Income in Investees (Note 7)
|
55,476 | 94,215 | ||||||
|
Other
Income, Net (Note 11)
|
223,978 | 674,860 | ||||||
|
Income
before Income Taxes
|
1,821,374 | 13,297,554 | ||||||
|
Provision
for Income Taxes (Notes 2 & 6)
|
213,975 | 3,649,861 | ||||||
|
Net
Income
|
$ | 1,607,399 | $ | 9,647,693 | ||||
|
Per
Share Data (Note 2):
|
||||||||
|
Net
Income, Basic and Diluted
|
$ | 9.92 | $ | 59.43 | ||||
|
Cash
Dividends
|
$ | 10.00 | $ | 40.00 | ||||
|
Weighted
Average Shares Outstanding, Basic and Diluted
|
162,040 | 162,325 | ||||||
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENTS
OF STOCKHOLDERS’ EQUITY
FOR THE
YEARS ENDED DECEMBER 31, 2008 AND 2009
|
Additional
|
||||||||||||||||
|
Common
|
Paid-in
|
Retained
|
Treasury
|
|||||||||||||
|
Stock
|
Capital
|
Earnings
|
Stock
|
|||||||||||||
|
Balance
at January 1, 2008
|
$ | 92,368 | $ | 65,000 | $ | 22,957,809 | $ | (562,822 | ) | |||||||
|
Net
Income
|
--- | --- | 9,647,693 | --- | ||||||||||||
|
Dividends
Declared
|
--- | --- | (6,491,486 | ) | --- | |||||||||||
|
Purchase
of Treasury Stock
|
--- | --- | --- | (72,020 | ) | |||||||||||
|
Balance
at December 31, 2008
|
$ | 92,368 | $ | 65,000 | $ | 26,114,016 | $ | (634,842 | ) | |||||||
|
Net
Income
|
--- | --- | 1,607,399 | --- | ||||||||||||
|
Dividends
Declared
|
--- | --- | (1,621,327 | ) | --- | |||||||||||
|
Purchase
of Treasury Stock
|
--- | --- | --- | (90,040 | ) | |||||||||||
|
Balance
at December 31, 2009
|
$ | 92,368 | $ | 65,000 | $ | 26,100,088 | $ | (724,882 | ) | |||||||
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENTS
OF CASH FLOWS
|
Year Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Cash
Flows from Operating Activities:
|
||||||||
|
Cash
Received-
|
||||||||
|
Oil
and Gas Sales
|
$ | 8,871,090 | $ | 20,457,619 | ||||
|
Lease
Bonuses and Coal Royalties
|
275,707 | 936,685 | ||||||
|
Agricultural
Rentals & Other
|
4,900 | 5,118 | ||||||
|
Cash
Paid-
|
||||||||
|
Production
Costs
|
(1,590,437 | ) | (2,248,936 | ) | ||||
|
Exploration
Costs
|
(891,221 | ) | (12,046 | ) | ||||
|
General
Suppliers, Employees and Taxes,
|
||||||||
|
Other
than Income Taxes
|
(1,486,515 | ) | (1,456,691 | ) | ||||
|
Interest
Received
|
118,477 | 390,206 | ||||||
|
Interest
Paid
|
(3,877 | ) | (3,866 | ) | ||||
|
Settlement
of Class Action Lawsuits
|
24,946 | 1,674 | ||||||
|
Dividends
Received on Trading Securities
|
2,732 | 931 | ||||||
|
Purchase
of Trading Securities
|
(1,047,123 | ) | (529,178 | ) | ||||
|
Sale
of Trading Securities
|
1,044,420 | 527,551 | ||||||
|
Income
Taxes Paid, net
|
(18,476 | ) | (4,525,337 | ) | ||||
|
Net
Cash Provided by Operating Activities
|
$ | 5,304,623 | $ | 13,543,730 | ||||
|
Cash
Flows from Investing Activities:
|
||||||||
|
Maturity
of Available-for-Sale Securities
|
32,944,856 | 26,632,838 | ||||||
|
Purchase
of Available-for-Sale Securities
|
(33,894,758 | ) | (29,307,880 | ) | ||||
|
Proceeds
from Disposal of Property
|
76,575 | 591,919 | ||||||
|
Purchase
of Property, Plant and Equipment
|
(3,222,146 | ) | (5,163,043 | ) | ||||
|
Cash
Distributions from Equity Investments
|
16,750 | 6,550 | ||||||
|
Repayments
from/(Advances to) Equity Investees
|
50,000 | (176,541 | ) | |||||
|
Net
Cash Applied to Investing Activities
|
$ | (4,028,723 | ) | $ | (7,416,157 | ) | ||
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENTS
OF CASH FLOWS
|
Year Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Cash
Flows Applied to Financing Activities:
|
||||||||
|
Dividends
Paid to Shareholders
|
$ | (1,565,551 | ) | $ | (5,857,097 | ) | ||
|
Purchase
of Treasury Stock
|
(90,040 | ) | (72,020 | ) | ||||
|
Total
Cash Applied to Financing Activities
|
$ | (1,655,591 | ) | $ | (5,929,117 | ) | ||
|
Net
Change in Cash and Cash Equivalents
|
(379,691 | ) | 198,456 | |||||
|
Cash
and Cash Equivalents at Beginning of Year
|
1,430,832 | 1,232,376 | ||||||
|
Cash
and Cash Equivalents at End of Year
|
$ | 1,051,141 | $ | 1,430,832 | ||||
|
Reconciliation
of Net Income to Net
|
||||||||
|
Cash
Provided by Operating Activities:
|
||||||||
|
Net
Income
|
$ | 1,607,399 | $ | 9,647,693 | ||||
|
Net
Income Increased (Decreased) by -
|
||||||||
|
Net
Change in -
|
||||||||
|
Unrealized
Holding (Gains) Losses on Trading Securities
|
(90,557 | ) | 164,318 | |||||
|
Accounts
Receivable
|
63,998 | 709,001 | ||||||
|
Interest
and Dividends Receivable
|
118,004 | 51,079 | ||||||
|
Income
Taxes (Refundable) Payable
|
105,006 | (1,152,667 | ) | |||||
|
Accounts
Payable
|
125,440 | 14,739 | ||||||
|
Trading
Securities
|
(41,587 | ) | (45,345 | ) | ||||
|
Other
Assets
|
(221,949 | ) | 98,297 | |||||
|
Deferred
Taxes
|
90,493 | 277,192 | ||||||
|
Other
Liabilities
|
3,696 | 8,720 | ||||||
|
Equity
Income in Investees
|
(55,476 | ) | (94,215 | ) | ||||
|
Disposition
of Property & Equipment
|
158,991 | (438,709 | ) | |||||
|
