UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
F
OR
M
10-KSB
(Mark
One)
þ
ANNUAL
REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the
fiscal year ended December 31, 2007
¨
TRANSITION REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE
ACT OF 1934
Commission
File number 0-8157
THE
RESERVE PETROLEUM COMPANY
(Name of
small business issuer 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
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73116-9092
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(Address
of principal executive offices)
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(Zip
Code)
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Issuer’s
telephone number:
(405) 848-7551
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)
Check
whether the issuer is not required to file reports pursuant to Section 13 or
15(d) of the Exchange Act.
o
Check
whether the issuer (1) filed all reports required to be filed by Section 13 or
15(d) of the Exchange Act during the past 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
Check if
there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-B contained in this form, and no disclosure will 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-KSB or any
amendment to this Form 10-KSB.
þ
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
issuer’s revenues for the fiscal year ended December 31, 2007 were
$14,332,718. .
The
aggregate market value of the voting stock held by non-affiliates was
$34,435,000 as computed by reference to the last reported sale which was on
January 7, 2008.
As of
March 25, 2008, there were 162,367.64 common shares 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 20, 2008 (the “Proxy Statement”) are incorporated
by reference into Part III of this Form 10-KSB.
Transitional
Small Business Disclosure Format (Check one):
Yes
o
No
þ
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Page
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3
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PART
I
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Item
1.
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3
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Item
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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22
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Item
8.
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45
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Item
8A.
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45
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PART
III
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Item 9.
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46
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Item
10.
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46
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Item
11.
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46
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Item
12.
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46
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Item
13.
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47
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Item
14.
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47
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Forward-Loo
king
Statements
This
Report on Form 10-KSB 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 6,
“Management’s Discussion and Analysis or Plan of Operation” 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-KSB. Readers should carefully review this Form 10-KSB 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-KSB
speak only as of the date of this Form 10-KSB. The Company does not
undertake to update its forward-looking statements.
PART
I
ITEM
1. DES
CRIPT
ION OF BUSINESS
.
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, “Description of Property”. 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 6, “Management’s Discussion and Analysis or Plan of
Operation”.
Owned
Mineral Property Management
The
Company owns non-producing mineral interests in approximately 263,567 gross
acres equivalent to 90,774 net acres. These mineral interests are
located in nine different states in the north and south central United
States. A total of 65,210 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 2007, $7,563,107 (54%) of oil
and gas sales was from royalty interests as compared to $5,942,930 (61%) in
2006. As a result of its mineral ownership, the Company had royalty
interests in 13 gross (.16 net) wells which were drilled and completed as
producing wells in 2007. This resulted in an average royalty
interest of about 1.2% for these 13 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
2007, the Company participated in the drilling of seventeen development wells
with twelve wells (1.95 net) completed as producers and five (.845 net) still
drilling.
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 2007 the Company
participated in the drilling of four exploration wells with two wells (.20)
completed as dry holes, one (.10 net) awaiting a pipeline connection and one
(.16 net) still being drilled.
For a
summation of exploratory and development wells drilled in 2007 or planned for in
2008, see Item 6, “Management’s Discussion and Analysis of Financial Condition
or Plan of Operation,” subheading, “Update of Oil and Gas Exploration and
Development Activity from December 31, 2006.”
Customers
In 2007,
the Company had three customers whose total purchases were greater than 10% of
revenues from oil and gas sales. ConocoPhillips purchases were
$3,853,591 or 28% of total oil and gas sales. Redland Resources, Inc., purchases
were $1,974,769, or 14% of total oil and gas sales. Luff Exploration
Company purchases were $1,643,498 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
6, “Management’s Discussion and Analysis or Plan of Operation”, subheading,
“Equity Investments” and Item 7, “Notes to Financial Statements,” Notes 2 and 7,
for a discussion of other business including guarantees.
Employees
At
December 31, 2007, the Company had eight employees, including
officers. See the Proxy Statement for additional
information. During 2007, 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 6, “Management’s Discussion and Analysis or Plan
of Operation”, subheading “Certain Relationships and Related Transactions” and
Note 12 of Item 7 for additional information.
ITEM
2. DE
SCRI
PTION OF PROPERTY.
The
Company’s principal properties are oil and natural gas
properties. The Company has interests in approximately 550
producing properties, with one-third of them being working interest properties
and the remaining two-thirds being royalty interest properties. About
93% of these properties are located in Oklahoma and Texas and account for
approximately 82.8% of our annual oil and gas sales. About 4% of the
properties are located in Kansas and South Dakota and account for approximately
17.1% of our annual oil and gas sales. The remaining 3% of these
properties are located in Colorado, Arkansas and Montana and account for less
than 0.1% of our annual oil and gas sales. No individual property
provides more than 10% of our annual oil and gas sales. See
discussion of revenues from Robertson County, Texas royalty interest properties
in Item 6, “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 40
for working interest reserve quantity information.
Since
January 1, 2007, 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 2006 annual report on Form 10-KSB and Federal income
tax return for the year ended December 31, 2006. 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, 2007, 2006 and 2005. 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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2007
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$
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67.35
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$
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6.19
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$
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65.71
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$
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6.63
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$
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1.65
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2006
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$
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62.72
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$
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6.06
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$
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59.68
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$
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6.63
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$
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1.65
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2005
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$
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54.93
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$
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7.55
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$
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54.56
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$
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7.55
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$
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1.73
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At
December 31, 2007, the Company had working interests in 126 gross (15.29 net)
wells producing primarily gas and had working interests in 88 gross (6.76 net)
wells producing primarily oil. These interests were in 46,965 gross
(5,704 net) producing acres. These wells include 42 gross (.408 net)
wells associated with secondary recovery projects.
Eight
percent or 6,249 barrels of the Company’s oil production during 2007 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, 2007.
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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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263,567
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90,774
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Undeveloped
Leaseholds
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50,145
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7,039
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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, 2005 and thereafter, as to net
productive and dry exploratory wells drilled and net productive and dry
development wells drilled. As indicated in the “Development and Exploration
Programs” on page 3, five development wells and three exploratory wells were
still in process at the time of this Form 10-KSB.
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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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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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2005
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.83
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.27
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2.17
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.21
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Recent
Activities
See Item
6, under the subheading, “Update of Oil and Gas Exploration and Development
Activity from December 31, 2006” for a summary of recent activities related to
oil and natural gas operations.
ITEM
3. L
EGA
L PROCEEDINGS.
There are
no material pending legal proceedings affecting the Company or any of its
properties.
ITEM 4. SUB
MIS
SION OF MATTERS TO A VOTE OF SECURITY HOLDERS
.
None.
PART
II
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ITEM 5.
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MA
RKET
FOR
COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND SMALL BUSINESS 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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03/31/06
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178.00
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140.00
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06/31//06
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177.00
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150.00
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09/30/06
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175.00
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158.00
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12/31/06
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166.00
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153.00
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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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There was
limited public trading in the Company’s common stock in 2007 and
2006. In 2007 there were 14 brokered trades appearing in the
Company’s transfer ledger, versus 14 in 2006.
