UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
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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, 2008
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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. Yes
o
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. Yes
þ
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 Yes
o
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Non
accelerated filer
o
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Smaller
reporting company
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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 $26,110,000, as computed
by reference to the last reported sale which was on March 24, 2009.
As of
March 25, 2009, there were 162,151.64 shares of the registrant’s common stock
outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the definitive proxy statement relating to the registrant’s Annual Meeting of
Shareholders to be held on May 19, 2009, which will be filed within 120 days of
the end of the registrant’s fiscal year ended December 31, 2008 (the “Proxy
Statement”) are incorporated by reference into Part III of this Form 10-K to the
extent described therein.
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TABLE
OF
CONTENTS
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Page
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Forward
Looking Statements
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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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6
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Item
3.
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7
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Item
4.
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7
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PART
II
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Item
5.
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8
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Item
6.
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9
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Item
7.
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9
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Item
7A.
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23
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Item
8.
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23
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Item
9.
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49
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Item
9A.(T).
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49
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Item
9B.
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50
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PART
III
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Item
10.
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50
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Item
11.
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50
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Item
12.
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50
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Item
13.
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50
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Item
14.
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51
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PART
IV
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Item
15.
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51
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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
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 approximately 262,063 gross
acres equivalent to 90,327 net acres. These mineral interests are
located in nine different states in the north and south central United
States. A total of 64,763 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 2008, $10,406,544 (53%) of oil
and gas sales was from royalty interests as compared to $7,563,107 (54%) in
2007. As a result of its mineral ownership, the Company had royalty
interests in 33 gross (1.13 net) wells which were drilled and completed as
producing wells in 2008. This resulted in an average royalty
interest of about 3.4% for these 33 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 development of additional wells on the exploratory prospect. In
2008, the Company participated in the drilling of nineteen development wells
with twelve wells (1.85 net) completed as producers and seven (1.14 net) in
progress. The five wells (.835 net) that were in progress at the end of 2007
were all completed as producers.
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 2008 the Company
participated in the drilling of seventeen exploration wells with seven wells
(1.07) completed as producers, one (.11 net) completed as a dry hole and nine
(.99 net) in progress. The one well (.16 net) still drilling at the end of 2007
was completed as a producer.
For a
summation of exploratory and development wells drilled in 2008 or planned for in
2009, 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, 2007.”
Customers
In 2008,
the Company had four customers whose total purchases were greater than 10% of
revenues from oil and gas sales. Redland Resources, Inc. purchases
were $3,923,381 or 20% of total oil and gas sales. ConocoPhillips Company
purchases were $3,820,151 or 19% of total oil and gas sales. Encana
Oil and
Gas, Inc. purchases were $2,634,748 or 13% of total oil and gas sales. Luff
Exploration Company purchases were $2,295,254 or 12% 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
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 regulation in future periods. However, the known effect to date
has not been material as to capital expenditures, earnings or industry
competitive position, nor are estimated expenditures for environmental
compliance expected to be material in the coming year. Such
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.
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, 2008, the Company had eight employees, including
officers. See the Proxy Statement for additional
information. During 2008, 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.
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
COMMENTS.
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Smaller
reporting companies are not required to provide the information required by this
Item.
The
Company’s principal properties are oil and natural gas
properties. The Company has interests in approximately 565
producing properties, with one-third of them being working interest properties
and the remaining two-thirds being royalty interest properties. About
89% of these properties are located in Oklahoma and Texas and account for
approximately 82.4% of the Company’s annual oil and gas sales. About
5% of the properties are located in Kansas and South Dakota and account for
approximately 16.3% 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 about 1.3% of the Company’s annual oil and gas
sales. No individual property provides more than 8% 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 44
for working interest reserve quantity information.
Since
January 1, 2008, 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 2007 annual report on Form 10-K and Federal income tax
return for the year ended December 31, 2007. 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, 2008, 2007 and 2006. 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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2008
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$96.80
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$8.41
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$91.10
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$7.95
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$2.10
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2007
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$67.35
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$6.19
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$65.71
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$6.63
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$1.65
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2006
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$62.72
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$6.06
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$59.68
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$6.63
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$1.65
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At
December 31, 2008, the Company had working interests in 130 gross (15.49 net)
wells producing primarily gas and had working interests in 103 gross (9.10 net)
wells producing primarily oil. These interests were in 51,002 gross
(6,302 net) producing acres. These wells include 42 gross (.41 net)
wells associated with secondary recovery projects.
Seven
percent or 5,907 barrels of the Company’s oil production during 2008 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, 2008.
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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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262,063
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90,327
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Undeveloped
Leaseholds
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45,583
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6,398
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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, 2006 and thereafter, as to net
productive and dry exploratory wells drilled and net productive and dry
development wells drilled. Net productive exploratory and development totals for
2008 include the six wells still drilling at the end of 2007. As indicated in
the “Development Program” and “Exploration Program” on page 4, seven development
wells and nine 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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2008
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1.23
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.11
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2.69
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---
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2007
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---
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.20
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1.95
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---
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2006
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.22
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.33
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2.02
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.10
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Recent
Activities
See Item
7, under the subheading, “Update of Oil and Gas Exploration and Development
Activity from December 31, 2007” 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 pending legal proceedings affecting the Company or any of its
properties.
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ITEM
4.
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SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS
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None.
PART
II
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ITEM
5.
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MARKET FOR REGISTRANT’S
COMMON EQUITY, RELATED STOCKHOLDER
M
ATTERS 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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03/31/07
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170.00
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145.00
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06/30/07
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200.00
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155.00
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09/30/07
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257.00
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191.25
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12/31/07
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300.00
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255.00
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03/31/08
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325.00
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260.00
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06/30/08
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440.00
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315.00
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09/30/08
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412.00
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330.00
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12/31/08
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360.00
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225.00
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There was
limited public trading in the Company’s common stock in 2008 and
2007. In 2008 there were 36 brokered trades appearing in the
Company’s transfer ledger, versus 14 in 2007.
At March
25, 2009, the Company had approximately 1,438 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 and $30.00 per share in the third
quarter of 2008 and $6.00 per share in 2007. See the “Financing Activities”
section of Item 7. below for more information about the 2008 dividend.
Management will review the amount of the annual dividend to be paid in 2009 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 Programs
(1)
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Approximate
Dollar Value of Shares that May Yet Be Purchased Under the Plans or
Programs (1)
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Oct 1,
2008 to Oct 31, 2008
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88
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$250.00
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-
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-
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Nov
1, 2008 to Nov 30, 2008
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-
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-
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-
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-
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Dec
1, 2008 to Dec 31, 2008
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4
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$250.00
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-
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-
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Total
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92
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$250.00
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-
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-
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(1)
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The
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:
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.
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.
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.
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.
The
provisions for depreciation, depletion and amortization of oil and gas
properties constitute a particularly sensitive accounting
estimate. 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.
Forward-looking estimates of such adjustments are very imprecise. 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,
Income
from available for sale securities and trading securities has made substantial
contributions to net income in certain prior periods. Available for
sale securities and trading securities are used to invest funds until needed in
the Company’s capital investing and financing activities. Net
income has been materially affected in past years and could be in the future
years by utilization of those funds in operations as well as significant
fluctuation in the interest rates and/or quoted market values applicable to the
Company’s available for sale securities and trading securities.
The
Company’s trading securities consist primarily of equity
securities. These securities are carried at fair value with
unrealized gains and losses included in earnings. The equity
securities are traded on various stock exchanges and/or the NASDAQ and over the
counter markets. Therefore, these securities are market-risk
sensitive instruments. The stock market is subject to wide price
swings in short periods of time.
The
Company has equity investments in organizations over which the Company has
limited or no control. These equity investments have in the past made
substantial contributions to the Company’s net income. The management
of these entities could at any time make decisions in their own best interests
which could materially 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.
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 2009 and any Current Reports on Form 8-K filed by the
Company.
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 is a more than 5% owner 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 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 2008,
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. Available for sale securities are US Treasury
Bills.
In 2008,
net cash provided by operating activities was $13,543,730. Sales, net of
production, exploration, general and administrative costs and income taxes paid
were $12,214,609, which accounted for 90% of the operations net cash
flow. The remaining components provided $1,329,121 or 10% of cash
flow. In 2008, net cash applied to investing activities was
$7,416,157. Net purchases of available for sale securities discussed below and
capitalized property additions (net of disposals) accounted for $7,246,166 of
the total net cash applied to investing activities. Maturing available for sale
securities provided $26,632,838 of gross cash flow due to their six month
maturities. However, these funds plus $2,675,042 of excess cash from
operations were re-invested in the same type of securities.
In 2008,
cash utilized for capitalized property additions (net of disposals) was
$4,571,124. Dividend payments and treasury stock purchases totaled $5,929,117
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 decreased $118,973 (35%) to $218,228 in 2008 from $337,201 in 2007.
All of the decrease is due to a $164,318 increase in unrealized losses which
represent the change in the market value of the securities from their original
cost. The losses were offset by $45,345 which represents the earnings from the
securities plus the net realized gains for the year. All earnings and
net realized gains are reinvested in additional securities.
Receivables
decreased $573,467 (25%) to $1,738,856 in 2008 from $2,312,323 in
2007. The decrease was mostly due to lower average monthly sales in
the fourth quarter of 2008 versus 2007. Average monthly oil and
natural gas sales for the fourth quarter of 2008 were about $950,000 compared to
about $1,340,000 for the fourth quarter of 2007. The receivables
balance at December 31, 2008 includes about 1.6 months of oil and natural gas
sales accruals. See the discussion of revenues under subheading
“Operating Revenues”, below for more information about the sales of oil and
natural gas, including the wells in Robertson County, Texas and the lower
product prices experienced at December 31, 2008.