Depreciation,
Depletion, Amortization and Valuation Provisions
|
3,441,165 | 4,303,627 | ||||||
|
Net
Cash Provided by Operating Activities
|
$ | 5,304,623 | $ | 13,543,730 | ||||
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
NOTES TO
FINANCIAL STATEMENTS
Note 1 –
NATURE OF
OPERATIONS
The
Company is principally engaged in oil and natural gas exploration and
development and minerals management with areas of concentration in Texas,
Oklahoma, Kansas and South Dakota, a single business segment.
Note 2 –
SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
Cash and Cash
Equivalents
The
Company considers all highly liquid debt instruments purchased with a maturity
of three months or less to be cash equivalents.
Investments
Marketable
Securities:
The
Company classifies its debt and equity securities in one of three categories:
trading, available-for-sale and held-to-maturity. Trading securities are bought
and held principally for the purposes of selling them in the near term.
Held-to-maturity securities are those securities in which the Company has both
the ability and intent to hold the security until maturity. All other securities
not included in trading or held-to-maturity are classified as
available-for-sale.
Trading
and available-for-sale securities are recorded at fair value. Unrealized gains
and losses on trading securities, which consist primarily of equity securities,
are reported in current earnings.
Unrealized
gains and losses on available-for-sale securities, which consist almost entirely
of U.S. Government securities, are reported as a component of other
comprehensive income, when significant to the financial statements.
Equity
Investments:
The
Company accounts for its investments in a partnership and limited liability
companies on the equity basis and adjusts the investment balance to agree with
its equity in the underlying assets of the entities. See Note 7 for additional
information.
Receivables and Revenue
Recognition
Oil and
gas sales and resulting receivables are recognized when the product is delivered
to the purchaser and title has transferred. Sales are to credit-worthy major
energy purchasers with payments generally received within 60 days of
transportation from the well site. Historically, the Company has had little, if
any, uncollectible receivables; therefore, an allowance for uncollectible
accounts has not been provided.
Property and
Equipment
Oil and
gas properties are accounted for on the successful efforts method. The
acquisition, exploration and development costs of producing properties are
capitalized. The Company has not, historically, had any capitalized exploratory
drilling costs that are pending determination of reserves for more than one
year. All costs relating to unsuccessful exploration, geological and geophysical
costs, delay rentals and abandoned properties are expensed. Lease costs related
to unproved properties are amortized over the life of the lease and are assessed
for impairment periodically. Any impairment of value is charged to
expense.
Depreciation,
depletion and amortization of producing properties are computed on the
units-of-production method on a property-by-property basis. The
units-of-production method is based, primarily, on estimates of proved reserve
quantities. Due to uncertainties inherent in this estimation process, it is at
least reasonably possible that reserve quantities will be revised in the near
term.
Other
property and equipment are depreciated on the straight-line, declining-balance
or other accelerated methods, as appropriate.
The
following estimated useful lives are used for the different types of
property:
|
Office
furniture & fixtures
|
5
to 10 years
|
|
Automotive
equipment
|
5
to 8 years
|
Impairment
losses are recorded on long-lived assets used in operations when indicators of
impairment are present and the undiscounted cash flows estimated to be generated
by those assets are less than the assets’ carrying amount. See Note 10 for
discussion of impairment losses.
Income
Taxes
The
Company utilizes a liability approach to calculating deferred income taxes.
Deferred income taxes are provided to reflect temporary differences in the basis
of net assets and liabilities for income tax and financial reporting purposes.
Deferred tax assets are reduced by a valuation allowance if a determination is
made that it is more likely than not that some or all of the deferred assets
will not be realized based on the weight of all available evidence.
The Company
recognizes a tax benefit from an uncertain tax position when it is more likely
than not that the position will be sustained upon examination, based upon the
technical merits of the position. The Company will record the largest amount of
tax benefit that is greater than 50% likely of being realized upon settlement
with taxing authorities.