At March
23, 2007, the Company had approximately 1,454 record holders of its common
stock. The Company paid dividends on its common stock in the amount
of $6.00 per share in the second quarter of 2007 and $4.00 per share in
2006. Management will review the amount of the annual dividend to be
paid in 2008 with the Board of Directors for their approval.
SMALL
BUSINESS ISSUER PURCHASES OF EQUITY SECURITIES
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Period
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Total Number of
Shares Purchased
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Average Price Paid Per
Share
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Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs (1)
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Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs (1)
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Oct 1,
2007 to Oct 31, 2007
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42
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$
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160.00
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-
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-
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Nov
1, 2007 to Nov 30, 2007
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-
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-
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-
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-
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Dec
1, 2007 to Dec 30, 2007
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-
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-
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-
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-
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Total
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42
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$
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160.00
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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. MAN
AGEM
ENT’S
DISCUSSION AND ANALYSIS OR PLAN OF OPERATION.
Please
refer to the financial statements and related notes in Item 7 of this Form
10-KSB 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 a leasehold is 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.
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
6 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 2008 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 and Robert T. McLain, directors and officers of the Company, are
directors and officers of Mesquite and Mid-American. Jerry Crow, a
Director of the Company, is a director 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 directors and
employees of the Company. Kyle McLain is a director and employee of
Mesquite and an advisory director and employee of
Mid-American. Cameron R. McLain is a director and employee of
Mid-American and an advisory director and employee of Mesquite. 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 30% 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 7, Note 12 for additional disclosures
regarding these relationships.
Equity
Investments
For most
of 2007 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 December, 2007
the Company sold its 9% ownership in Millennium Golf Properties,
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 7, Note 7 to the accompanying financial statements
includes related disclosures and additional information regarding the sale of
Millennium Golf Properties, LLC.
Liquidity
and Capital Resources
To
supplement the following discussion, please refer to the Balance Sheets on Pages
24 and 25, and the Statements of Cash Flows beginning on page 28 of this Form
10-KSB.
In 2007,
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 2007,
net cash provided by operating activities was $9,488,931. Sales, net of
production, exploration general and administrative costs and income taxes paid
were $8,569,587, which accounted for 90% of the operations net cash
flow. The remaining components provided $919,344 or 10% of cash
flow. In 2007, net cash applied to investing and financing activities
was $9,578,262. Net purchases of available for sale securities
discussed below, capitalized property additions (net of disposals) of $8,826,634
and dividend payments and treasury stock purchases of $1,010,252 accounted for
all of the net cash applied. Maturing available for sale securities
provided $18,290,624 of gross cash flow due to their six month
maturities. However, these funds plus $4,972,279 of excess cash from
operations were re-invested in the same type of securities.
In 2007,
cash utilized for capitalized property additions (net of disposals) of
$3,854,356 and dividend payments and treasury stock purchases of $1,010,252 were
$4,624,323 less than cash provided by operating activities.
Other
than cash, cash equivalents and available for sale securities, other significant
changes in working capital include the following:
Trading
securities increased $47,472 (16%) to $337,201 in 2007 from $289,729 in
2006. Most of the increase is due to a $31,309 increase in unrealized
gains which represent the change in the market value of the securities over
their original cost. The remaining $16,163 increase 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 $304,072 (12%) to $2,312,323 in 2007 from $2,616,395 in
2006. The decrease was the net result of two specific receivables at
year-end 2006 that were collected in 2007 offset mostly by an overall increase
in purchaser receivables due to increased average monthly sales in 2007. One
receivable of approximately $295,000 was from a purchaser for a royalty interest
in a new well in Tyler County, Texas. This amount represented sales
from July 2006 through December 2006 and was paid to the Company in January
2007. The other receivable of approximately $1,000,000 was for gas
revenues from two Robertson County, Texas wells. These revenues were paid in
April, 2007 and had been estimated and accrued from date of first sales or 14
months for one well and 7 months for the other at December,
2006. These decreases were mostly offset by increased average monthly
sales in 2007 versus 2006. Average monthly oil and natural gas sales
for the fourth quarter of 2007 were about $1,340,000 compared to about $850,000
for the fourth quarter of 2006. The receivables balance at December
31, 2007 includes about 1.67 months of oil and natural gas sales
accruals. See the discussion of revenues under subheading “Operating
Revenues”, below for more information about the increased sales of oil and
natural gas, including the wells in Robertson County, Texas.
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, 2006 in the “Results of Operations”
section below. There were no similar prepaid expenses in
2006.
Accounts
payable increased $196,862 (183%) to $304,288 in 2007 from $107,426 in
2006. This increase was primarily due to increased drilling activity
at year end 2007 versus 2006. See the discussion of this activity
under “Update of Oil and Gas Exploration and Development Activity” from December
31, 2006 in the “Results of Operations” section below.
Income
taxes payable were $153,094 in 2007 versus a $52,547 refundable balance in
2006. This was due to timing and larger estimated tax payments as a
result of the increased current Federal and State income taxes in 2007 versus
2006.
Deferred
income taxes and other, decreased $202,230 (35%) to $379,832 in 2007 from
$582,062 in 2006. Of the decrease, deferred income taxes decreased
$165,851 primarily because of the tax effect of decreased sales
accruals. The remaining decrease was due mostly to a decrease of
$34,475 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, 2007 and 2006. Also see the discussion
of changes in operating results under “Results of Operations” below in this Item
6.
Operating
Activities
As noted
above, net cash flows provided by operating activities in 2007 were $9,488,931,
which when compared to the $5,218,413 provided in 2006, represents an increase
of $4,270,518 or an 82% increase in net cash flows provided by operating
activities from 2006 to 2007. The increase resulted because of
an increase in oil and gas sales cash flows of $5,123,956, an increase in lease
bonuses and coal royalties of $130,062, a decrease in exploration costs of
$241,433, and an increase in interest income of $205,614. Those increases in
cash flows were partially offset by increased production costs of $625,284, an
increase in general, administrative, taxes and other expenses of $324,359, and
an increase in income taxes paid of $475,947. Additional discussion
of the more significant items follows.
Discussion
of Selected Material Line Items Resulting in an Increase in Cash
Flows.
The $5,123,956 (56%) increase in cash received from oil
and gas sales to $14,243,622 in 2007 from $9,119,666 in 2006 was the result of
an increase in both the average oil and gas price and 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 $130,062 (43%) to
$431,363 in 2007 from $301,301 in 2006. Most of the increase is due to an
increase in cash received for coal royalties of $190,567 to $221,028 in 2007
from $30,461 in 2006. This increase was offset by a decline in the cash received
for lease bonuses of about $60,700 in 2007 versus 2006.
Cash flow
increased due to a decrease in cash paid for exploration expenses of $241,433
(41%) to $340,993 in 2007 from $582,426 in 2006. About $85,000 of the
decrease was due to lower geological and geophysical expense in 2007 versus 2006
and most of the remaining decrease of about $156,000 was due to lower dry hole
costs in 2007 versus 2006.