Refundable
income taxes were $999,573 in 2008 versus a $153,094 payable balance in
2007. This was due to timing and an overpayment of the fourth quarter
estimated tax payments in 2008 versus an underpayment in 2007.
Prepaid
expenses of $103,373 in 2007 were prepaid seismic expenses on the Harper County,
Kansas prospect discussed in the “Update of Oil and Gas Exploration and
Development Activity from December 31, 2007” in the “Results of Operations”
section below. The seismic survey work was completed in September, 2008 and
there were no similar prepaid expenses at December 31, 2008.
Accounts
payable decreased $95,801 (31%) to $208,487 in 2008 from $304,288 in
2007. This decrease was primarily due to decreased drilling activity
at year end 2008 versus 2007. See the discussion of this activity
under “Update of Oil and Gas Exploration and Development Activity from December
31, 2007” in the “Results of Operations” section below.
Deferred
income taxes and other, decreased $158,566 (42%) to $221,266 in 2008 from
$379,832 in 2007. Deferred income taxes decreased $167,286 because of the tax
effect of decreased sales accruals and the unrealized losses on trading
securities. This decrease was offset by an increase of $10,000 in the
accrual for some delayed 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, 2008 and 2007. 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 2008 were $13,543,730,
which when compared to the $9,488,931 provided in 2007, represents an increase
of $4,054,799 or 43%. The increase resulted because of an increase in
oil and gas sales cash flows of $6,213,997, an increase in lease bonuses and
coal royalties of $505,322 and a decrease in exploration costs of $328,947.
Those increases in cash flows were partially offset by increased production
costs of $574,364, an increase in general, administrative, taxes and other
expenses of $114,432, an increase in income taxes paid of $2,209,126 and a
decrease in interest income of $96,956. Additional discussion of the more
significant items follows.
Discussion
of Selected Material Line Items Resulting in an Increase in Cash
Flows.
The $6,213,997 (44%) increase in cash received from oil
and gas sales to $20,457,619 in 2008 from $14,243,622 in 2007 was the result of
an increase 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 increased $505,322 (117%) to
$936,685 in 2008 from $431,363 in 2007. Most of the increase is due to an
increase in cash received for lease bonuses of about $534,000 in 2008 versus
2007. This increase was offset by a decline in the cash received for coal
royalties of $29,068 to $191,960 in 2008 from $221,028 in 2007.
Cash flow
increased due to a decrease in cash paid for exploration expenses of $328,947
(96%) to $12,046 in 2008 from $340,993 in 2007. About $97,000 of the
decrease was due to lower geological and geophysical expense in 2008 versus 2007
due mostly to the prepaid seismic balance at 2007 year end. The remaining
decrease of about $232,000 was due to lower dry hole costs in 2008 versus
2007.
Discussion
of Selected Material Line Items Resulting in a Decrease in Cash
Flows.
Cash paid for production costs increased $574,364 (34%)
to $2,248,936 in 2008 from $1,674,572 in 2007. Most of the increase
was due to a $248,199 increase in lease operating expenses and handling expenses
and an increase of $326,165 in production taxes in 2008 versus
2007. Most of the lease operating expense increase was attributable
to wells which first produced in 2008 and late 2007. The increase in
production taxes was due to increased sales in 2008 versus
2007.
Cash paid
for general suppliers, employees and taxes other than income taxes increased
$114,432 (9%) to $1,456,691 in 2008 from $1,342,259 in 2007. Most of this
increase is due to an increase in salaries and employee benefits of about
$114,000 to $764,000 paid in 2008 versus $650,000 paid in 2007.
Cash
received for interest earned on cash equivalents and available for sale
securities decreased $96,956 (20%) to $390,206 in 2008 from $487,162 in
2007. The decrease was the result of a decrease in the average rate
of return to 2.41% in 2008 from 4.29% in 2007 offset by an increase in the
average balance of cash equivalents and available for sale securities
outstanding to $16,219,149 in 2008 from $11,351,296 in 2007.
Income
taxes paid increased $2,209,126 (95%) to $4,525,337 in 2008 from $2,316,211 in
2007 due to increased income tax expense and estimated tax payments discussed
above and below in “Results of Operations”.
Investing
Activities
Net cash
applied to investing activities decreased $1,151,853 (13%) to $7,416,157 in 2008
from $8,568,010 in 2007. In 2008, net cash applied to available for
sale securities decreased $2,297,237 from $4,972,279 in 2007 to $2,675,042 in
2008. This decline was a result of utilizing a larger portion of the operations
cash flow for financing activities in 2008 as discussed below. Cash
flows related to property acquisitions resulted in an increase in cash
applications to investing activities in 2008 versus 2007. Cash applied to
property acquisitions increased $1,284,671 (33%) to $5,163,043 in 2008 from
$3,878,372 in 2007 due primarily to increased exploration and development
drilling activity. See the “Update of Oil and Gas Exploration and
Development Activity from December 31, 2007” under the “Results of Operations”
heading below for more information regarding expenditures related to this
drilling activity. Cash flow from property dispositions increased $567,903 to
$591,919 in 2008 from $24,016 in 2007 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 2007. The increases in cash applications for investing activities also
included a decrease in cash distributions from equity investments of $252,075
(97%) to $6,550 in 2008 from $258,625 in 2007. This decrease is due to a
$225,000 distribution in 2007 from Millennium Golf Properties, LLC representing
the proceeds from the sale of our 9% ownership interest to the remaining owners
in the limited liability company. There were no similar sales or distributions
in 2008.
Financing
Activities
Cash
applied to financing activities increased $4,918,865 (487%) to $5,929,117 in
2008 from $1,010,252 in 2007. Cash flows applied to financing
activities consist of cash dividends on common stock and cash used for the
purchase of treasury stock. In 2008, cash dividends paid on common
stock amounted to $5,857,097 as compared to $883,052 in
2007. The increase was the result of an increase in the 2008
dividends per share to $40.00 from $6.00 in 2007. The increase was necessary to
distribute to the Company’s shareholders a portion of the funds from operating
activities cash flow that was in excess of the funds needed for investing
activities. The cash applied to the purchase of treasury stock was
$72,020 in 2008 as compared to $127,200 in 2007. The decrease in
treasury stock purchases in 2008 from 2007 is due to a combination of fewer
shares purchased in 2008 (347 shares) versus 2007 (795 shares) and a higher
average price paid in 2008 of $208 per share versus $160 per share in
2007. For additional information about treasury stock
purchases, see Note (1) 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 2009 and beyond indicates the
projected activity can be funded from cash flow from operations and other
internal sources including net working capital. See additional
discussion of 2009 operating income estimates below at the end of the “Operating
Revenues” section. 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 2008
the Company had net income of $9,647,693 as compared to a net income of
$7,527,876 in 2007. Net income per share, basic and diluted was
$59.43 in 2008, an increase of $13.18 per share from $46.25 in
2007. Material line item changes in the Statements of Operations will
be discussed in the following paragraphs.
Operating
Revenues
Operating
revenues increased $6,373,292 (44%) to $20,706,010 in 2008 from $14,332,718 in
2007. Oil and gas sales increased $5,801,876 (42%) to $19,717,442 in 2008 from
$13,915,566 in 2007. Lease bonuses and other revenues increased
$571,416 (137%) to $988,568 in 2008 from $417,152 in 2007. This increase was the
result of an increase in lease bonuses of $532,946 due to increased bonuses from
East Texas, Oklahoma and Colorado leases. In addition, coal royalties
from North Dakota leases increased $38,470 (19%) to $245,287 in 2008 from
$206,817 in 2007. The Company does not anticipate that coal royalties will have
a significant impact on its future results of operations. The
increase in oil and gas sales will be discussed in the following
paragraphs.
The
$5,801,876 increase in oil and gas sales was the net result of a $3,229,778
increase in gas sales plus a $2,446,578 increase in oil sales and a $125,520
increase 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 2007 to 2008. Miscellaneous oil and gas product sales of
$289,763 in 2008 and $164,243 in 2007 are not included in the
analysis.
|
|
|
|
|
|
Variance
|
|
|
|
|
|
Production
|
|
2008
|
|
|
Price
|
|
|
Volume
|
|
|
2007
|
|
|
Gas
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MCF
(000 omitted)
|
|
1,452
|
|
|
|
|
|
55
|
|
|
1,397
|
|
|
$(000
omitted)
|
|
$12,029
|
|
|
$2,882
|
|
|
$348
|
|
|
$8,799
|
|
|
Unit
Price
|
|
$8.28
|
|
|
$1.98
|
|
|
|
|
|
$6.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bbls
(000 omitted)
|
|
80
|
|
|
|
|
|
5
|
|
|
75
|
|
|
$(000
omitted)
|
|
$7,399
|
|
|
$2,097
|
|
|
$350
|
|
|
$4,952
|
|
|
Unit
Price
|
|
$92.09
|
|
|
$26.09
|
|
|
|
|
|
$66.00
|
|
The
$3,229,778 (37%) increase in natural gas sales to $12,029,060 in 2008 from
$8,799,282 in 2007 was the result of an increase in both the average price
received per thousand cubic feet (MCF) and gas sales volumes. The
average price per MCF of natural gas sales increased $1.98 per MCF to $8.28 in
2008 from $6.30 in 2007 resulting in a positive gas price variance of
$2,881,974. A positive volume variance of $347,803 was the result of
an increase in natural gas volumes sold of 55,207 MCF to 1,452,368 MCF in 2008
from 1,397,161 MCF in 2007. The increase in the volume of gas
production was the net result of new 2008 production of about 411,800 MCF offset
by declines of 356,593 MCF. These declines are a combination of about 202,500
MCF of normal decline in production from mature producing properties and a
positive sales adjustment of 154,056 MCF included in the 2007 volumes. This
adjustment was for 2005 and 2006 volumes and sales from two Robertson County,
Texas wells received and recorded in September, 2007. The purchaser had
originally suspended the revenues due to a potential title problem and the
Company had not accrued these sales for that reason. This adjustment and the
reasons for it were discussed in the Company’s Form 10-QSB for the period ended
September 30, 2007. This adjustment slightly distorted the variance between 2007
and 2008 natural gas production and accounts for part of the variance
above. 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 not adequate to replace working
interest reserves produced in 2008 or 2007.