The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The Federal income tax return for 2008 is subject to examination. An audit of the Company’s 2007 Federal income tax return was conducted in 2009 by the Internal Revenue Service. There were no changes to the income tax return as originally filed, nor any changes to the 2007 income tax provision.
The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The Federal income tax return for 2008 is subject to examination. An audit of the Company’s 2007 Federal income tax return was conducted in 2009 by the Internal Revenue Service. There were no changes to the income tax return as originally filed, nor any changes to the 2007 income tax provision.
Earnings Per
Share
Accounting
guidance for Earnings Per Share (EPS) establishes the methodology of calculating
basic earnings per share and diluted earnings per share. The calculations of
basic earnings per share and diluted earnings per share differ in that
instruments convertible to common stock (such as stock options, warrants, and
convertible preferred stock) are added to weighted average shares outstanding
when computing diluted earnings per share. For the years ended December 31, 2009
and 2008, the Company had no dilutive shares outstanding, therefore basic and
diluted earnings per share are the same.
Concentrations of Credit
Risk and Major Customers
The
Company’s receivables relate primarily to sales of oil and natural gas to
purchasers with operations in Texas, Oklahoma, Kansas and South Dakota. The
Company had four purchasers in 2009 and 2008 whose purchases were in excess of
10% of total oil and gas sales.
The
Company maintains its cash in bank deposit accounts, which, at times, may exceed
federally insured limits. The Company has not experienced any losses in such
accounts, and believes that it is not exposed to any significant credit risk
with respect to cash and cash equivalents.
Use of
Estimates
The
preparation of the 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 amounts reported in the financial
statements and accompanying notes. These estimates include oil and natural gas
reserve quantities that form the basis for the calculation of amortization of
oil and natural gas properties. Management emphasizes that reserve estimates are
inherently imprecise and that estimates of more recent reserve discoveries are
more imprecise than those for properties with long production histories. Actual
results could differ from the estimates and assumptions used in the preparation
of the Company’s financial statements.
Gas
Balancing
Gas
imbalances are accounted for under the sales method whereby revenues are
recognized based on production sold. A liability is recorded when the Company’s
excess takes of natural gas volumes exceeds its estimated remaining recoverable
reserves (over produced). No receivables are recorded for those wells where the
Company has taken less than its ownership share of gas production (under
produced).
Guarantees
At the
inception of a guarantee or subsequent modification, the Company records a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The Company records a liability for its obligations when it becomes
probable that the Company will have to perform under the guarantee. The Company
has issued guarantees associated with the Company’s equity investments in
Broadway Sixty-Eight, Ltd. and JAR Investment, LLC.
Asset Retirement
Obligation
The
Company records the fair value of its estimated liability to retire its oil and
natural gas producing properties in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
Subsequently, the asset is amortized to expense over the life of the property.
The liability is accreted annually at 3.25%.
The
following table summarizes the asset retirement obligation for the years ended
December 31:
|
2009
|
2008
|
|||||||
|
Beginning
balance at January 1
|
$ | 516,054 | $ | --- | ||||
|
Liabilities
incurred
|
108,024 | 505,733 | ||||||
|
Liabilities
settled
|
--- | --- | ||||||
|
Accretion
expense
|
20,642 | 10,321 | ||||||
|
Revision
to estimate
|
54,672 | --- | ||||||
|
Ending
balance at December 31
|
$ | 699,392 | $ | 516,054 | ||||
New Accounting
Pronouncements
In June
2009, the FASB issued Accounting Standards Update 2009-01, “The FASB Accounting
Standards Codification and the Hierarchy of Generally Accepted Accounting
Principles (FASB ASC) — a replacement of FASB Statement No. 162” (“ASU
2009-01”). The FASB ASC is intended to be the source of authoritative GAAP and
reporting standards as issued by the FASB. The primary purpose of the FASB ASC
is to improve clarity and use of existing standards by grouping authoritative
literature under common topics. ASU 2009-01 is effective for financial
statements issued for interim and annual periods ending after September 15,
2009. The Codification does not change or alter existing GAAP. The
implementation of ASU 2009-01 had no impact to the Company’s financial position
or results of operations.
In
January 2010, the FASB issued Accounting Standards Update 2010-03 (“ASU
2010-03”) to align the oil and gas reserve estimation and disclosure
requirements of ASC Topic 932, Extractive Industries — Oil and Gas, with the
requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas
Reporting Requirements, which was issued on December 31, 2008, and was
effective for the year ended December 31, 2009. The Modernization of the Oil and Gas
Reporting Requirements was designed to modernize and update the oil and
gas disclosure requirements to align with current practices and changes in
technology. Key provisions of ASU 2010-03 affecting the Company are as
follows:
The new
rules require reserve estimates to be calculated using a 12-month average price.
The use of a 12-month average price rather than a single-day price is intended
to reduce the impact on reserve estimates due to short-term volatility and
seasonality of prices.
The new
rules require the qualifications of any employee, primarily responsible for
preparing or auditing the reserve estimates, to be reported.
The
Company implemented ASU 2010-03, prospectively, as a change in accounting
principle inseparable from a change in accounting estimate at December 31, 2009.