Cash
received for interest earned on cash equivalents and available for sale
securities increased $205,614 (73%) to $487,162 in 2007 from $281,548 in
2006. The increase was the result of an increase in the average rate
of return to 4.29% in 2007 from 3.71% in 2006 and an increase in the average
balance of cash equivalents and available for sale securities outstanding to
$11,351,296 in 2007 from $7,590,730 in 2006.
Discussion
of Selected Material Line Items Resulting in a Decrease in Cash
Flows.
Cash paid for production costs increased $625,284 (60%)
to $1,674,572 in 2007 from $1,049,288 in 2006. Most of the increase
was due to a $396,196 increase in lease operating expenses and handling expenses
and an increase of $229,088 in production taxes in 2007 versus
2006. Most of the lease operating expense increase was attributable
to wells which first produced in 2007 and late 2006. The increase in
production taxes was a due to increased sales in 2007 versus 2006 and lower
production tax refunds received in 2007 versus 2006. These refunds
and the reason for the refunds are discussed later in the “Results of
Operations” section.
Cash paid
for general suppliers, employees and taxes other than income taxes increased
$324,359 (32%) to $1,342,259 in 2007 from $1,017,900 in 2006. Part of
this increase is due to an increase in property and franchise taxes of $144,407
to $320,286 paid in 2007 versus $175,879 paid in 2006. Most of the
remaining increase is due to an increase in salaries and employee benefits of
about $143,000 to $650,000 paid in 2007 versus $507,000 paid in 2006. The
remaining increase is due to increased subscription costs paid for energy and
engineering information services in 2007 versus 2006.
Income
taxes paid increased $475,947 (26%) to $2,316,211 in 2007 from $1,840,264 in
2006 due to increased income tax expense and estimated tax payments discussed
above and below in the “Results of Operations”.
Investing
Activities
Net cash
applied to investing activities increased $4,621,266 (117%) to $8,568,010 in
2007 from $3,946,744 in 2006. In 2007, net cash applied to available
for sale securities increased $3,021,127 from $1,951,152 in 2006 to $4,972,279
in 2007. This was a result of investing excess cash from 2007 cash flows
provided by operations. Cash flows related to both property
acquisitions and dispositions resulted in increases in cash applications to
investing activities in 2007 versus 2006. Cash applied to property acquisitions
increased $1,215,018 (46%) to $3,878,372 in 2007 from $2,663,354 in 2006 due
primarily increased exploration and development drilling activity in 2007 versus
2006. See the “Update of Oil and Gas Exploration and Development
Activity” from December 31, 2006 under the “Results of Operations” heading below
for more information regarding expenditures related to this drilling activity.
Cash flow from property dispositions declined $619,746 (96%) to $24,016 in 2007
from $643,762 in 2006 resulting in increased cash applications to investing
activities. Property dispositions in 2006 included proceeds of almost $617,000
from the sale of the Hughes County prospect and a fully depreciated producing
property with no similar sales in 2007. These increases in cash applications for
investing activities were offset somewhat by an increase in cash distributions
from equity investments of $234,625 (978%) to $258,625 in 2007 from $24,000 in
2006. This increase is due to a $225,000 distribution 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 2006. See Item 7, Note 7 to the accompanying
financial statements for additional information regarding the sale of this
equity investment.
Financing
Activities
Cash
applied to financing activities increased $356,169 (54%) to $1,010,252 in 2007
from $654,083 in 2006. Cash flows applied to financing activities
consist of cash dividends on common stock and cash used for the purchase of
treasury stock. In 2007, cash dividends paid on common stock amounted
to $883,052 as compared to $608,403 in 2006. The increase was
the result of an increase in the 2007 dividends per share to $6.00 from $4.00 in
2006. Cash applied to the purchase of treasury stock was $127,200 in
2007 as compared to $45,680 in 2006. The increase in treasury stock
purchases in 2007 from 2006 is due to more shares purchased in 2007 (795 shares)
versus 2006 (313 shares) and a higher average price paid in 2007 of $160 per
share versus $146 per share in 2006. For additional information
about treasury stock purchases, see Note (1) at the end of Part II, Item
5.”Market for Common Equity…” above.
Forward-Looking
Summary
The
latest estimate of business to be done in 2007 and beyond indicates the
projected activity can be funded from cash flow from operations and other
internal sources including net working capital. The Company is
engaged in exploratory drilling. If this drilling is successful,
substantial development drilling may result. Also, should other
exploration projects which fit the Company’s risk parameters become available,
or other investment opportunities become known, capital requirements may be more
than the Company has available. If so, external sources of financing
could be required.
Results
of Operations
As
disclosed in the Statements of Operations in Item 7, of this Form 10-KSB, in
2007 the Company had net income of $7,527,876 as compared to a net income of
$4,274,921 in 2006. Net income per share, basic and diluted was
$46.25 in 2007, an increase of $20.11 per share from $26.14 in
2006. Material line item changes in the Statements of Operations will
be discussed in the following paragraphs.
Operating
Revenues
Operating
revenues increased $4,399,769 (44%) to $14,332,718 in 2007 from $9,932,949 in
2006. Oil and gas sales increased $4,196,383 (43%) to $13,915,566 in 2007 from
$9,719,183 in 2006. Lease bonuses and other revenues increased
$203,386 (95%) to $417,152 in 2007 from $213,766 in 2006. This increase was the
result of an increase in lease bonuses and delay rentals of $64,112 due to
increased bonuses from East Texas, Oklahoma and South Dakota
leases. In addition coal royalties from North Dakota leases (first
received in 2006) increased $139,274 (206%) to $206,817 in 2007 from $67,543 for
2006 (last half of the year only). The Company does not anticipate 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
$4,196,383 increase in oil and gas sales was the net result of a $1,812,066
increase in gas sales plus a $2,377,518 increase in oil sales and a $6,799
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 2006 to 2007. Miscellaneous oil and gas product sales of
$164,243 in 2007 and $157,444 in 2006 are not included in the
analysis.
|
|
|
|
|
|
Variance
|
|
|
|
|
|
Production
|
|
2007
|
|
|
Price
|
|
|
Volume
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MCF
(000 omitted)
|
|
|
1,397
|
|
|
|
|
|
|
275
|
|
|
|
1,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$(000
omitted)
|
|
$
|
8,799
|
|
|
$
|
98
|
|
|
$
|
1,714
|
|
|
$
|
6,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit
Price
|
|
$
|
6.30
|
|
|
$
|
0.07
|
|
|
|
|
|
|
$
|
6.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bbls
(000 omitted)
|
|
|
75
|
|
|
|
|
|
|
|
33
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$(000
omitted)
|
|
$
|
4,952
|
|
|
$
|
391
|
|
|
$
|
1,987
|
|
|
$
|
2,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit
Price
|
|
$
|
66.00
|
|
|
$
|
5.21
|
|
|
|
|
|
|
$
|
60.79
|
|
The
$1,812,066 (26%) increase in natural gas sales to $8,799,282 in 2007 from
$6,987,216 in 2006 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 $0.07 per MCF to $6.30 in
2007 from $6.23 in 2006 resulting in a positive gas price variance of
$98,095. A positive volume variance of $1,713,971 was the result of
an increase in natural gas volumes sold of 275,116 MCF to 1,397,161 MCF in 2007
from 1,122,045 MCF in 2006. The increase in the volume of gas
production was the net result of new 2007 production of about 380,900 MCF as
partially offset by about 105,800 MCF of normal decline in production from
mature producing properties. As disclosed in Supplemental Schedule 1 of the
Unaudited Supplemental Financial Information included in Item 7, below, working
interests in natural gas extensions and discoveries were adequate to replace
working interest reserves produced in 2006, but not in 2007.