The gas
production for 2007 and 2008 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 December, 2008. These
properties accounted for approximately 817,000 MCF and $5,105,000 of the 2007
gas sales and approximately 845,000 MCF and $7,279,000 of the 2008 gas
sales. 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
$2,446,578 (49%) increase in crude oil sales to $7,398,619 in 2008 from
$4,952,041 in 2007 was the result of an increase in both the average price per
barrel (Bbl) and oil sales volumes. The average price received per Bbl of oil
increased $26.09 to $92.09 in 2008 from $66.00 in 2007, resulting in a positive
oil price variance of $2,096,491. An increase in oil sales volumes of
5,304 Bbls to 80,337 Bbls in 2008 from 75,033 Bbls in 2007 resulted in a
positive volume variance of $350,087. The increase in the oil volume production
was the net result of new 2008 production of about 15,900 Bbls offset by about
10,600 Bbls of normal decline in production from mature producing
properties.
Of the
new 2008 production approximately 9,900 Bbls (62%) was from Woods County,
Oklahoma. Of the remaining new production, about 3,500 Bbls (22%) was from new
working interest wells in Kansas and Oklahoma (in counties other than Woods) and
about 2,500 Bbls 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 adequate to replace working interest reserves produced in 2007
but not in 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 prices in 2008
provided an excellent example of the fluctuations that can and do
occur.
Spot
market prices for crude oil in 2008 started the year at about $100/Bbl, peaked
above $145/Bbl in July and then rapidly declined to less than $35/Bbl in early
2009. Crude oil spot prices are about $50/Bbl at the time of this
Form 10-K, so wellhead oil prices are less than one-half of the $92.06/Bbl
average sales price the Company received for its 2008 oil
production.
Spot
market prices for natural gas in 2008 started the year at about $7/MMBTU
(million British thermal units), peaked above $13/MMBTU in July and then
declined to less than $4/MMBTU in early 2009. Natural gas spot market prices are
about $4/MMBTU at the time of this Form 10-K, so wellhead gas prices are also
less than one-half of the $8.28/MCF average sales price the Company received for
its 2008 natural gas production.
These
depressed prices, if they continue for the remainder of the year, will result in
substantially lower sales and operating results in 2009 compared to
2008.
Operating
Costs and Expenses
Operating costs and expenses increased
$3,490,566 (74%) to $8,177,531 in 2008 from $4,686,965 in 2007, primarily due to
increases in production costs and depreciation, depletion and
amortization. The material components of operating costs and expenses
will
be discussed
below
.
Production
Costs.
Production costs increased $599,648 (36%) to $2,272,224
in 2008 from $1,672,576 in 2007. The increase was the net result of a $351,945
(64%) increase in gross production tax (net of production tax refunds) to
$903,224 in 2008, from $551,279 in 2007, plus an increase in lease operating and
handling expense of $247,702 (22%) to $1,369,000 in 2008 from $1,121,298 in
2007. Most of the increase in lease operating and handling expense was due to an
increase in lease operating expenses of $223,585 (30%) to $962,107 in 2008 from
$738,522 in 2007 with about $165,000 of the increase related to new 2008 wells
or wells that began producing in late 2007. Most of the remaining increase in
lease operating expense was due to required repairs on two salt water disposal
(“SWD”) wells that were part of a group of wells sold in June, 2008. See the
“Other Income (Loss), Net” discussion below for more information regarding this
sale of properties. Handling expense increased $24,117 (6%) to $406,893 in 2007
from $382,776 in 2007. 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, inclusive of geological and geophysical costs were $5,189,037 in
2008 and $4,272,382 in 2007. See Item 8, Note 8 to the accompanying
financial statements for additional information regarding a breakdown of these
costs. Costs charged to operations were $142,550 in 2008 and $237,507 in 2007
inclusive of geological and geophysical costs of $120,446 in 2008 and $10,805 in
2007
.
Update
of Oil
and Gas Exploration and Development Activity from December 31,
2008.
For the twelve months ended December 31, 2008, the
Company participated in the drilling of seventeen gross exploratory and nineteen
gross development working interest wells with working interests ranging from a
high of 21.5% to a low of 2.75%. Of the seventeen exploratory wells,
seven were completed as producers and one as dry hole, and nine were in
progress. Of the nineteen development wells, twelve were completed as
producers and seven 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 17, 2009, updating both exploration and
development activity from December 31, 2007.
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 January 2008 and completed in March 2008 as commercial oil and gas
producers. Two additional step-out wells will be drilled in
2009. Capitalized costs were $217,438 for the year ended December 31,
2008.
The
Company participated with its 18% working interest in the drilling of five
step-out wells on a Barber County, Kansas prospect which adjoins the previous
prospect. The first well was started in August 2008 and the second
and third wells in September 2008. The third well was a re-entry and
washdown of an old dry hole. All three wells were completed in
December 2008, the first as a commercial oil and gas producer and the other two
as marginal oil and gas producers. The fourth and fifth wells were
started in November 2008 and completion attempts of both are currently in
progress. Capitalized costs were $525,546 for the period ended December 31,
2008, including $115,968 in prepaid drilling costs.
The
Company participated with its 4.3% interest in the drilling of a horizontal
development well in a Harding County, South Dakota waterflood
unit. The well was started in June 2008 and completed in September
2008 as a commercial oil producer. Another unit well was converted
from an oil producer to a water injection well, with injection commencing in
December 2008. Costs for the year at December 31, 2008 were
$137,459.
The
Company participated with working interests of 18%, 18%, 17.4%, 18% and 17.9% in
the drilling of five development wells on a Woods County, Oklahoma
prospect. The first well was started in January 2008 and the second
in February 2008. Both were completed in March 2008 as commercial oil
and gas wells; however, the second well has since declined to marginal
status. The third well was started in March 2008 and completed in
April 2008 as a commercial oil and gas producer. The fourth and fifth
wells were started in October 2008 and completed in December 2008 as commercial
oil and gas producers. Capitalized costs totaled $653,274 as of
December 31, 2008, including $79,783 in prepaid drilling costs.
In 2007
the Company participated in the drilling and completion of an exploratory well
on a Grady County, Oklahoma prospect in which it has a 10%
interest. Sales commenced in April 2008 following the construction of
a pipeline, with gas and condensate flowing at a commercial rate. The
Company participated in the drilling of four additional exploratory wells on
this prospect in 2008. The first well was started in February 2008
and completed in May 2008 as a commercial gas and condensate
producer. The second well was started in July 2008 and completed in
March 2009. Preliminary flow rates indicate a commercial gas and
condensate producer. The third well was started in August 2008 and
casing was set in September 2008. A completion attempt is currently
in progress. The fourth 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. Total capitalized costs for the period ended December
31, 2008 were $750,930, including $72,130 in prepaid drilling costs. Dry hole
costs of $13,365 were expensed as of December 31, 2008.
The
Company participated in the drilling of three development wells on a Woods
County, Oklahoma prospect. The first well (Company working interest
12%) was started in December 2007 and completed in January 2008. The
second well (14% interest) was started in May 2008 and completed in July
2008. The third well (16% interest) was started in July 2008 and
completed in September 2008. All three are commercial oil and gas
wells. Two additional development wells (12% and 14% interests) will
be drilled starting in May 2009. Total costs for these wells at
December 31, 2008 were $340,307, including $13,066 in prepaid drilling
costs.
In 2007
the Company participated with a 16% interest in the drilling and completion of
an exploratory well on a Woods County, Oklahoma prospect. Sales
commenced in February 2008 with oil and gas flowing at a commercial
rate. The Company participated with an 8% working interest in the
drilling of another exploratory well which was started in March 2008 and
completed in April 2008 as a commercial oil and gas producer. Two
step-out wells (11.75% and 16% interests) were started in September 2008 and
completed in December 2008 as oil and gas producers, the first commercial and
the second marginal. Capitalized costs for the period ended December 31, 2008
were $283,333, including $9,460 in prepaid drilling costs.
The
Company participated with an 18% interest in the development of nine prospects
along a trend in Comanche and Kiowa Counties, Kansas. An exploratory
well (Company working interest 18%) was started in April 2008 and completed in
August 2008 as a marginal oil producer. A second exploratory well
(16.2% interest) was started in April 2008 and completed in June 2008 as a
commercial gas well. Two additional exploratory wells (18% and 16.2%
interests) were started in November 2008. The first was completed in
February 2009 and is currently being tested. A completion is in
progress on the second. Five additional exploratory wells are planned
for 2009, the first to start in March. Total capitalized costs at
December 31, 2008 were $516,888, including $139,822 in prepaid drilling costs,
and $217,890 in leasehold costs.
A 3-D
seismic survey was started in February 2008 on a Harper County, Kansas prospect
in which the Company has a 16% interest. Weather delays forced the
suspension of the survey prior to completion; however, data was acquired over
most of the prospect acreage. Two potential structures were
identified. Two exploratory wells were started in July
2008. One was completed in November 2008 as a commercial oil and gas
well and then shut in to await the construction of a pipeline. It
started producing again in March 2009. A completion attempt of the
other was unsuccessful in one zone. It is currently being evaluated
for a completion attempt in another zone. The seismic survey was
completed in September 2008. At least two additional wells are
planned for 2009. At December 31, 2008, capitalized well costs were
$215,417, and $120,446 was expensed for seismic costs.
In March
2008 the Company participated with its 18% interest in the drilling of an
exploratory well on a Logan County, Oklahoma prospect. The well was
completed in June 2008 as a marginal oil and gas
producer. Capitalized costs for the period ended December 31, 2008
were $109,944.