The Company has not determined reserve levels at December 31, 2009, under the
previous accounting rules due to the operational and technical challenges of
preparing reserve reports under two sets of rules; and therefore, it is not
practicable to determine the impact of adopting this accounting
principle.
Reclassifications
Reclassifications
Certain amounts in the 2008 financial statements have been
reclassified to conform to the 2009 presentaion. The amounts were not material
to the financial statements and had no effect on previously reported net
income.
Note 3 –
DIVIDENDS
PAYABLE
Dividends
payable include amounts that are due to stockholders whom the Company has been
unable to locate and uncashed dividend checks of other
stockholders.
Note 4 –
COMMON
STOCK
The
following table summarizes the changes in common stock issued and
outstanding:
|
Shares
of
|
||||||||||||
|
Shares
|
Treasury
|
Shares
|
||||||||||
|
Issued
|
Stock
|
Outstanding
|
||||||||||
|
January
1, 2008, $.50 par value stock, 400,000 shares authorized
|
184,735.28 | 22,209.64 | 162,525.64 | |||||||||
|
Purchase
of stock
|
--- | 347.00 | (347.00 | ) | ||||||||
|
December
31, 2008, $.50 par value stock 400,000 shares authorized
|
184,735.28 | 22,556.64 | 162,178.64 | |||||||||
|
Purchase
of stock
|
--- | 485.00 | (485.00 | ) | ||||||||
|
December
31, 2009, $.50 par value stock 400,000 shares authorized
|
184,735.28 | 23,041.64 | 161,693.64 | |||||||||
Note 5 –
MARKETABLE
SECURITIES
Available-for-sale
securities, consisting almost entirely of U.S. government securities by
contractual maturity are as follows at December 31, 2009:
|
Due
within one year or less
|
$ | 16,070,475 |
For
trading securities, during 2009, the Company recorded realized gains of $38,884
and unrealized gains of $90,557. During 2008, the Company recorded realized
gains of $43,719 and unrealized losses of $(164,318).
Note 6 –
INCOME
TAXES
Components
of deferred taxes follow:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Assets
|
||||||||
|
Leasehold
Costs (net of impairment reserves)
|
$ | 230,736 | $ | 64,774 | ||||
|
Gas
Balancing Receivable
|
52,379 | 52,379 | ||||||
|
Long-Lived
Asset Impairment
|
905,701 | 835,711 | ||||||
|
Marketable
Securities
|
2,284 | 33,123 | ||||||
|
Other
|
153,187 | 73,764 | ||||||
|
Total
Assets
|
1,344,287 | 1,059,751 | ||||||
|
Liabilities
|
||||||||
|
Receivables
|
165,377 | 198,742 | ||||||
|
Intangible
Drilling Costs
|
2,035,500 | 2,248,349 | ||||||
|
Depletion,
Depreciation and Other
|
432,426 | 391,441 | ||||||
|
Total
Liabilities
|
2,633,303 | 2,838,532 | ||||||
|
Net
Deferred Tax Liability
|
$ | (1,289,016 | ) | $ | (1,778,781 | ) | ||
The
following table summarizes the current and deferred portions of income tax
expense:
|
Year Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Current
Tax Provision:
|
||||||||
|
Federal
|
$ | 695,139 | $ | 3,337,569 | ||||
|
State
|
8,602 | 35,100 | ||||||
| 703,741 | 3,372,669 | |||||||
|
Deferred
Provision/(Benefit)
|
(489,766 | ) | 277,192 | |||||
|
Total
Provision
|
$ | 213,975 | $ | 3,649,861 | ||||
The total
provision for income tax expressed as a percentage of income before income tax
was 12% in 2009 and 27% in 2008. These amounts differ from the amounts computed
by applying the statutory U.S. Federal income tax rate of 34% for 2009 and 2008
to income before income tax as summarized in the following
reconciliation:
|
Year Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Computed
Federal Tax Provision
|
$ | 619,267 | $ | 4,521,168 | ||||
|
Increase
(Decrease) in Tax From:
|
||||||||
|
Allowable
Depletion in Excess of Basis
|
(407,974 | ) | (942,714 | ) | ||||
|
Dividend
Received Deduction
|
(650 | ) | (222 | ) | ||||
|
State
Income Tax Provision
|
8,602 | 35,100 | ||||||
|
Other
|
(5,270 | ) | 36,529 | |||||
|
Provision
for Income Tax
|
$ | 213,975 | $ | 3,649,861 | ||||
|
Effective
Tax Rate
|
12 | % | 27 | % | ||||
Note 7 –
EQUITY
INVESTMENTS
The
carrying values of Equity Investments consist of the following at December
31:
|
Ownership %
|
2009
|
2008
|
|||||||||
|
Broadway
Sixty-Eight, Ltd.
|
33% | $ | 479,136 | $ | 451,654 | ||||||
|
JAR
Investment, LLC
|
25% | (2,738 | ) | (5,001 | ) | ||||||
|
Bailey
Hilltop Pipeline, LLC
|
10% | 70,195 | 61,233 | ||||||||
|
OKC
Industrial Properties, LLC
|
10% | 54,716 | 54,698 | ||||||||
| $ | 601,309 | $ | 562,584 | ||||||||
Broadway
Sixty-Eight, Ltd. (the “Partnership”), an Oklahoma limited partnership, owns and
operates an office building in Oklahoma City, Oklahoma. Although the Company
invested as a limited partner, it agreed, jointly and severally, with all other
limited partners to reimburse the general partner for any losses suffered from
operating the Partnership. The indemnity agreement provides no limitation to the
maximum potential future payments. To date, no monies have been paid with
respect to this agreement.