The gas
production for 2006 and 2007 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 October 2007. These
properties accounted for approximately 590,000 MCF and $3,430,000 of the 2006
gas sales and approximately 817,000 MCF and $5,105,000 of the 2007 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
$2,377,518 (92%) increase in crude oil sales to $4,952,041 in 2007 from
$2,574,523 in 2006 was the result of an increase in both the average price per
barrel and oil sales volumes. The average price received per barrel (Bbl) of oil
increased $5.21 (9%) to $66.00 per Bbl in 2007 from $60.79 per Bbl in 2006,
resulting in a positive oil price variance of $390,928. An increase
in oil sales volumes of 32,679 Bbls to 75,033 Bbls in 2007 from 42,354 Bbls in
2006 resulted in a positive volume variance of $1,986,590. The increase in the
oil volume production was the net result of new 2007 production of about 37,700
Bbls as partially offset by about 5,000 Bbls of normal decline in production
from mature producing properties.
Of the new 2007
production,
approximately 13,000 Bbls
(34%) was from Harding County, South Dakota and approximately 16,700 Bbls (44%)
was from Woods County, Oklahoma. As disclosed in Supplemental
Schedule 1 of the Unaudited Supplemental Financial Information included below in
Item 7, working interests in oil extensions and discoveries were adequate to
replace working interest reserves produced in 2007 and 2006.
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.
Operating Costs and
Expenses
Operating costs and expenses decreased
$25,747 (1%) to $4,686,965 in 2007 from $4,712,712 in 2006, primarily due to
decreases in exploration costs and depreciation, depletion and amortization
mostly offset by an increase in production costs. The material
components of operating costs and expenses will
be discussed below
.
Production
Costs.
Production costs increased $611,272 (58%) to $1,672,576
in 2007 from $1,061,304 in 2006. The increase was the net result of a $181,904
(35%) increase in gross production tax to $704,361 in 2007, from $522,457 in
2006, plus an increase in lease operating and handling expense of $396,196 (55%)
to $1,121,298 in 2007 from $725,102 in 2006, offset by gross production tax
refunds of $153,082 received in 2007 and $186,254 received in
2006. Most of the increase in lease operating and handling expense
was due to an increase in the handling costs of $260,347 (213%) to $382,776 in
2007 from $122,429 in 2006. Handling expense is comprised of gas transportation
and compression costs. In 2006, ConocoPhillips purchased Burlington Resources
and began paying us for some of the Robertson County, Texas gas production in
January, 2007. Burlington Resources had previously deducted or netted their
handling costs against the price/MCF they paid us for our gas, so the costs were
not reflected as expenses. This method resulted in lower average gas prices for
their purchases. ConocoPhillips reflected the handling costs as a separate
deduction on their checks when they became the operator and gas purchaser on a
significant portion of the Robertson County properties. This is the primary
reason for the increase in the handling expense. The remaining $135,894 increase
relates to increased operating expenses with about $117,000 of the increase
related to new 2007 wells (including the increased WI in the SD waterflood
discussed below) or wells that began producing in late 2006. 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 month’s 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 $4,272,382 in
2007 and $3,261,774 in 2006. Costs charged to operations were
$237,507 in 2007 and $803,860 in 2006 inclusive of geological and geophysical
costs of $10,805 in 2007 and $95,614 in 2006
.
Update
of Oil
and Gas Exploration and Development Activity from December 31,
2006.
For the twelve months ended December 31, 2007, the
Company participated in the drilling of four gross exploratory and seventeen
gross development working interest wells with net working interests ranging from
a high of 22.5% to a low of 9.6%. Of the four exploratory wells, two
were deemed dry holes and charged to expense, one is awaiting a pipeline
connection and one is still drilling. Of the seventeen development wells, twelve
were completed as producers and five are still drilling. In
management’s opinion, the exploratory drilling summarized above has produced
some possible development drilling opportunities.
The
following is a summary as of February 26, 2008, updating both exploration and
development activity from December 31, 2006.
The
Company participated with its 18% working interest in the drilling of five
step-out wells on a Barber County, Kansas prospect. The first well
was started in May 2007 and completed in June 2007 as a commercial gas
producer. It has since declined to marginal status but was recently
equipped with a pumping unit in an attempt to restore commercial
production. The second well was started in May 2007 and completed in
July 2007 as a commercial oil and gas producer. The third well was
started in September 2007 and completed in November 2007. It appears
to be a marginal gas well; however, it has a commercial zone behind pipe, as
does the first well. The fourth and fifth wells were started in
January 2008 and completion attempts on both are currently in progress.
Capitalized costs were $258,015 for the year ended December 31, 2007, including
$30,181 in prepaid drilling costs.
In July
2007 the Company purchased an 18% interest in 5,020 net acres of leasehold in
Barber County, Kansas for $54,217. This acreage adjoins the previous
prospect to the east. A step-out well was started in September 2007
and completed in November 2007 as a commercial oil and gas
producer. Sales commenced in January 2008. Total
capitalized costs were $114,630 for the year ended December 31, 2007, including
$26,845 in prepaid drilling costs.
The
Company has a 4.32% interest in a Harding County, South Dakota waterflood
unit. The Company’s interest increased from 0.96% on January 1, 2007
with the start of Phase II. At the beginning of the year there were
six horizontal wells in the unit producing oil and one horizontal water
injector. In April 2007 an additional lateral was drilled from one of
the producing wells. Another producer was converted to a water injector in July
2007. Capitalized costs for the year ended December 31, 2007 were
$248,233 including $222,072 for the investment adjustment associated with the
change in interest described above.
The
Company participated with a fee mineral interest in the drilling of a step-out
horizontal well in Harding County, South Dakota. The Company has a
14.6% working interest in the well which was started in March 2007 and completed
in June 2007 as a commercial oil producer. In April 2007 the Company
participated with its 10.9% working interest in the drilling of an extension of
a lateral in a previously drilled horizontal oil well. The Company
participated with an 18.8% working interest in the drilling of another step-out
horizontal well which was started in June 2007 and completed in September 2007
as a commercial oil producer. Capitalized costs for the year ended
December 31, 2007 were $971,283.
The
Company participated with its 18% working interest in the drilling of five
step-out wells on a Woods County, Oklahoma prospect. The first and
second wells were started in June 2007 and completed in September 2007 as
commercial oil and gas producers. The third well was started in July
2007 and completed in October 2007 as a commercial gas producer. The
fourth well was drilled in January 2008 and a completion attempt is currently in
progress. The fifth well was drilled in February 2008 and a
completion attempt is pending. The Company will participate with a
17.4% working interest in the drilling of an additional development well which
will start in March 2008. Capitalized costs totaled $340,164 for the
year ended December 31, 2007, including $20,516 in prepaid drilling
costs.