The
Company participated with its 16% working interest in the drilling of two
development wells on a Woods County, Oklahoma prospect. Both were
started in November 2007 and completed in February 2008 as commercial oil and
gas wells. Total costs for these wells at December 31, 2008 were
$223,943.
The
Company participated with a 21.5% working interest in the drilling of a step-out
well on a Woods County, Oklahoma prospect. The well was started in
November 2007 and completed in February 2008 as a commercial gas
producer. It also makes some oil. An additional step-out
well was started in July 2008 and completed in September 2008 as a commercial
oil and gas producer. Total costs for these wells at December 31,
2008 were $294,928, including $7,054 in prepaid drilling costs.
In March
2008 the Company purchased a 21% interest in 637.5 net acres of leasehold on a
Lincoln County, Oklahoma prospect for $13,388. A step-out dual
lateral horizontal well was started in March 2008. Drilling
difficulties were encountered and neither lateral reached its planned total
depth. Completion efforts so far have been unsuccessful, and the well
is currently non-commercial. An impairment expense of $566,027 was
charged to the well for the year ended December 31, 2008.
In April
2008 the Company purchased a 2.75% interest in 2,064 net acres of leasehold on a
Garvin County, Oklahoma prospect for $14,795, including $3,300 for
seismic. An exploratory well was started in May 2008, drilled to
total depth and then temporarily abandoned in August 2008. A test of
the target formation in November 2008 indicated that it was non-productive, and
the well is currently being evaluated for conversion to a disposal
well. Total costs at December 31, 2008, were $71,806.
The
Company participated with an 18% interest in the development of a McClain
County, Oklahoma prospect. Acreage has been acquired and it is likely
that an exploratory well will be drilled in 2009. Leasehold costs at
December 31, 2008 were $10,571.
The
Company participated with a 50% interest in the development of another McClain
County, Oklahoma prospect. Acreage has been acquired and a deal has
been made to obtain access to a 3-D seismic survey which covered the prospect
area. The Company will retain a 16% interest in the prospect
acreage. Decisions about drilling will be made after the seismic has
been evaluated. Leasehold costs at December 31, 2008 were
$65,942.
In August
2008 the Company purchased a 5% interest in a Garvin County, Oklahoma prospect
for $15,000. An exploratory well was started in September 2008 and
reached total depth in October 2008. The lower part of the hole has
been plugged; however, a completion will be attempted in a shallow zone that is
behind the intermediate casing.
In
November 2008 the Company purchased a 10.5% interest in 803.5 net acres of
leasehold on a Woods County, Oklahoma prospect for $21,093. Two
exploratory wells were drilled starting in November 2008. One
was completed in March 2009 and is currently being tested. The other
is shut in awaiting tank battery construction. Capitalized costs were
$202,549 for the year ended December 31, 2008.
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.
Capitalized costs were $56,800 at December 31, 2008, including $31,987 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 and paid $259,413 in
estimated seismic costs. A 3-D seismic survey has been completed and
an exploratory well is planned for May 2009.
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. Two
exploratory wells will be drilled starting in April 2009.
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 $140,562 in 2008 and $92,293 in 2007. The increase in the
provision for impairment is directly related to the exploration activity
discussed under “Exploration and Development Costs”, above. 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 2008 and 2007. The 2008 impairment loss of
$1,924,219 was partly the result of reserve adjustments on wells which first
produced in 2006 and 2007 and mostly due to wells completed in 2008, 2007 and
2006 for which the estimated fair market 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 had a significant impact on the market value of
future production and accordingly the current year’s impairment loss. The 2007
impairment loss of $67,745 was primarily the result of the reserve adjustments
on newer wells as there were no similar depressed prices in 2007.
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 $2,204,069 in 2008 and
$1,271,520 in 2007. Most of the increase of $932,549 is due to
increased oil and gas property additions in recent years and changes in reserve
estimates. It also includes $99,116 for 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 increased
$155,097 (12%) to $1,459,130 in 2008 from $1,304,033 in 2007. The
increase was partly due to an increase in employee salaries and benefits of
approximately $119,000 and an increase in accounting and legal fees of
approximately $18,000. Most of the remaining increase was due to a decrease of
about $45,000 in franchise taxes (primarily Texas) and an increase in ad valorem
taxes of about $54,000. The ad valorem tax increase relates to
price-related increases in revenue on Texas producing properties. Texas ad
valorem taxes are based on assessments on property valuations using oil and gas
prices at the beginning of the year.
Equity
Income (Loss) in Investees.
The following is an analysis of
equity income (loss) in investees by entity for the years ended December 31,
2008 and 2007. In December 2007, the Company sold its 9% equity
interest in Millennium Golf Properties, LLC for $225,000, resulting in a gain of
$175,458 that was included in the 2007 results of operations. See
Item 8, Note 7 to the accompanying financial statements for more information
about these investments.
|
|
|
Net Income (Loss)
|
|
|
2008
Income
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Over 2007
|
|
|
Broadway
Sixty-Eight, Ltd.
|
|
$
|
73,030
|
|
|
$
|
42,148
|
|
|
$
|
30,882
|
|
|
Millennium
Golf Properties, LLC
|
|
|
---
|
|
|
|
(320
|
)
|
|
|
320
|
|
|
OKC
Industrial Properties, LC
|
|
|
3,043
|
|
|
|
19,362
|
|
|
|
(16,319
|
)
|
|
Bailey
Hilltop Pipeline, LLC
|
|
|
9,692
|
|
|
|
---
|
|
|
|
9,692
|
|
|
JAR
Investment, LLC
|
|
|
8,450
|
|
|
|
4,875
|
|
|
|
3,575
|
|
|
Total
|
|
$
|
94,215
|
|
|
$
|
66,065
|
|
|
$
|
28,150
|
|
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 2008 and 2007. Other income, net declined $64,956 (9%) to $674,860
in 2008 from $739,816 in 2007.
Net
realized and unrealized gains (losses) on trading securities declined $165,279
(37%) to a net loss of $(120,599) in 2008 from a net gain of $44,680 in 2007.
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 market value. In 2008, the Company had realized gains of $51,333
and unrealized losses of $(164,318). In 2007, the Company had
realized gains of $13,371 and unrealized gains of $31,309.
Accrual
basis interest income decreased $159,304 (32%) to $339,126 in 2008 from $498,430
in 2007. 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 1.88% to 2.41% in 2008 from 4.29% in 2007. An increase of $4,867,853
(43%) in the average balance outstanding to $16,219,149 from $11,351,296 in 2007
resulted in a smaller decrease than would have occurred if the average balance
had remained the same as the prior year.
Most of
the remaining increase in this line item was due to the increase in gains on
asset sales of $259,381 to $452,475 in 2008 from $193,094 in
2007. The increase 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, most of which were
acquired in 2003. Other miscellaneous property disposals accounted
for the remaining net gains of about $3,000. Most of the 2007 gain was from the
sale of the Company’s ownership interest in its Millennium Golf Properties, LLC.
equity investment.
Provision for Income
Taxes.
See Note 6 to the accompanying financial statements for
an analysis of the various components of income taxes. 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. In 2007,
the Company had an estimated provision for income taxes of $2,923,758 as the
result of a current tax provision of $2,521,852 plus a deferred tax provision of
$401,906.
|
ITEM
7A.
|
QUANTATIVE
AND QUALATATIVE 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.
|
I
ndex to
Financial Statements.
|
|
Page
|
|
Report
of Independent Registered Public Accounting Firms
|
|
|
Eide
Bailly LLP – 2008
|
24
|
|
|
|
|
Murrell,
Hall, McIntosh & Co., PLLP - 2007
|
25
|
|
|
|
|
Balance
Sheets - December 31, 2008 and 2007
|
26
|
|
|
|
|
Statements
of Operations - Years Ended December 31, 2008 and 2007
|
28
|
|
|
|
|
Statement
of Stockholders’ Equity – Years Ended December 31, 2008 and
2007
|
29
|
|
|
|
|
Statements
of Cash Flows - Years Ended December 31, 2008 and 2007
|
30
|
|
|
|
|
Notes
to Financial Statements
|
32
|
|
|
|
|
Unaudited
Supplemental Financial Information
|
44
|
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 operations, 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
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, 2007, and the related statements of operations, stockholders’
equity, and cash flows for the year then ended. These financial statements are
the responsibility of the Company’s management. Our responsibility is to express
an opinion on these financial statements based on our 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 on the effectiveness of the Company’s internal control
over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
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, 2007, and the results of its operations and cash flows for the year
then ended, in conformity with accounting principles generally accepted in the
United States of America.