The
Company leases its corporate office from the Partnership. The operating lease,
under which the space was rented, expired December 31, 1995, and the space is
currently rented on a year-to-year basis under the terms of the expired lease.
Rent expense for lease of the corporate office from the Partnership was
approximately $28,000 for each of the years ended December 31, 2009 and
2008.
Included
with Receivables is a Note receivable in the amount of $75,000 from the
Partnership bearing 3.5% interest and due December 31, 2009. On December 31,
2009, the interest due on this note was received along with a new Note
receivable from the Partnership bearing 3.5% interest and due June 30, 2010. The Note
receivable and interest rate included with Receivables at December 31, 2008, was
$125,000 with a 5% rate. This related party transaction is connected to the
construction of a new office building.
JAR
Investment, LLC (JAR), an Oklahoma limited liability company, previously held
Oklahoma City metropolitan area real estate that was sold in June 2005 (see
below). JAR also owns a 70% management interest in Main-Eastern, LLC (M-E), an
Oklahoma limited liability company. M-E was formed in 2002 to establish a joint
venture to develop a retail/commercial center on a portion of JAR’s real
estate.
The
Company has a guarantee agreement limited to 25% of JAR’s 70% interest in M-E’s
outstanding loan, plus all costs and expenses related to enforcement and
collection or $133,409 at December 31, 2009. This loan matures December 27,
2013. The Company has evaluated its guarantee related to this obligation and
believes it is unlikely to have to make any payments under the provisions of the
guarantee agreement.
In June
2008, the Company purchased a 10% ownership in Bailey Hilltop Pipeline, LLC (the
“Pipeline”) for $51,541. The Pipeline was constructed for the transportation of
gas from wells in the Bailey Hilltop prospect.
OKC
Industrial Properties, LLC, an Oklahoma limited liability company, holds certain
Oklahoma City metropolitan area real estate as an investment.
|
Note
8 –
|
COSTS INCURRED IN OIL
AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT
ACTIVITIES
|
All of
the Company’s oil and gas operations are within the continental United States.
In connection with its oil and gas operations, the following costs were
incurred:
|
Year Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Acquisition
of Properties:
|
||||||||
|
Unproved
|
$ | 496,586 | $ | 361,685 | ||||
|
Proved
|
$ | --- | $ | --- | ||||
|
Exploration
Costs
|
$ | 1,618,080 | $ | 981,032 | ||||
|
Development
Costs
|
$ | 2,075,048 | $ | 3,846,320 | ||||
|
Asset
Retirement Obligation
|
$ | 162,696 | $ | 516,054 | ||||
Note 9 –
FAIR VALUE
MEASUREMENTS
Inputs
used to measure fair value are organized into a fair value hierarchy based on
how observable the inputs are. Level 1 inputs consist of quoted prices in active
markets for identical assets. Level 2 inputs are inputs, other than quoted
prices for similar assets that are observable. Level 3 inputs are unobservable
inputs.
Recurring
Fair Value Measurements
Certain
of the Company’s assets are reported at fair value in the accompanying balance
sheets on a recurring basis. At December 31, 2009 and 2008, the Company’s assets
reported at fair value on a recurring basis are summarized as
follows:
|
2009
|
||||||||||||
|
Level 1 Inputs
|
Level 2 Inputs
|
Level 3 Inputs
|
||||||||||
|
Financial
Assets:
|
||||||||||||
|
Available-for-sale
securities
|
$ | --- | $ | 16,070,475 | $ | --- | ||||||
|
Trading
securities
|
$ | 350,372 | $ | --- | $ | --- | ||||||
|
2008
|
||||||||||||
|
Level 1 Inputs
|
Level 2 Inputs
|
Level 3 Inputs
|
||||||||||
|
Financial
Assets:
|
||||||||||||
|
Available-for-sale
securities
|
$ | --- | $ | 15,120,573 | $ | --- | ||||||
|
Trading
securities
|
$ | 218,228 | $ | --- | $ | --- | ||||||
Non-recurring
Fair Value Measurements
The
Company’s asset retirement obligations incurred annually represent non-recurring
fair value liabilities. The fair value of these non-financial liabilities
incurred was $108,024 in 2009 and $505,733 in 2008 and was calculated using
Level 3 inputs. See Note 2 above for more information about this liability and
the inputs used for calculating fair value.
Fair
Value of Financial Instruments
The
Company’s financial instruments consist primarily of cash and cash equivalents,
trade receivables, marketable securities, trade payables and dividends payable.
As of December 31, 2009 and 2008, the historical cost of cash and cash
equivalents, trade receivables, trade payables and dividends payable are
considered to be representative of their respective fair values due to the
short-term maturities of these items.