In
December 2005 the Company purchased a 10% interest in a Grady County, Oklahoma
prospect. A 3-D seismic survey was conducted and four prospective
structures were identified. Additional acreage was acquired. An
exploratory well was started in May 2007 and completed in September
2007. Preliminary testing indicates commercial gas and gas condensate
production. The well is currently shut in awaiting pipeline
construction. A second exploratory well was started in August 2007
and completed in September 2007 as a dry hole. A third exploratory
well was started in February 2008 and is currently drilling. Total
drilling costs for the year ended December 31, 2007 were $536,911, including
$136,160 in dry hole costs.
The
Company participated in the development of a Hughes County, Oklahoma prospect
which was sold in September 2006 with the Company retaining an 8.75% interest in
the prospect acreage. An exploratory horizontal well was started in
January 2007 and a second in February 2007. Both wells were drilled;
however, completion attempts of both failed to establish commercial
production. The Company has only a reversionary working interest in
these wells and therefore has no cost exposure. The original operator
has sold the prospect and the Company is currently negotiating with the new
owner to encourage them to drill additional wells.
The
Company participated in the drilling of five development wells on a Woods
County, Oklahoma prospect in which it has a 16% interest. The first
(Company working interest 13%) was started in March 2007 and completed in April
2007. The second (13% interest) was started in April 2007 and
completed in May 2007. The third (16% interest) was started in May
2007 and the fourth (12% interest) in June 2007. Both were completed
in July 2007. The fifth (12% interest) was started in December 2007
and completed in January 2008. All five wells are commercial oil and
gas producers. Total costs for the year ended December 31, 2007 were
$457,801, including $40,692 in prepaid drilling costs.
In May
2007 the Company purchased a 16% interest in a Woods County, Oklahoma prospect
for $80,800. The Company participated with a 10.3% working interest
in the drilling of an exploratory well which was started in June 2007 and
completed in July 2007 in a zone that has since proved to be
noncommercial. A completion attempt in a shallower zone in December
2007 was also unsuccessful and the well will be plugged. The Company
participated with a 16% working interest in a second exploratory well which was
started in October 2007 and completed in December 2007. Sales
commenced in February 2008 with gas flowing at a commercial rate but with a high
water cut. The Company will participate with an 8% working interest
in the drilling of a third exploratory well in March 2008. Total
drilling costs for the year ended December 31, 2007 were $183,178, including
$15,291 in prepaid drilling costs, and $80,778 in dryhole costs.
In April
2007 the Company agreed to participate with an 18% interest in the development
of nine prospects along a trend in Comanche and Kiowa Counties,
Kansas. Acreage has been acquired and an exploratory well will be
drilled in the second quarter of 2008.
In August
2007 the Company purchased a 16% interest in 8,301 acres of leasehold on a
Harper County, Kansas prospect for $79,690. A 3-D seismic survey is
currently in progress and should be completed in March
2008. Following the acquisition, processing and evaluation of the
seismic data decisions about drilling will be made. At December 31,
2007, $103,373 in prepaid seismic expense was carried as a current
asset.
In
October 2007 the Company purchased an 8% interest in a marginal well and the
associated 640 acres of leasehold in Woods County, Oklahoma for $60,000, $8,000
of which was allocated to well equipment. The well was
recompleted in October 2007 as a commercial oil producer. Additional
completion costs for the year ended December 31, 2007 were $19,949.
In
October 2007 the Company agreed to purchase an 18% interest in a Logan County,
Oklahoma prospect for $13,680. An exploratory well will be drilled in
March 2008.
The
Company participated with its 16% working interest in the drilling of two
development wells on a Woods County, Oklahoma prospect. Both wells
were started in November 2007. The first was completed in February
2008 as a commercial oil and gas well and a completion attempt is currently in
progress on the second. Drilling costs for the year ended December
31, 2007 were $228,800 including $115,419 in prepaid drilling
costs.
The
Company participated with a 22.5% 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. Drilling costs for the year ended December 31, 2007 were
$147,375, including $72,123 in prepaid drilling costs.
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 $92,293 in 2007 and $82,414 in 2006. The increase in the
provision for impairment is directly related to the exploration activity
discussed under “Exploration Costs”, above. The 2007 provision for impairment
was due to the annual amortization of undeveloped leaseholds with none due to
specific leasehold impairments.
As
discussed in 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 amount. Reviews were performed in both 2007 and
2006. The 2007 impairment loss of $67,745 was partly the result of
reserve adjustments on wells which first produced in 2005 and 2006 and partly
due to wells completed in 2007 for which the estimated fair market value of
future production was less than the Company’s carrying amount in the
well. The 2006 impairment loss of $597,751 was to a great extent the
result of similar declines in 2006.
The
depletion and depreciation of oil and gas properties are computed by the
units-of-production method. The amount expensed in any year will
fluctuate with the change in estimated reserves of oil and gas, a change in the
rate of production or a change in the basis of the assets. The
provision for depletion and depreciation totaled $1,271,520 in 2007 and
$1,068,146 in 2006. Most of the increase of $203,374 is due to
increased oil and gas property additions in recent years.
General,
Administrative and Other Expenses (G&A).
G&A increased
$247,214 (23%) to $1,304,032 in 2007 from $1,056,818 in
2006. The increase was partly due to an increase in employee salaries
and benefits of approximately $143,000 and an increase in subscription costs for
energy and engineering information services of approximately $26,000. Most of
the remaining increase was due to an increase in franchise taxes of about
$46,000 (primarily Texas) and ad valorem taxes of almost $20,000. The
ad valorem tax increase relates to the new wells in Robertson County,
Texas.
Equity
Income (Loss) in Investees.
The following is an analysis of
equity income (loss) in investees by entity for the years ended December 31,
2007 and 2006. See Note 7 to the accompanying financial statements
included below in Item 7, for more information.
|
|
|
Net Income (Loss)
|
|
|
2007
Income
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Over 2006
|
|
|
Broadway
Sixty-Eight, Ltd.
|
|
$
|
42,148
|
|
|
$
|
10,785
|
|
|
$
|
31,363
|
|
|
Millennium
Golf Properties, LLC
|
|
|
(320)
|
|
|
|
(4,291)
|
|
|
|
3,971
|
|
|
OKC
Industrial Properties, LC
|
|
|
19,362
|
|
|
|
942
|
|
|
|
18,420
|
|
|
JAR
Investment, LLC
|
|
|
4,875
|
|
|
|
6,827
|
|
|
|
(1,952)
|
|
|
Total
|
|
$
|
66,065
|
|
|
$
|
14,263
|
|
|
$
|
51,802
|
|
Other
Income (Loss), Net.
See Note 11 to the accompanying financial
statements for an analysis of the components of this line item for the years
ended 2007 and 2006. Other income, net increased $223,260 (43%) to $739,816 in
2007 from $516,556 in 2006.