/S/
MURRELL, HALL, MCINTOSH & CO., PLLP
Oklahoma
City, Oklahoma
March 25,
2008
THE
RESERVE PETROLEUM COMPANY
BALANCE
SHEETS
ASSETS
|
|
|
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Current
Assets:
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents (Note 2)
|
|
$
|
1,430,832
|
|
|
$
|
1,232,376
|
|
|
Available
for Sale Securities (Notes 2 & 5)
|
|
|
15,120,573
|
|
|
|
12,445,531
|
|
|
Trading
Securities (Notes 2 & 5)
|
|
|
218,228
|
|
|
|
337,201
|
|
|
Refundable
Income Taxes
|
|
|
999,573
|
|
|
|
----
|
|
|
Receivables
(Notes 2 & 7)
|
|
|
1,738,856
|
|
|
|
2,312,323
|
|
|
Prepaid
Expenses
|
|
|
----
|
|
|
|
103,373
|
|
|
|
|
|
19,508,062
|
|
|
|
16,430,804
|
|
|
Investments:
|
|
|
|
|
|
|
|
|
|
Equity
Investments (Notes 2 & 7)
|
|
|
562,584
|
|
|
|
423,378
|
|
|
Other
|
|
|
15,298
|
|
|
|
15,298
|
|
|
|
|
|
577,882
|
|
|
|
438,676
|
|
|
Property,
Plant & Equipment (Notes 2, 8 & 10):
|
|
|
|
|
|
|
|
|
|
Oil
& Gas Properties, at Cost Based on the Successful Efforts Method of
Accounting
|
|
|
|
|
|
|
|
|
|
Unproved
Properties
|
|
|
1,029,500
|
|
|
|
1,156,804
|
|
|
Proved
Properties
|
|
|
20,543,660
|
|
|
|
17,014,112
|
|
|
|
|
|
21,573,160
|
|
|
|
18,170,916
|
|
|
Less
- Valuation Allowance and Accumulated Depreciation, Depletion &
Amortization
|
|
|
12,932,782
|
|
|
|
10,610,212
|
|
|
|
|
|
8,640,378
|
|
|
|
7,560,704
|
|
|
Other
Property & Equipment, at Cost
|
|
|
375,544
|
|
|
|
376,843
|
|
|
Less
- Accumulated Depreciation & Amortization
|
|
|
272,779
|
|
|
|
244,510
|
|
|
|
|
|
102,765
|
|
|
|
132,333
|
|
|
Total
Property, Plant and Equipment
|
|
|
8,743,143
|
|
|
|
7,693,037
|
|
|
Other
Assets
|
|
|
325,744
|
|
|
|
320,667
|
|
|
Total
Assets
|
|
$
|
29,154,831
|
|
|
$
|
24,883,184
|
|
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
BALANCE
SHEETS
LIABILITIES AND
STOCKHOLDERS’ EQUITY
|
|
|
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
Accounts
Payable (Note 2)
|
|
$
|
208,487
|
|
|
$
|
304,288
|
|
|
Income
Taxes Payable
|
|
|
----
|
|
|
|
153,094
|
|
|
Other
Current Liabilities -
|
|
|
|
|
|
|
|
|
|
Deferred
Income Taxes and Other
|
|
|
221,266
|
|
|
|
379,832
|
|
|
|
|
|
429,753
|
|
|
|
837,214
|
|
|
Long
Term Liabilities:
|
|
|
|
|
|
|
|
|
|
Asset
Retirement Obligation (Note 2)
|
|
|
516,054
|
|
|
|
----
|
|
|
Dividends
Payable (Note 3)
|
|
|
959,319
|
|
|
|
324,930
|
|
|
Deferred
Tax Liability (Note 6)
|
|
|
1,613,163
|
|
|
|
1,168,685
|
|
|
|
|
|
3,088,536
|
|
|
|
1,493,615
|
|
|
Total
Liabilities
|
|
|
3,518,289
|
|
|
|
2,330,829
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
26,114,016
|
|
|
|
22,957,809
|
|
|
|
|
|
26,271,384
|
|
|
|
23,115,177
|
|
|
Less
- Treasury Stock, at Cost
|
|
|
634,842
|
|
|
|
562,822
|
|
|
Total
Stockholders’ Equity
|
|
|
25,636,542
|
|
|
|
22,552,355
|
|
|
Total
Liabilities and Stockholders’ Equity
|
|
$
|
29,154,831
|
|
|
$
|
24,883,184
|
|
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENTS
OF OPERATIONS
|
|
|
Year Ended
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Operating
Revenues:
|
|
|
|
|
|
|
|
Oil
& Gas Sales
|
|
$
|
19,717,442
|
|
|
$
|
13,915,566
|
|
|
Lease
Bonuses & Other Revenues
|
|
|
988,568
|
|
|
|
417,152
|
|
|
|
|
|
20,706,010
|
|
|
|
14,332,718
|
|
|
Operating
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
2,272,224
|
|
|
|
1,672,576
|
|
|
Exploration
|
|
|
142,550
|
|
|
|
237,507
|
|
|
Depreciation,
Depletion, Amortization & Valuation Provisions
|
|
|
4,303,627
|
|
|
|
1,472,849
|
|
|
General,
Administrative and Other
|
|
|
1,459,130
|
|
|
|
1,304,033
|
|
|
|
|
|
8,177,531
|
|
|
|
4,686,965
|
|
|
Income
from Operations
|
|
|
12,528,479
|
|
|
|
9,645,753
|
|
|
Equity
Income in Investees (Note 7)
|
|
|
94,215
|
|
|
|
66,065
|
|
|
Other
Income, Net (Note 11)
|
|
|
674,860
|
|
|
|
739,816
|
|
|
Income
before Income Taxes
|
|
|
13,297,554
|
|
|
|
10,451,634
|
|
|
Provision
for Income Taxes (Notes 2 & 6)
|
|
|
3,649,861
|
|
|
|
2,923,758
|
|
|
Net
Income
|
|
$
|
9,647,693
|
|
|
$
|
7,527,876
|
|
|
Per
Share Data (Note 2):
|
|
|
|
|
|
|
|
|
|
Net
Income, Basic and Diluted
|
|
$
|
59.43
|
|
|
$
|
46.25
|
|
|
Cash
Dividends
|
|
$
|
40.00
|
|
|
$
|
6.00
|
|
|
Weighted
Average Shares Outstanding, Basic and Diluted
|
|
|
162,325
|
|
|
|
162,759
|
|
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENT
OF STOCKHOLDERS’ EQUITY
FOR THE
TWO YEARS ENDED DECEMBER 31, 2008
|
|
|
Common
Stock
|
|
|
Additional
Paid-in
Capital
|
|
|
Retained
Earnings
|
|
|
Treasury
Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at January 1, 2007
|
|
$
|
92,368
|
|
|
$
|
65,000
|
|
|
$
|
16,407,036
|
|
|
$
|
(435,622
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
----
|
|
|
|
----
|
|
|
|
7,527,876
|
|
|
|
----
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Dividends on Common Stock
|
|
|
----
|
|
|
|
----
|
|
|
|
(977,103
|
)
|
|
|
----
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase
of Treasury Stock
|
|
|
----
|
|
|
|
----
|
|
|
|
----
|
|
|
|
(127,200
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2007
|
|
|
92,368
|
|
|
|
65,000
|
|
|
|
22,957,809
|
|
|
|
(562,822
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
-----
|
|
|
|
----
|
|
|
|
9,647,693
|
|
|
|
----
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Dividends on Common Stock
|
|
|
-----
|
|
|
|
----
|
|
|
|
(6,491,486
|
)
|
|
|
----
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase
of Treasury Stock
|
|
|
-----
|
|
|
|
----
|
|
|
|
----
|
|
|
|
(72,020
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2008
|
|
$
|
92,368
|
|
|
$
|
65,000
|
|
|
$
|
26,114,016
|
|
|
$
|
(634,842
|
)
|
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENTS
OF CASH FLOWS
|
|
|
Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Cash
Flows from Operating Activities:
|
|
|
|
|
|
|
|
Cash
Received-
|
|
|
|
|
|
|
|
Oil
and Gas Sales
|
|
$
|
20,457,619
|
|
|
$
|
14,243,622
|
|
|
Lease
Bonuses and Coal Royalties
|
|
|
936,685
|
|
|
|
431,363
|
|
|
Agricultural
Rentals & Other
|
|
|
5,118
|
|
|
|
5,286
|
|
|
Cash
Paid-
|
|
|
|
|
|
|
|
|
|
Production
Costs
|
|
|
(2,248,936
|
)
|
|
|
(1,674,572
|
)
|
|
Exploration
Costs
|
|
|
(12,046
|
)
|
|
|
(340,993
|
)
|
|
General
Suppliers, Employees and Taxes,
|
|
|
|
|
|
|
|
|
|
Other
than Income Taxes
|
|
|
(1,456,691
|
)
|
|
|
(1,342,259
|
)
|
|
Interest
Received
|
|
|
390,206
|
|
|
|
487,162
|
|
|
Interest
Paid
|
|
|
(3,866
|
)
|
|
|
(3,933
|
)
|
|
Settlement
of Class Action Lawsuits
|
|
|
1,674
|
|
|
|
467
|
|
|
Dividends
Received on Trading
|
|
|
|
|
|
|
|
|
|
Securities
|
|
|
931
|
|
|
|
1,791
|
|
|
Purchase
of Trading Securities
|
|
|
(529,178
|
)
|
|
|
(669,307
|
)
|
|
Sale
of Trading Securities
|
|
|
527,551
|
|
|
|
666,515
|
|
|
Income
Taxes Paid, net
|
|
|
(4,525,337
|
)
|
|
|
(2,316,211
|
)
|
|
Net
Cash Provided by Operating Activities
|
|
$
|
13,543,730
|
|
|
$
|
9,488,931
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
Maturity
of Available for Sale Securities
|
|
|
26,632,838
|
|
|
|
18,290,624
|
|
|
Purchase
of Available for Sale Securities
|
|
|
(29,307,880
|
)
|
|
|
(23,262,903
|
)
|
|
Proceeds
from Disposal of Property
|
|
|
591,919
|
|
|
|
24,016
|
|
|
Purchase
of Property, Plant and Equipment
|
|
|
(5,163,043
|
)
|
|
|
(3,878,372
|
)
|
|
Cash
Distributions from Equity Investments
|
|
|
6,550
|
|
|
|
258,625
|
|
|
Purchase
of Equity Investment
|
|
|
(51,541
|
)
|
|
|
----
|
|
|
Note
Receivable from Equity Investment
|
|
|
(125,000
|
)
|
|
|
----
|
|
|
Net
Cash Applied to Investing Activities
|
|
$
|
(7,416,157
|
)
|
|
$
|
(8,568,010
|
)
|
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENTS
OF CASH FLOWS
|
|
|
Year Ended
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Cash
Flows Applied to Financing Activities:
|
|
|
|
|
|
|
|
Dividends
Paid to Shareholders
|
|
$
|
(5,857,097
|
)
|
|
$
|
(883,052
|
)
|
|
Purchase
of Treasury Stock
|
|
|
(72,020
|
)
|
|
|
(127,200
|
)
|
|
Total
Cash Applied to Financing Activities
|
|
$
|
(5,929,117
|
)
|
|
$
|
(1,010,252
|
)
|
|
Net
Change in Cash and Cash Equivalents
|
|
|
198,456
|
|
|
|
(89,331
|
)
|
|
Cash
and Cash Equivalents at Beginning of Year
|
|
|
1,232,376
|
|
|
|
1,321,707
|
|
|
Cash
and Cash Equivalents at End of Year
|
|
$
|
1,430,832
|
|
|
$
|
1,232,376
|
|
|
Reconciliation
of Net Income to Net Cash Provided by Operating
Activities:
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
$
|
9,647,693
|
|
|
$
|
7,527,876
|
|
|
Net Income Increased (Decreased)
by -
Net Change in -
|
|
|
|
|
|
|
|
|
|
Unrealized
Holding (Gains) Losses on Trading Securities
|
|
|
164,318
|
|
|
|
(31,309
|
)
|
|
Accounts
Receivable
|
|
|
709,001
|
|
|
|
328,940
|
|
|
Interest
and Dividends Receivable
|
|
|
51,079
|
|
|
|
(11,268
|
)
|
|
Income
Taxes (Refundable) Payable
|
|
|
(1,152,667
|
)
|
|
|
205,641
|
|
|
Accounts
Payable
|
|
|
14,739
|
|
|
|
17,280
|
|
|
Trading
Securities
|
|
|
(45,345
|
)
|
|
|
(16,163
|
)
|
|
Other
Assets
|
|
|
98,297
|
|
|
|
(111,283
|
)
|
|
Deferred
Taxes
|
|
|
277,192
|
|
|
|
401,906
|
|
|
Other
Liabilities
|
|
|
8,720
|
|
|
|
(36,379
|
)
|
|
Equity
Income in Investees
|
|
|
(94,215
|
)
|
|
|
(66,065
|
)
|
|
Gain
from Sale of Equity Investment
|
|
|
----
|
|
|
|
(175,458
|
)
|
|
Disposition
of Property & Equipment
|
|
|
(438,709
|
)
|
|
|
(17,636
|
)
|
|
Depreciation,
Depletion, Amortization and Valuation Provisions
|
|
|
4,303,627
|
|
|
|
1,472,849
|
|
|
Net
Cash Provided by Operating Activities
|
|
$
|
13,543,730
|
|
|
$
|
9,488,931
|
|
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.