Note 10 –
LONG-LIVED ASSETS
IMPAIRMENT LOSS
Certain
oil and gas producing properties have been deemed to be impaired because the
assets, evaluated on a property-by-property basis, are not expected to recover
their entire carrying value through future cash flows. Impairment losses
totaling $1,353,020 for the year ended December 31, 2009, and $1,924,219 for the
year ended December 31, 2008, are included in the Statements of Income in the
line item, Depreciation, Depletion, Amortization and Valuation Provisions. The
impairments for 2009 and 2008 were calculated by reducing the carrying value of
the individual properties to an estimated fair value equal to the discounted
present value of the future cash flow from these properties. An average monthly
price was used for calculating future revenue and cash flow.
Note 11 –
OTHER INCOME,
NET
The
following is an analysis of the components of Other Income, Net for the years
ended December 31, 2009 and 2008:
|
2009
|
2008
|
|||||||
|
Net
Realized and Unrealized Gain (Loss) on Trading Securities
|
$ | 129,441 | $ | (120,599 | ) | |||
|
Gain
on Asset Sales
|
12,950 | 452,476 | ||||||
|
Interest
Income
|
73,528 | 339,126 | ||||||
|
Settlements
of Class Action Lawsuits
|
24,946 | 1,674 | ||||||
|
Agricultural
Rental Income
|
5,600 | 5,600 | ||||||
|
Dividend
and Other Income
|
2,732 | 931 | ||||||
|
Interest
and Other Expenses
|
(25,219 | ) | (4,348 | ) | ||||
|
Other
Income, Net
|
$ | 223,978 | $ | 674,860 | ||||
Note 12 –
CERTAIN RELATIONSHIPS
AND RELATED TRANSACTIONS
The
Company is affiliated by common management and ownership with Mesquite Minerals,
Inc. (Mesquite), Mid-American Oil Company (Mid-American), Lochbuie Limited
Partnership (LLTD) and Lochbuie Holding Company (LHC). The Company also owns
interests in certain producing and non-producing oil and gas properties as
tenants in common with Mesquite, Mid-American and LLTD.
Mesquite,
Mid-American and LLTD share facilities and employees, including executive
officers, with the Company. The Company has been reimbursed for services,
facilities and miscellaneous business expenses incurred during 2009 by payment
to the Company in the amount of $146,217 by Mesquite, $146,217 by Mid-American
and $146,217 by LLTD. Reimbursements for 2008 were $149,195 by Mesquite,
$149,195 by Mid-American and $149,195 by LLTD. Included in the 2009 amounts,
Mesquite paid $106,528, Mid-American $106,528 and LLTD $106,528 for their share
of salaries. In 2008, the share of salaries paid by Mesquite was $108,794,
Mid-American $108,794 and LLTD $108,794.
UNAUDITED
SUPPLEMENTAL FINANCIAL INFORMATION
SUPPLEMENTAL
SCHEDULE 1
THE
RESERVE PETROLEUM COMPANY
WORKING
INTERESTS RESERVE QUANTITY INFORMATION
(Unaudited)
|
Year Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Oil
& Natural Gas Liquids (Bbls)
|
||||||||
|
Proved
Developed and Undeveloped Reserves:
|
||||||||
|
Beginning
of Year
|
266,865 | 290,989 | ||||||
|
Revisions
of Previous Estimates
|
16,320 | (1,829 | ) | |||||
|
Extensions
and Discoveries
|
42,411 | 45,035 | ||||||
|
Sales
of Reserves
|
--- | (996 | ) | |||||
|
Production
|
(65,432 | ) | (66,334 | ) | ||||
|
End
of Year
|
260,164 | 266,865 | ||||||
|
Proved
Developed Reserves:
|
||||||||
|
Beginning
of Year
|
266,865 | 290,989 | ||||||
|
End
of Year
|
260,164 | 266,865 | ||||||
|
Gas
(MCF)
|
||||||||
|
Proved
Developed and Undeveloped Reserves:
|
||||||||
|
Beginning
of Year
|
1,555,422 | 1,664,360 | ||||||
|
Revisions
of Previous Estimates
|
179,859 | 119,180 | ||||||
|
Extensions
and Discoveries
|
475,205 | 291,743 | ||||||
|
Sales
of Reserves
|
--- | (123,902 | ) | |||||
|
Production
|
(399,946 | ) | (395,959 | ) | ||||
|
End
of Year
|
1,810,540 | 1,555,422 | ||||||
|
Proved
Developed Reserves
|
||||||||
|
Beginning
of Year
|
1,555,422 | 1,664,360 | ||||||
|
End
of Year
|
1,810,540 | 1,555,422 | ||||||
See notes
on next page.
SUPPLEMENTAL
SCHEDULE 1
THE
RESERVE PETROLEUM COMPANY
WORKING
INTERESTS RESERVE QUANTITY INFORMATION
(Unaudited)
Notes:
|
|
1.
|
Estimates
of royalty interests’ reserves have not been included because the
information required for the estimation of said reserves is not available.
The Company’s share of production from its net royalty interests was
14,145 Bbls of oil and 897,388 MCF of gas for the year ended December 31,
2009, and 14,004 Bbls of oil and 1,056,409 MCF of gas for the year ended
December 31, 2008.
|
|
|
2.
|
The
preceding table sets forth estimates of the Company’s proved developed oil
and gas reserves, together with the changes in those reserves, as prepared
by the Company’s engineer, for the years ended December 31, 2009 and 2008.