Net
realized and unrealized gains on trading securities increased $11,039 (33%) to
$44,680 in 2007 from $33,641 in 2006. Realized gains or losses result when a
trading security which is owned 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 2007, the
Company had realized gains of $13,371 and unrealized gains of
$31,309. In 2006, the Company had realized gains of $6,406 and
unrealized gains of $27,235.
Accrual
basis interest income increased $171,832 (52%) to $498,430 in 2007 from $326,598
in 2006. The increase was the result of an increase 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
increased 0.58% to 4.29% in 2007 from 3.71% in 2006, and the average balance
outstanding of $11,351,296 increased $3,760,566 (50%) from $7,590,730 in
2006.
Most of
the remaining increase in this line item was due to the increase in gains on
asset sales of $44,208 to $193,094 in 2007 from $148,886 in
2006. The increase in the gains on asset sales was due
primarily to a $175,458 gain on the sale of the Company’s ownership interest in
Millennium Golf Properties, LLC. Other miscellaneous property disposals
accounted for the remaining net gains of about $18,000.
Provision for Income
Taxes.
See Note 6, to the accompanying financial statements
for an analysis of the various components of income taxes 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.
In 2006, the Company had an estimated provision for income taxes of $1,476,135
as the result of a current tax provision of $1,456,305 plus a deferred tax
provision of $19,830.
ITEM
7. FINA
NCIA
L STATEMENTS.
Index to
Financial Statements.
|
|
|
Page
|
|
Report
of Independent Registered Public Accounting Firm – Murrell, Hall, McIntosh
& Co., PLLP, 2007 and 2006.
|
|
23
|
|
|
|
|
|
Balance
Sheets - December 31, 2007 and 2006
|
|
24
|
|
|
|
|
|
Statements
of Operations - Years Ended December 31, 2007 and 2006
|
|
26
|
|
|
|
|
|
Statement
of Stockholders’ Equity – Years Ended December 31, 2007 and
2006
|
|
27
|
|
|
|
|
|
Statements
of Cash Flows - Years Ended December 31, 2007 and 2006
|
|
28
|
|
|
|
|
|
Notes
to Financial Statements
|
|
30
|
|
|
|
|
|
Unaudited
Supplemental Financial Information
|
|
40
|
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Stockholders
The
Reserve Petroleum Company
We have
audited the accompanying balance sheets of THE RESERVE PETROLEUM COMPANY as of
December 31, 2007 and 2006, and the related statements of operations,
stockholders’ equity, and cash flows for the years then ended. These financial
statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audits 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 audits 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 audits provide a reasonable basis for our
opinion.
In our
opinion, the financial statements referred to above present fairly, in all
material respects, the financial position of The Reserve Petroleum Company as of
December 31, 2007 and 2006, and the results of its operations and cash flows for
the years 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,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Current
Assets:
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents (Note 2)
|
|
$
|
1,232,376
|
|
|
$
|
1,321,707
|
|
|
Available
for Sale Securities (Notes 2 & 5)
|
|
|
12,445,531
|
|
|
|
7,473,252
|
|
|
Trading
Securities (Notes 2 & 5)
|
|
|
337,201
|
|
|
|
289,729
|
|
|
Refundable
Income Taxes
|
|
|
-
|
|
|
|
52,547
|
|
|
Receivables
(Note 2)
|
|
|
2,312,323
|
|
|
|
2,616,395
|
|
|
Prepaid
Expenses
|
|
|
103,373
|
|
|
|
-
|
|
|
|
|
|
16,430,804
|
|
|
|
11,753,630
|
|
|
Investments:
|
|
|
|
|
|
|
|
|
|
Equity
Investments (Notes 2 & 7)
|
|
|
423,378
|
|
|
|
440,480
|
|
|
Other
|
|
|
15,298
|
|
|
|
15,298
|
|
|
|
|
|
438,676
|
|
|
|
455,778
|
|
|
Property,
Plant & Equipment (Notes 2, 8 & 10):
|
|
|
|
|
|
|
|
|
|
Oil
& Gas Properties, at Cost Based on the Successful Efforts Method of
Accounting
|
|
|
|
|
|
|
|
|
|
Unproved
Properties
|
|
|
1,156,804
|
|
|
|
842,872
|
|
|
Proved
Properties
|
|
|
14,135,166
|
|
|
|
10,752,832
|
|
|
|
|
|
15,291,970
|
|
|
|
11,595,704
|
|
|
Less
- Valuation Allowance and Accumulated
|
|
|
|
|
|
|
|
|
|
Depreciation,
Depletion & Amortization
|
|
|
7,731,266
|
|
|
|
6,630,682
|
|
|
|
|
|
7,560,704
|
|
|
|
4,965,022
|
|
|
Other
Property & Equipment, at Cost
|
|
|
376,843
|
|
|
|
366,108
|
|
|
Less
- Accumulated Depreciation & Amortization
|
|
|
244,510
|
|
|
|
203,219
|
|
|
|
|
|
132,333
|
|
|
|
162,889
|
|
|
Total
Property, Plant and Equipment
|
|
|
7,693,037
|
|
|
|
5,127,911
|
|
|
Other
Assets
|
|
|
320,667
|
|
|
|
312,758
|
|
|
Total
Assets
|
|
$
|
24,883,184
|
|
|
$
|
17,650,077
|
|
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
BALANCE
SHEETS
LIABILITIES AND
STOCKHOLDERS’ EQUITY
|
|
|
December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
Accounts
Payable (Note 2)
|
|
$
|
304,288
|
|
|
$
|
107,426
|
|
|
Income
Taxes Payable
|
|
|
153,094
|
|
|
|
-
|
|
|
Other
Current Liabilities - Deferred Income Taxes and Other
|
|
|
379,832
|
|
|
|
582,062
|
|
|
|
|
|
837,214
|
|
|
|
689,488
|
|
|
Long
Term Liabilities:
|
|
|
|
|
|
|
|
|
|
Dividends
Payable (Note 3)
|
|
|
324,930
|
|
|
|
230,879
|
|
|
Deferred
Tax Liability (Note 6)
|
|
|
1,168,685
|
|
|
|
600,928
|
|
|
|
|
|
1,493,615
|
|
|
|
831,807
|
|
|
Commitments
& Contingencies (Notes 2 & 7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Liabilities
|
|
|
2,330,829
|
|
|
|
1,521,295
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
Equity: (Notes 3 & 4)
|
|
|
|
|
|
|
|
|
|
Common
Stock
|
|
|
92,368
|
|
|
|
92,368
|
|
|
Additional
Paid-in Capital
|
|
|
65,000
|
|
|
|
65,000
|
|
|
Retained
Earnings
|
|
|
22,957,809
|
|
|
|
16,407,036
|
|
|
|
|
|
23,115,177
|
|
|
|
16,564,404
|
|
|
Less
- Treasury Stock, at Cost
|
|
|
562,822
|
|
|
|
435,622
|
|
|
Total
Stockholders’ Equity
|
|
|
22,552,355
|
|
|
|
16,128,782
|
|
|
Total
Liabilities and Stockholders’ Equity
|
|
$
|
24,883,184
|
|
|
$
|
17,650,077
|
|
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENTS