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. The Company maintains
its cash in bank deposit accounts which at times may exceed federally insured
limits. The Company believes it is not exposed to any significant
credit risk on such accounts.
Investments
Marketable
Securities:
Statement
of Financial Accounting Standards (“SFAS”) 115, “Accounting for Certain
Investments in Debt and Equity Securities”, requires the Company to classify 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 market value. Trading
securities, which consist primarily of equity securities, are carried at fair
value with unrealized gains and losses reported in current earnings. During
2008, the Company recorded realized gains of $51,333 and unrealized losses of
$171,932. During 2007, the Company recorded realized gains of $24,403
and unrealized gains of $20,277.
Available-for-sale
securities, which consist entirely of US Government securities, are carried at
fair value with unrealized gains and losses reported as a component of other
comprehensive income, when significant to the financial
statements. As of December 31, 2008 and 2007, the unrealized gains of
$79,577 and $126,677, respectively, are not reflected in the accompanying
balance sheet.
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. The Company has
historically 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
periodically. Any impairment of value is charged to
expense.
Depreciation,
depletion and amortization of producing properties is 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 is depreciated on the straight-line, declining-balance or
other accelerated methods.
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 SFAS 109, “Accounting for Income Taxes,” that requires, among
other things, a liability approach to calculating deferred income taxes. The
objective is to measure a deferred income tax liability or asset using the tax
rates expected to apply to taxable income in the periods in which the deferred
income tax liability or asset is expected to be settled or realized. Any
resulting net deferred income tax assets should be reduced by a valuation
allowance sufficient to reduce such assets to the amount that is more likely
than not to be realized.
In July
2006, FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes”, which
clarifies the application of SFAS 109 by defining a criterion that an individual
income tax position must meet for any part of the benefit of that position to be
recognized in an enterprise’s financial statements and provides guidance on
measurement, de-recognition, classification, accounting for interest and
penalties, accounting in interim periods, disclosure and transition. In
accordance with the transition provisions, the Company adopted FIN 48 on
January 1, 2007, which did not have a material impact on the Company’s
operating results, financial position or cash flows. The Company did
not record a cumulative effect adjustment related to the adoption of FIN
48.
Earnings Per
Share
The
Company follows Statement of Financial Accounting Standards (“SFAS”) 128,
addressing earnings per share. SFAS 128 established the methodology of
calculating basic earnings per share and diluted earnings per share. The
calculations differ by adding any instruments convertible to common stock (such
as stock options, warrants, and convertible preferred stock) to weighted average
shares outstanding when computing diluted earnings per share. For the
years ended December 31, 2008 and 2007, the Company had no dilutive shares
outstanding, therefore basic and diluted earnings per share is the same amount
as presented in the accompanying statement of operations.
Segment
Reporting
SFAS 131,
“Disclosures about Segments of an Enterprise and Related Information”, requires
a public entity to report financial and descriptive information about its
reportable operating segments. Management believes that all operations are
evaluated and managed as a single segment — oil and natural gas exploration and
development.
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 2008 and three purchasers
in 2007 whose purchases were in excess of 10% of total oil and gas sales. In
2008, Redland Resources, Inc. purchases were $3,923,381, or 19.6% of total oil
and gas sales; ConocoPhillips Company purchases were $3,820,151 or
19.1% of total oil and gas sales; Encana Oil and Gas, Inc. purchases were
$2,634,748 or 13.1% of total oil and gas sales and Luff Exploration Company
purchases were $2,295,254 or 11.5% of total oil and gas sales. In
2007, ConocoPhillips Company purchases were $3,853,591 or 27.7% of total oil and
gas sales; Redland Resources, Inc. purchases were $1,974,769, or 14.2% of total
oil and gas sales; and Luff Exploration Company purchases were $1,643,498 or
11.8% of total oil and gas sales.
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 exceed 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
In
November 2002, the Financial Accounting Standards Board (“FASB”) issued
Interpretation 45,
Guarantor’s
Accounting and Disclosure
Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others
(FIN 45), was
issued. FIN 45 requires a guarantor entity, at the inception of a
guarantee covered by the measurement provisions of the interpretation, to record
a liability for the fair value of the obligation undertaken in
issuing the guarantee. The Company previously did not record a
liability when guaranteeing obligations unless it became probable that the
Company would have to perform under the guarantee. FIN 45 applied
prospectively to guarantees the Company issues or modifies subsequent to
December 31, 2002. The Company historically issues guarantees only on
a limited basis but has issued such guarantees associated with the Company’s
equity investments in Broadway Sixty-Eight, Ltd and JAR Investment,
LLC. Disclosures required by FIN 45 are discussed in Note
7.
Asset Retirement
Obligation
In June
2001, FASB issued SFAS 143,
Accounting for Asset Retirement
Obligations.
SFAS 143 requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred and a corresponding increase in the carrying amount of the related
long-lived asset, unless such items are immaterial. Subsequently, the
asset retirement cost should be allocated to expense using a systematic and
rational method. Prior to 2008, the Company assessed the impact of
SFAS 143 and based on the results of the assessment believed the impact of this
statement was immaterial to its financial position and results of operations.
However, in 2008, estimated well retirement costs increased significantly from
previous years estimated costs. The depressed prices at 2008 year end
resulted in shorter estimated production lives for many of the Company’s
producing wells. This factor combined with the increased estimated
abandonment costs, resulted in a significant increase in the estimated expense
to be charged to the 2008 results of operations. While the Company
still feels the impact of this assessment is immaterial to this statement, it
has elected to record the estimated amounts for 2008 and in future
years. The following table summarizes the asset retirement obligation
for the years ended December 31:
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Beginning
balance at January 1
|
|
$
|
---
|
|
|
$
|
---
|
|
|
Liabilities
incurred
|
|
|
505,733
|
|
|
|
---
|
|
|
Liabilities
settled
|
|
|
---
|
|
|
|
---
|
|
|
Accretion
expense
|
|
|
10,321
|
|
|
|
---
|
|
|
Revision
to estimate
|
|
|
---
|
|
|
|
---
|
|
|
|
|
Ending
balance at December 31
|
|
$
|
516,054
|
|
|
$
|
---
|
|
Fair Value
Measurements
The
Company has determined the fair value of certain assets and liabilities in
accordance with the provisions of SFAS 157,
Fair Value Measurements
,
which provides a framework for measuring fair value under generally accepted
accounting principles.
SFAS 157
defines fair value as the exchange price that would be received for an asset or
paid to transfer a liability (an exit price) in the principal or most
advantageous market for the asset or liability in an orderly transaction between
market participants on the measurement date. SFAS 157 requires that valuation
techniques maximize the use of observable inputs and minimize the use of
unobservable inputs. SFAS 157 also establishes a fair value hierarchy, which
prioritizes the valuation inputs into three broad levels as discussed further in
Note 9.
New Accounting
Pronouncements
In
December 2007, the FASB issued SFAS 141R,
Business Combinations
(“SFAS
141R”), which replaces SFAS 141,
Business Combinations
. SFAS
141R establishes principles and requirements for determining how an enterprise
recognizes and measures the fair value of certain assets and liabilities
acquired in a business combination, including non-controlling interests,
contingent consideration, and certain acquired contingencies. SFAS 141R also
requires acquisition-related transaction expenses and restructuring costs be
expensed as incurred rather than capitalized as a component of the business
combination. SFAS 141R will be applicable prospectively to business combinations
for which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. SFAS 141R would
have an impact on accounting for any businesses acquired after the effective
date of the pronouncement.