The Company engineer’s qualifications in the Proxy Statement are
incorporated herein by reference. All reserves are located within the
United States.
|
|
|
3.
|
The
Company emphasizes that the reserve volumes shown are estimates, which by
their nature are subject to revision in the near term. The estimates have
been made by utilizing geological and reservoir data, as well as actual
production performance data available to the Company. These estimates are
reviewed annually and are revised upward or downward as warranted by
additional performance data. The Company’s engineer is not independent,
but strives to use an objective approach in calculating the Company’s
working interest reserve estimates.
|
|
|
4.
|
As
of the date of this Form 10-K, the Company has limited internal controls
relating to the calculation of its working interests' reserves estimates.
However, management reviewed internal controls relative to accounting data
flowing into the calculation of the reserves estimates. Management
concluded the existing internal controls were effective enough to ensure
the weakness indentified was not material, was mitigated, and was not
significant enough to cause a material misstatement in the financial
statements. Management will review our internal controls and consider
possibly strengthening our internal controls in 2010 relative to the
reserves estimation process.
|
SUPPLEMENTAL
SCHEDULE 2
THE
RESERVE PETROLEUM COMPANY
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING
TO PROVED WORKING INTERESTS
OIL AND
GAS RESERVES
(Unaudited)
|
At December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Future
Cash Inflows
|
$ | 19,706,075 | $ | 15,536,365 | ||||
|
Future
Production and Development Costs
|
(7,793,116 | ) | (6,406,107 | ) | ||||
|
Future
Income Tax Expense
|
(2,135,115 | ) | (1,695,833 | ) | ||||
|
Future
Net Cash Flows
|
9,777,844 | 7,434,425 | ||||||
|
10%
Annual Discount for Estimated Timing of Cash Flows
|
(2,636,067 | ) | (2,157,644 | ) | ||||
|
Standardized
Measure of Discounted Future Net Cash Flows
|
$ | 7,141,777 | $ | 5,276,781 | ||||
Estimates
of future net cash flows from the Company’s proved working interests in oil and
gas reserves are shown in the table above. For 2008, these estimates, which by
their nature are subject to revision in the near term, were based on prices in
effect at December 31, 2008, with no escalation. For 2009, these estimates were
based on an average monthly product price received by the Company for the twelve
months ended December 31, 2009, with no escalation. The development and
production costs are based on year-end cost levels, assuming the continuation of
existing economic conditions. Cash flows are further reduced by estimated future
income tax expense calculated by applying the current statutory income tax rates
to the pretax net cash flows, less depreciation of the tax basis of the
properties and depletion applicable to oil and gas production.
The
change in method of calculating the estimated product prices in 2009 from 2008
is due to the Company adopting the reserve estimation and disclosure
requirements of ASC Topic 932, Extractive Industries – Oil and Gas,
prospectively, on December 31, 2009. See Item 8, Note 2 to the accompanying
financial statements for additional information on this matter.
SUPPLEMENTAL
SCHEDULE 3
THE
RESERVE PETROLEUM COMPANY
CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH
FLOWS FROM PROVED WORKING INTERESTS RESERVE QUANTITIES
(Unaudited)
|
Year Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Standardized
Measure, Beginning of Year
|
$ | 5,276,781 | $ | 12,802,235 | ||||
|
Sales
and Transfers, Net of Production Costs
|
(3,530,056 | ) | (7,642,024 | ) | ||||
|
Net
Change in Sales and Transfer Prices, Net of Production
Costs
|
1,971,696 | (7,179,892 | ) | |||||
|
Extensions,
Discoveries and Improved Recoveries, Net of Future Production and
Development Costs
|
1,978,755 | 1,401,574 | ||||||
|
Revisions
of Quantity Estimates
|
714,279 | 212,149 | ||||||
|
Accretion
of Discount
|
648,048 | 1,687,571 | ||||||
|
Sales
of Reserves in Place
|
--- | (394,649 | ) | |||||
|
Net
Change in Income Taxes
|
(355,786 | ) | 2,869,772 | |||||
|
Changes
in Production Rates (Timing) and Other
|
438,060 | 1,520,045 | ||||||
|
Standardized
Measure, End of Year
|
$ | 7,141,777 | $ | 5,276,781 | ||||
|
ITEM 9.
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
|
None.
|
ITEM 9A.(T).
|
CONTROLS
AND PROCEDURES
|
Disclosure
Controls and Procedures
As
defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934
(the "Exchange Act"), the term "disclosure controls and procedures" means
controls and other procedures of an issuer that are designed to ensure that
information required to be disclosed by the issuer in the reports that it files
or submits under the Exchange Act is recorded, processed, summarized and
reported, within the time periods specified in the SEC's rules and forms.
Disclosure controls and procedures include, without limitation, controls and
procedures designed to ensure that information required to be disclosed by an
issuer in the reports that it files or submits under the Exchange Act is
accumulated and communicated to the issuer's management, including its principal
executive and principal financial officers, or persons performing similar
functions, as appropriate to allow timely decisions regarding required
disclosure.
The
Company's Principal Executive Officer and Principal Financial Officer evaluated
the effectiveness of the Company's disclosure controls and procedures and
concluded that the Company's disclosure controls and procedures were effective
as of December 31, 2009.
Changes
in Internal Control over Financial Reporting
There
were no changes in the Company’s internal control over financial reporting
during the quarter ended December 31, 2009, that have materially affected, or
are reasonably likely to materially affect, the Company's internal control over
financial reporting.