OF OPERATIONS
|
|
|
Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues:
|
|
|
|
|
|
|
|
Oil
& Gas Sales
|
|
$
|
13,915,566
|
|
|
$
|
9,719,183
|
|
|
Lease
Bonuses & Other Revenues
|
|
|
417,152
|
|
|
|
213,766
|
|
|
|
|
|
14,332,718
|
|
|
|
9,932,949
|
|
|
Operating
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
1,672,576
|
|
|
|
1,061,304
|
|
|
Exploration
|
|
|
237,507
|
|
|
|
803,860
|
|
|
Depreciation,
Depletion, Amortization& Valuation Provisions
|
|
|
1,472,849
|
|
|
|
1,790,730
|
|
|
General,
Administrative and Other
|
|
|
1,304,033
|
|
|
|
1,056,818
|
|
|
|
|
|
4,686,965
|
|
|
|
4,712,712
|
|
|
Income
from Operations
|
|
|
9,645,753
|
|
|
|
5,220,237
|
|
|
Equity
Income in Investees (Note 7)
|
|
|
66,065
|
|
|
|
14,263
|
|
|
Other
Income, Net (Note 11)
|
|
|
739,816
|
|
|
|
516,556
|
|
|
Income
before Income Taxes
|
|
|
10,451,634
|
|
|
|
5,751,056
|
|
|
Provision
for Income Taxes (Notes 2 & 6)
|
|
|
2,923,758
|
|
|
|
1,476,135
|
|
|
Net
Income
|
|
$
|
7,527,876
|
|
|
$
|
4,274,921
|
|
|
Per
Share Data (Note 2):
|
|
|
|
|
|
|
|
|
|
Net
Income, Basic and Diluted
|
|
$
|
46.25
|
|
|
$
|
26.14
|
|
|
Cash
Dividends
|
|
$
|
6.00
|
|
|
$
|
4.00
|
|
|
Weighted
Average Shares Outstanding, Basic and Diluted
|
|
|
162,759
|
|
|
|
163,544
|
|
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENT
OF STOCKHOLDERS’ EQUITY
FOR THE
TWO YEARS ENDED DECEMBER 31, 2007
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
Paid-in
|
|
|
Retained
|
|
|
Treasury
|
|
|
|
|
Stock
|
|
|
Capital
|
|
|
Earnings
|
|
|
Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at January 1, 2006
|
|
$
|
92,368
|
|
|
$
|
65,000
|
|
|
$
|
12,786,650
|
|
|
$
|
(
389,942
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
-
|
|
|
|
-
|
|
|
|
4,274,921
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Dividends on Common Stock
|
|
|
-
|
|
|
|
-
|
|
|
|
(654,535
|
)
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase
of Treasury Stock
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(45,680
|
)
|
|
Balance
at December 31, 2006
|
|
|
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
|
)
|
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENTS
OF CASH FLOWS
|
|
|
Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Cash
Flows from Operating Activities:
|
|
|
|
|
|
|
|
Cash
Received-
|
|
|
|
|
|
|
|
Oil
and Gas Sales
|
|
$
|
14,243,622
|
|
|
$
|
9,119,666
|
|
|
Lease
Bonuses and Coal Royalties
|
|
|
431,363
|
|
|
|
301,301
|
|
|
Agricultural
Rentals & Other
|
|
|
5,286
|
|
|
|
5,294
|
|
|
Cash
Paid-
|
|
|
|
|
|
|
|
|
|
Production
Costs
|
|
|
(1,674,572
|
)
|
|
|
(1,049,288
|
)
|
|
Exploration
Costs
|
|
|
(340,993
|
)
|
|
|
(582,426
|
)
|
|
General
Suppliers, Employees and Taxes, Other than Income Taxes
|
|
|
(1,342,259
|
)
|
|
|
(1,017,900
|
)
|
|
Interest
Received
|
|
|
487,162
|
|
|
|
281,548
|
|
|
Interest
Paid
|
|
|
(3,933
|
)
|
|
|
(3,968
|
)
|
|
Settlement
of Class Action Lawsuits
|
|
|
467
|
|
|
|
4,440
|
|
|
Dividends
Received on Trading Securities
|
|
|
1,791
|
|
|
|
1,665
|
|
|
Purchase
of Trading Securities
|
|
|
(669,307
|
)
|
|
|
(341,666
|
)
|
|
Sale
of Trading Securities
|
|
|
666,515
|
|
|
|
340,011
|
|
|
Income
Taxes Paid, net
|
|
|
(2,316,211
|
)
|
|
|
(1,840,264
|
)
|
|
Net
Cash Provided by Operating Activities
|
|
$
|
9,488,931
|
|
|
$
|
5,218,413
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
Maturity
of Available for Sale Securities
|
|
|
18,290,624
|
|
|
|
12,141,847
|
|
|
Purchase
of Available for Sale Securities
|
|
|
(23,262,903
|
)
|
|
|
(14,092,999
|
)
|
|
Proceeds
from Disposal of Property
|
|
|
24,016
|
|
|
|
643,762
|
|
|
Purchase
of Property, Plant and Equipment
|
|
|
(3,878,372
|
)
|
|
|
(2,663,354
|
)
|
|
Cash
Distributions from Equity Investments
|
|
|
258,625
|
|
|
|
24,000
|
|
|
Net
Cash Applied to Investing Activities
|
|
$
|
(8,568,010
|
)
|
|
$
|
(3,946,744
|
)
|
See
Accompanying Notes
THE
RESERVE PETROLEUM COMPANY
STATEMENTS
OF CASH FLOWS
|
|
|
Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Cash
Flows Applied to Financing Activities:
|
|
|
|
|
|
|
|
Dividends
Paid to Shareholders
|
|
$
|
(883,052
|
)
|
|
$
|
(608,403
|
)
|
|
Purchase
of Treasury Stock
|
|
|
(127,200
|
)
|
|
|
(45,680
|
)
|
|
Total
Cash Applied to Financing Activities
|
|
$
|
(1,010,252
|
)
|
|
$
|
(654,083
|
)
|
|
Net
Change in Cash and Cash Equivalents
|
|
|
(89,331
|
)
|
|
|
617,586
|
|
|
Cash
and Cash Equivalents at Beginning of Year
|
|
|
1,321,707
|
|
|
|
704,121
|
|
|
Cash
and Cash Equivalents at End of Year
|
|
$
|
1,232,376
|
|
|
$
|
1,321,707
|
|
Reconciliation
of Net Income to Net
Cash Provided by Operating
Activities:
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
$
|
7,527,876
|
|
|
$
|
4,274,921
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income Increased (Decreased) by - Net Change in -
|
|
|
|
|
|
|
|
|
|
Unrealized
Holding (Gains) on Trading Securities
|
|
|
(31,309
|
)
|
|
|
(27,235
|
)
|
|
Accounts
Receivable
|
|
|
328,940
|
|
|
|
(479,326
|
)
|
|
Interest
and Dividends Receivable
|
|
|
(11,268
|
)
|
|
|
(45,050
|
)
|
|
Income
Taxes Refundable/Payable
|
|
|
205,641
|
|
|
|
(383,959
|
)
|
|
Accounts
Payable
|
|
|
17,280
|
|
|
|
(21,773
|
)
|
|
Trading
Securities
|
|
|
(16,163
|
)
|
|
|
(8,060
|
)
|
|
Other
Assets
|
|
|
(111,283
|
)
|
|
|
(7,876
|
)
|
|
Deferred
Taxes
|
|
|
401,906
|
|
|
|
19,830
|
|
|
Other
Liabilities
|
|
|
(36,379
|
)
|
|
|
42,582
|
|
|
Equity
Income in Investees
|
|
|
(66,065
|
)
|
|
|
(14,263
|
)
|
|
Gain
from Sale of Equity Investment
|
|
|
(175,458
|
)
|
|
|
---
|
|
|
Disposition
of Property & Equipment
|
|
|
(17,636
|
)
|
|
|
77,893
|
|
|
Depreciation,
Depletion, Amortization and Valuation Provisions
|
|
|
1,472,849
|
|
|
|
1,790,729
|
|
|
Net
Cash Provided by Operating Activities
|
|
$
|
9,488,931
|
|
|
$
|
5,218,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 ACCOUNTING
POLICIES
Cash & 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
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 material.