In
December 2007, the FASB also issued SFAS 160,
Non-controlling Interests in
Consolidated Financial Statements — An Amendment of ARB 51
(“SFAS 160”).
SFAS 160 establishes accounting and reporting standards for the non-controlling
interest in a subsidiary. SFAS 160 is effective for fiscal years, and interim
periods within those fiscal years, beginning on or after December 15, 2008.
SFAS 160 requires retroactive adoption of the presentation and disclosure
requirements for existing minority interests. All other requirements of SFAS 160
shall be applied prospectively. The Company does not currently have any interest
in any subsidiaries. SFAS 160 would have an impact on the presentation and
disclosure of the non-controlling interests of any non wholly-owned businesses
acquired in the future.
In
May 2008, the FASB issued SFAS 162,
The Hierarchy of Generally Accepted
Accounting Principles
(“SFAS 162”). SFAS 162 is intended to improve
financial reporting by identifying a consistent framework, or hierarchy, for
selecting accounting principles to be used in preparing financial statements
that are presented in conformity with GAAP for nongovernmental entities. The
FASB believes that the GAAP hierarchy should be directed to entities because it
is the entity (not its auditor) that is responsible for selecting accounting
principles for financial statements that are presented in conformity with GAAP.
This statement became effective on November 15, 2008 following the SEC’s
approval of the Public Company Accounting Oversight Board amendments to AU
Section 411, “The Meaning of Present Fairly in Conformity With Generally
Accepted Accounting Principles.” The adoption of SFAS 162 had no effect on the
Company’s results of operations, financial position or cash flows.
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, 2007, $.50 par value stock, 400,000 shares authorized
|
|
|
184,735.28
|
|
|
|
21,414.64
|
|
|
|
163,320.64
|
|
|
Purchase
of stock
|
|
|
----
|
|
|
|
795.00
|
|
|
|
(795.00
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2007, $.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
|
|
Note 5
-
MARKETABLE
SECURITIES
At
December 31, 2008 and 2007, the difference between the aggregate fair value and
amortized cost basis of available for sale securities was immaterial; therefore,
reporting of comprehensive income is not reflected in the accompanying financial
statements. The available for sale securities by contractual
maturity are as follows at December 31, 2008:
|
Due
within one year or less
|
|
$
|
15,120,573
|
|
As to the
trading securities held at year end, unrealized trading gains (losses) included
in earnings were $(164,317) for 2008 and $31,309 for 2007.
Note 6 -
INCOME
TAXES
Components
of deferred taxes follow:
|
|
|
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Assets
|
|
|
|
|
|
|
|
Leasehold
Costs
|
|
$
|
64,774
|
|
|
$
|
321,115
|
|
|
Gas
Balancing Receivable
|
|
|
52,379
|
|
|
|
52,379
|
|
|
Long-Lived
Asset Impairment
|
|
|
835,711
|
|
|
|
379,245
|
|
|
Marketable
Securities
|
|
|
33,123
|
|
|
|
----
|
|
|
Other
|
|
|
73,764
|
|
|
|
19,313
|
|
|
Total
Assets
|
|
|
1,059,751
|
|
|
|
772,052
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
Marketable
Securities
|
|
|
----
|
|
|
|
23,214
|
|
|
Receivables
|
|
|
198,742
|
|
|
|
309,690
|
|
|
Intangible
Drilling Costs, Depletion and Depreciation
|
|
|
2,639,790
|
|
|
|
1,940,737
|
|
|
Total
Liabilities
|
|
|
2,838,532
|
|
|
|
2,273,641
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Deferred Tax Liability
|
|
$
|
(1,778,781
|
)
|
|
$
|
(1,501,589
|
)
|
The
following table summarizes the current and deferred portions of income tax
expense.
|
|
|
Year Ended
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Current
Tax Provision:
|
|
|
|
|
|
|
|
Federal
|
|
$
|
3,337,569
|
|
|
$
|
2,500,860
|
|
|
State
|
|
|
35,100
|
|
|
|
20,992
|
|
|
|
|
|
2,521,852
|
|
|
|
3,372,669
|
|
|
Deferred
Provision
|
|
|
277,192
|
|
|
|
401,906
|
|
|
Total
Provision
|
|
$
|
3,649,861
|
|
|
$
|
2,923,758
|
|
The total
provision for income tax expressed as a percentage of income before income tax
was 27% in 2008 and 28% in 2007. These amounts differ from the
amounts computed by applying the statutory US Federal income tax rate of 34% for
2008 and 2007 to income before income tax as summarized in the following
reconciliation:
|
|
|
Year Ended
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
Computed
Federal Tax Provision
|
|
$
|
4,521,168
|
|
|
$
|
3,553,556
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(Decrease) in Tax From:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowable
Depletion in Excess of Basis
|
|
|
(942,714
|
)
|
|
|
(696,697
|
)
|
|
Dividend
Received Deduction
|
|
|
(222
|
)
|
|
|
(439
|
)
|
|
State
Income Tax Provision
|
|
|
35,100
|
|
|
|
20,992
|
|
|
Other
|
|
|
36,529
|
|
|
|
46,346
|
|
|
Provision
for Income Tax
|
|
$
|
3,649,861
|
|
|
$
|
2,923,758
|
|
|
Effective
Tax Rate
|
|
|
27%
|
|
|
|
28%
|
|
The
Company adopted the provisions of FASB Interpretation No. 48,
Accounting for Uncertainty in Income
Taxes
, (FIN 48) on January 1, 2007. Our calculation of the current income
tax provision for the twelve months ended December 31, 2008 and 2007 includes
tax positions for which the ultimate recognition or deductibility is highly
certain but there is uncertainty about the timing of the revenue recognition or
the expense deduction. Because of the impact of deferred tax
accounting, other than interest and penalties, the disallowance of the later
revenue recognition or the shorter deductibility period would not affect the
annual effective tax rate. It would accelerate the payment of cash to
the taxing authority to an earlier period. While uncertainty exists, the Company
believes it more likely than not that these positions would be fully sustained
under audit.
The
Company recognizes interest and penalties related to unrecognized tax benefits
in income tax expense.
|
Note
7 -
|
INVESTMENTS AND
RELATED COMMITMENTS AND CONTINGENT
LIABILITIES INCLUDING
GUARANTEES
|
The
carrying values of Equity Investments consist of the following at December
31:
|
|
|
Ownership %
|
|
|
2008
|
|
|
2007
|
|
|
Broadway
Sixty-Eight, Ltd.
|
|
|
33%
|
|
|
$
|
451,654
|
|
|
$
|
378,624
|
|
|
JAR
Investment, LLC
|
|
|
25%
|
|
|
|
(5,001
|
)
|
|
|
(6,901
|
)
|
|
Bailey
Hilltop Pipeline, LLC
|
|
|
10%
|
|
|
|
61,233
|
|
|
|
----
|
|
|
OKC
Industrial Properties, L.L.C.
|
|
|
10%
|
|
|
|
54,698
|
|
|
|
51,655
|
|
|
|
|
|
|
|
|
$
|
562,584
|
|
|
$
|
423,378
|
|
Broadway
Sixty-Eight, Ltd., an Oklahoma limited partnership (the “Partnership”), owns and
operates an office building in Oklahoma City, Oklahoma. Although the
Company invested as a limited partner, along with the other limited partners, 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
cost-sharing 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, 2008 and 2007.
Included
with Receivables is a Note receivable from the Partnership bearing 5% interest
and due December 31, 2008. On January 1, 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, 2009. This related party
transaction is connected to new office building construction. The new office
buildings are being constructed on undeveloped land adjacent to the existing
office building. When completed the new office buildings will be
offered for sale.
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 $142,319 at December 31, 2008. 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. However, assuming the fair
value of the obligation is equal to $142,319 at December 31, 2008, the Company
has not recorded a liability related to this guarantee in its financial
statements as the Company does not believe the potential obligation under this
guarantee is material to the accompanying financial statements.
In June
2005, JAR sold all real estate except the portion with the retail/commercial
center developed by the M-E joint venture discussed above. At
closing, a JAR bank loan secured by the property sold was paid off and the
Company’s guarantee agreement relating to this loan was terminated.
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, L.L.C., 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,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Acquisition
of Properties
|
|
|
|
|
|
|
|
Unproved
|
|
$
|
361,685
|
|
|
$
|
531,971
|
|
|
Proved
|
|
$
|
----
|
|
|
$
|
----
|
|
|
Exploration
Costs
|
|
$
|
981,032
|
|
|
$
|
1,148,093
|
|
|
Development
Costs
|
|
$
|
3,846,320
|
|
|
$
|
2,592,319
|
|
|
Note
9 -
|
FAIR VALUE
MEASUREMENTS
|
In
September 2006, the FASB issued SFAS 157 "Fair Value Measurements" in order
to establish a single definition of fair value and a framework
for measuring fair value in generally accepted accounting principles (GAAP)
that is intended to result in increased consistency and comparability in
fair value measurements. SFAS 157 also expands disclosures about fair
value measurements. SFAS 157 applies whenever other authoritative
literature requires (or permits) certain assets or liabilities to be
measured at fair value, but does not expand the use of fair value. SFAS 157
was originally effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years
with early adoption permitted.
In early
2008, the FASB issued Staff Position (FSP) FAS-157-2, "Effective Date of
SFAS 157," which delays by one year, the effective date of SFAS 157
for all non-financial assets and non-financial liabilities, except
those that are recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually). The delay pertains to
items including, but not limited to, non-financial assets and non-financial
liabilities initially measured at fair value in a business combination,
non-financial assets recorded at fair value at the time
of donation, and long-lived assets measured at fair value for
impairment assessment under SFAS 144 "Accounting for the Impairment or
Disposal of Long-Lived Assets".