Management's
Annual Report on Internal Control over Financial Reporting
The
management of The Reserve Petroleum Company is responsible for establishing and
maintaining adequate internal control over financial reporting for the Company
as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is
designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in
accordance with accounting principles generally accepted in the United States of
America.
The
Company's internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the
assets of the Company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the Company are being made only in accordance with
authorizations of management and the directors of the Company; and (iii) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the Company's assets that could have a
material effect on the financial statements, and provide reasonable assurance as
to the detection of fraud.
Because
of its inherent limitations, a system of internal control over financial
reporting can provide only reasonable assurance and may not prevent or detect
misstatements. Further, because of changes in conditions, effectiveness of
internal controls over financial reporting may vary over time.
With the
participation of the Chief Executive Officer and Chief Financial Officer, the
Company’s management conducted an evaluation of the effectiveness of the
Company’s internal control over financial reporting based on the framework and
criteria established in Internal Control-Integrated
Framework, issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on this evaluation, the Company’s management
concluded that the Company's internal control over financial reporting was
effective as of December 31, 2009.
This
Annual Report on Form 10-K does not include an attestation report of the
Company’s independent registered public accounting firm regarding internal
control over financial reporting. Management’s report was not subject to
attestation by the Company’s independent registered public accounting firms
pursuant to temporary rules of the Securities and Exchange Commission that
permit the Company to provide only management’s report in this Annual Report on
Form 10-K.
|
/s/ Cameron R. McLain
|
/s/ James L. Tyler
|
||
|
Cameron
R. McLain, President
|
James
L. Tyler, 2nd
Vice President
|
||
|
Principal
Executive Officer
|
Principal
Financial Officer
|
||
|
March
31, 2010
|
March
31, 2010
|
||
|
ITEM 9B.
|
OTHER
INFORMATION
|
None.
PART III
|
ITEM
10.
|
DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
|
Information
regarding directors and executive officers, compliance with Section 16(a) of the
Exchange Act, the Company’s Code of Ethics and Corporate Governance in the Proxy
Statement is incorporated herein by reference.
|
ITEM 11.
|
EXECUTIVE
COMPENSATION
|
Information
regarding executive compensation in the Proxy Statement is incorporated herein
by reference.
|
ITEM 12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
|
Information
regarding security ownership of certain beneficial owners and management and
related stockholder matters in the Proxy Statement is incorporated herein by
reference.
|
ITEM 13.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
|
See Item
7, “Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and Item 8, Note 12 to Financial Statements. Information regarding
the independence of our directors in the Proxy Statement is incorporated herein
by reference.
|
ITEM 14.
|
PRINCIPAL
ACCOUNTANT FEES AND SERVICES
|
Information
regarding fees billed to the Company by its independent registered public
accounting firm in the Proxy Statement is incorporated herein by
reference.
PART IV
|
ITEM
15.
|
EXHIBITS
AND FINANCIAL STATEMENT SCHEDULES
|
The
following documents are exhibits to this Form 10-K. Each document marked by an
asterisk is filed electronically herewith.
| Exhibit Number |
Description
|
||
|
3.1
|
Restated
Certificate of Incorporation dated November 1, 1988, is incorporated by
reference to Exhibit 3.1 of The Reserve Petroleum Company’s Annual Report
on Form 10-KSB (Commission File No. 0-8157) filed March 28,
1997.
|
||
|
3.2
|
Amended
By-Laws dated November 16, 2004, are incorporated by reference to Exhibit
3.2 of The Reserve Petroleum Company’s Annual Report on Form 10-KSB
(Commission File No. 0-8157) filed March 30, 2006.
|
||
|
14
|
Code
of Ethics incorporated by reference to Exhibit 14 of The Reserve Petroleum
Company’s Annual Report on Form 10-KSB (Commission File No. 0-8157) filed
March 30, 2006.
|
||
|
Certification
of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a)
under the Securities Exchange Act of 1934, as amended.
|
|||
|
Certification
of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a)
under the Securities Exchange Act of 1934, as amended.
|
|||
|
Certification
of Principal Executive Officer and Principal Financial Officer Pursuant to
18 U.S.C. Section 1350.
|
|||
SIGNATURES
In
accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
|
THE
RESERVE PETROLEUM COMPANY
|
|||
|
(Registrant)
|
|||
|
/s/
|
Cameron R. McLain
|
||
|
By:
|
Cameron
R. McLain, President
|
||
|
(Principal
Executive Officer)
|
|||
|
/s/
|
James L. Tyler
|
||
|
By:
|
James
L. Tyler, 2nd
Vice President
|
||
|
(Principal
Financial Officer)
|
|||
Date: March
31, 2010
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the Registrant and in the
capacities and on the dates indicated:
|
/s/ Mason McLain
|
/s/ Jerry L. Crow
|
||
|
Mason
W. McLain (Director)
|
Jerry
L. Crow (Director)
|
||
|
March
31, 2010
|
March
31, 2010
|
|
/s/ Robert L. Savage
|
/s/ William M. Smith
|
||
|
Robert
L. Savage (Director)
|
William
M. Smith (Director)
|
||
|
March
31, 2010
|
March
31, 2010
|
51