The
Company has adopted the portion of SFAS 157 that has not been delayed
by FSP FAS-157-2 as of the beginning of 2008, and plans to adopt the
balance of its provisions as of the beginning of 2009. Items carried at
fair value on a recurring basis (to which SFAS No. 157 applies in 2008) consist
of available for sale securities based on quoted prices in active or
brokered markets for identical as well as similar assets and liabilities.
Items carried at fair value on a non-recurring basis (to which SFAS No. 157
will apply in 2009) generally consist of assets held for sale. The Company
also uses fair value concepts to test various long-lived assets
for impairment. The Company is continuing to evaluate the impact the
standard will have on the determination of fair value related to
non-financial assets and non-financial liabilities in post-2008
years.
The standard establishes
three levels of inputs between which to classify fair value assets.
Level
1 inputs consist of quoted prices in active markets for identical assets or
liabilities that the reporting entity has the ability to access at the
measurement date. Level 2 inputs are inputs other than quoted prices included
within Level 1 that are observable for the related asset or liability. Level 3
inputs are unobservable inputs related to the asset or
liability.
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, 2008 and 2007, 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. At December 31, 2008 and 2007 the fair
value of the Company’s marketable securities was based upon quoted market prices
for the securities owned by the Company which is a Level 1 input.
The
carrying amounts and estimated fair values of select Company assets and
liabilities are as follows as of December 31, 2008:
|
|
|
Level
1 Inputs
|
|
|
Level
2 Inputs
|
|
|
Level
3 Inputs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available
for sale securities
|
|
$
|
15,120,573
|
|
|
$
|
---
|
|
|
$
|
---
|
|
|
Trading
securities
|
|
$
|
218,228
|
|
|
$
|
---
|
|
|
$
|
---
|
|
The
carrying amounts and estimated fair values of select Company assets and
liabilities are as follows as of December 31, 2007:
|
|
|
Level
1 Inputs
|
|
|
Level
2 Inputs
|
|
|
Level
3 Inputs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available
for sale securities
|
|
$
|
12,445,531
|
|
|
$
|
---
|
|
|
$
|
---
|
|
|
Trading
securities
|
|
$
|
337,201
|
|
|
$
|
---
|
|
|
$
|
---
|
|
|
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 $1,924,219 for the year
ended December 31, 2008 and $67,745 for the year ended December 31, 2007 are
included in the Statements of Operations in the line item, Depreciation,
Depletion, Amortization and Valuation Provisions.
|
Note
11 –
|
OTHER INCOME,
NET
|
The
following is an analysis of the components of Other Income, Net for the years
ended 2008 and 2007:
|
|
|
2008
|
|
|
2007
|
|
|
Net
Realized and Unrealized Gain (Loss)On Trading Securities
|
|
$
|
(120,599
|
)
|
|
$
|
44,680
|
|
|
Gain
on Asset Sales
|
|
|
452,476
|
|
|
|
193,094
|
|
|
Interest
Income
|
|
|
339,126
|
|
|
|
498,430
|
|
|
Settlements
of Class Action Lawsuits
|
|
|
1,674
|
|
|
|
468
|
|
|
Agricultural
Rental Income
|
|
|
5,600
|
|
|
|
5,600
|
|
|
Dividend
and Other Income
|
|
|
931
|
|
|
|
1,791
|
|
|
Interest
and Other Expenses
|
|
|
(4,348
|
)
|
|
|
(4,247
|
)
|
|
Other
Income, Net
|
|
$
|
674,860
|
|
|
$
|
739,816
|
|
|
Note12
-
|
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 2008 by
payment to the Company in the amount of $149,195 by Mesquite, $149,195 by
Mid-American and $149,195 by LLTD. Reimbursements for 2007 were $129,539 by
Mesquite, $129,539 by Mid-American and $129,539 by LLTD. Included in
the 2008 amounts, Mesquite paid $108,794, Mid-American $108,794 and LLTD
$108,794 for their share of salaries. In 2007, the share of salaries
paid by Mesquite was $85,109, Mid-American $85,109, and LLTD
$85,109.
UNAUDITED
SUPPLEMENTAL FINANCIAL INFORMATION
SUPPLEMENTAL
SCHEDULE 1
THE
RESERVE PETROLEUM COMPANY
WORKING
INTERESTS RESERVE QUANTITY INFORMATION
(Unaudited)
|
|
|
Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Oil
& Natural Gas Liquids (Bbls)
|
|
|
|
|
|
|
|
Proved
Developed and Undeveloped Reserves
|
|
|
|
|
|
|
|
Beginning
of Year
|
|
|
290,989
|
|
|
|
232,438
|
|
|
Revisions
of Previous Estimates
|
|
|
(1,829
|
)
|
|
|
(23,101
|
)
|
|
Extensions
and Discoveries
|
|
|
45,035
|
|
|
|
143,505
|
|
|
Sales
of Reserves
|
|
|
(996
|
)
|
|
|
---
|
|
|
Production
|
|
|
(66,334
|
)
|
|
|
(61,853
|
)
|
|
End
of Year
|
|
|
266,865
|
|
|
|
290,989
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
Developed Reserves
|
|
|
|
|
|
|
|
|
|
Beginning
of Year
|
|
|
290,989
|
|
|
|
232,438
|
|
|
End
of Year
|
|
|
266,865
|
|
|
|
290,989
|
|
|
Gas
(MCF)
|
|
|
|
|
|
|
|
|
|
Proved
Developed and Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
Beginning
of Year
|
|
|
1,664,360
|
|
|
|
1,710,576
|
|
|
Revisions
of Previous Estimates
|
|
|
119,180
|
|
|
|
71,721
|
|
|
Extensions
and Discoveries
|
|
|
291,743
|
|
|
|
227,161
|
|
|
Sales
of Reserves
|
|
|
(123,902
|
)
|
|
|
----
|
|
|
Production
|
|
|
(395,959
|
)
|
|
|
(345,098
|
)
|
|
End
of Year
|
|
|
1,555,422
|
|
|
|
1,664,360
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
Developed Reserves
|
|
|
|
|
|
|
|
|
|
Beginning
of Year
|
|
|
1,664,360
|
|
|
|
1,710,576
|
|
|
End
of Year
|
|
|
1,555,422
|
|
|
|
1,664,360
|
|
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 14,004 Bbls of oil and 1,056,409 MCF of gas for the
year ended December 31, 2008, and 13,181 Bbls of oil and 1,052,063 MCF of
gas for the year ended December 31,
2007.
|
|
|
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, 2008 and
2007. 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.
|
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,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
Future
Cash Inflows
|
|
$
|
15,536,365
|
|
|
$
|
35,190,438
|
|
|
|
|
|
|
|
|
|
|
|
|
Future
Production and Development Costs
|
|
|
(6,406,107
|
)
|
|
|
(8,837,987
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Future
Income Tax Expense
|
|
|
(1,695,833
|
)
|
|
|
(6,360,828
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Future
Net Cash Flows
|
|
|
7,434,425
|
|
|
|
19,991,623
|
|
|
|
|
|
|
|
|
|
|
|
|
10%
Annual Discount for Estimated Timing of Cash Flows
|
|
|
(2,157,644
|
)
|
|
|
(7,189,387
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
Measure of Discounted Future Net Cash Flows
|
|
$
|
5,276,781
|
|
|
$
|
12,802,236
|
|
Estimates
of future net cash flows from the Company’s proved working interests oil and gas
reserves are shown in the table above. These estimates, which by
their nature are subject to revision in the near term, are based on prices in
effect at year end 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.
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,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
Standardized
Measure, Beginning of Year
|
|
$
|
12,802,235
|
|
|
$
|
8,900,979
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
and Transfers, Net of Production Costs
|
|
|
(7,642,024
|
)
|
|
|
(5,192,909
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
Change in Sales and Transfer Prices, Net of Production
Costs
|
|
|
(7,179,892
|
)
|
|
|
3,248,497
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions,
Discoveries and Improved Recoveries, Net of Future Production and
Development Costs
|
|
|
1,401,574
|
|
|
|
5,585,157
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of Quantity Estimates
|
|
|
212,149
|
|
|
|
730,817
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion
of Discount
|
|
|
1,687,571
|
|
|
|
1,120,315
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of Reserves in Place
|
|
|
(394,649
|
)
|
|
|
----
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Change in Income Taxes
|
|
|
2,869,772
|
|
|
|
(1,771,303
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in Production Rates (Timing) and Other
|
|
|
1,520,045
|
|
|
|
180,682
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
Measure, End of Year
|
|
$
|
5,276,781
|
|
|
$
|
12,802,235
|
|
|
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, 2008.
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, 2008 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, 2008.
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 firm
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/ Mason McLain
|
|
/s/ James L. Tyler
|
|
Mason
McLain, President
|
|
James
L. Tyler, 2
nd
Vice President
|
|
Principal
Executive Officer
|
|
Principal
Financial Officer
|
|
March
25, 2009
|
|
March
25, 2009
|
|
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 firms in the Proxy Statement is incorporated herein by
reference.
|
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 Pursuant to Rules 13a-14(a) and 15d-14(a)
under the Securities Exchange Act of 1934, as
amended.
|
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/Mason W. McLain
|
|
|
|
By:
|
Mason
W. McLain, President
|
|
|
|
|
Principal
Executive Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ James L. Tyler
|
|
|
|
By:
|
James
L. Tyler, 2nd Vice President
|
|
|
|
|
(Principal
Financial Officer)
|
|
Date: March
25, 2009
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
25, 2009
|
|
March
25, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Robert L. Savage
|
|
/s/ William M. Smith
|
|
|
Robert
L. Savage (Director)
|
|
William
M. Smith (Director)
|
|
|
March
25, 2009
|
|
March
25, 2009
|
|
52
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