Trading
securities, which consist primarily of equity securities, are carried at fair
value with unrealized gains and losses reported in current
earnings.
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 is not required.
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
Deferred
income taxes are provided for significant carryforwards and temporary
differences using the liability method. See Note 6 for additional
information.
Net Income Per
Share
Net
income per share is calculated based on the weighted average of the number of
shares outstanding during the year. There are no dilutive
shares.
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 three purchasers in 2007 and two
purchasers in 2006 whose purchases were in excess of 10% of total oil and gas
sales. In 2007, ConocoPhillips 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. In 2006, XTO Energy purchases were $1,494,274, or 15.4% of
total oil and gas sales and Burlington Resources purchases were $1,719,354 or
17.7% 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. Actual results could differ from
those estimates.
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, FASB 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 market 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 and the effect of guarantees issued in 2002 are discussed in Note
7.
Asset Retirement
Obligations
In June
2001, the
Financial
Accounting Standards Board (“FASB”)
issued SFAS No. 143,
Accounting for Asset Retirement
Obligations.
SFAS No. 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. The Company has assessed the impact of SFAS No. 143
and based on the results of the assessment believes the impact of this statement
is immaterial to its financial position and results of operations.
Accounting
Changes
During
2007 the
Company
adopted Financial Accounting Standards
Board (FASB) Statement No. 157, “
Fair Value Measurements
”,
(SFAS No. 157) and Interpretation 48, “
Accounting for Uncertainty in Income
Taxes
”, (FIN 48). See Note 6 for FIN 48 disclosures and Note 9
for SFAS No. 157 accounting and disclosures. Our implementation of SFAS No. 157
required no change from the Company’s previous accounting methods or disclosures
for financial instruments.
In December 2007, the FASB issued
SFAS No. 141R,
"Business
Combinations",
a revision of
SFAS No.141,
"
Business Combinations
"
and SFAS No. 160,
"Noncontrolling Interests in
Consolidated Financial Statements - an amendment of ARB No. 51"
. SFAS No.
141R will apply to all business combinations and will require most identifiable
assets, liabilities, noncontrolling interests, and goodwill acquired in a
business combination to be recorded at "full fair value" at the acquisition date
and require transaction-related costs to be expensed in the period incurred,
rather than capitalizing these costs as a component of the purchase price. SFAS
No.160 changes the accounting and reporting for noncontrolling interests in
consolidated financial statements. SFAS No. 141R is effective for acquisitions
completed after January 1, 2009 and SFAS No. 160 is effective for fiscal years
beginning on or after December 15, 2008. The adoption of these pronouncements
should have no impact on the Company's results of
operations.
Also in December 2007, the
Securities and Exchange Commission issued SAB 110,
"Certain Assumptions Used in
Valuation Methods"
, which extends the use of the "simplified" method,
under certain circumstances, in developing an estimate of expected term of
"plain vanilla" share options in accordance with SFAS No. 123R. This bulletin
has no impact on the Company as we have never issued stock options.
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.
The
following table summarizes the changes in common stock issued and
outstanding:
|
|
|
Shares
|
|
|
Shares
of
Treasury
|
|
|
Shares
|
|
|
|
|
Issued
|
|
|
Stock
|
|
|
Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1, 2006, $.50par value stock, 400,000 shares authorized
|
|
|
184,735.28
|
|
|
|
21,101.64
|
|
|
|
163,633.64
|
|
|
Purchase
of stock
|
|
|
-
|
|
|
|
313.00
|
|
|
|
(313.00
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2006, $.50par 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, $.50par value stock, 400,000 shares authorized
|
|
|
184,735.28
|
|
|
|
22,209.64
|
|
|
|
162,525.64
|
|
Note 5
-
INVESTMENTS IN DEBT AND
EQUITY SECURITIES
At
December 31, 2007 and 2006, 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 required. The
available for sale securities by contractual maturity are as follows at December
31, 2007:
|
Due
within one year or less
|
|
|
$
|
12,445,531
|
|
As to the
trading securities held at year end, unrealized trading gains included in
earnings were $31,309 for 2007 and $27,235 for 2006.
Components
of deferred taxes follow:
|
|
|
December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Assets
|
|
|
|
|
|
|
|
Leasehold
Costs
|
|
$
|
321,115
|
|
|
$
|
403,749
|
|
|
Gas
Balancing Receivable
|
|
|
52,379
|
|
|
|
52,379
|
|
|
Long-Lived
Asset Impairment
|
|
|
379,245
|
|
|
|
442,968
|
|
|
Other
|
|
|
19,313
|
|
|
|
33,906
|
|
|
Total
Assets
|
|
|
772,052
|
|
|
|
933,002
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
Marketable
Securities
|
|
|
23,214
|
|
|
|
12,447
|
|
|
Receivables
|
|
|
309,690
|
|
|
|
486,309
|
|
|
Intangible
Development Costs and Depreciation
|
|
|
1,940,737
|
|
|
|
1,533,930
|
|
|
Total
Liabilities
|
|
|
2,273,641
|
|
|
|
2,032,686
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Deferred Tax Liability
|
|
$
|
(1,501,589
|
)
|
|
$
|
(1,099,684
|
)
|
The
following table summarizes the current and deferred portions of income tax
expense.
|
|
|
Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Current
Tax Provision:
|
|
|
|
|
|
|
|
Federal
|
|
$
|
2,500,860
|
|
|
$
|
1,442,705
|
|
|
State
|
|
|
20,992
|
|
|
|
13,600
|
|
|
|
|
|
2,521,852
|
|
|
|
1,456,305
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
Provision
|
|
|
401,906
|
|
|
|
19,830
|
|
|
Total
Provision
|
|
$
|
2,923,758
|
|
|
$
|
1,476,135
|
|
The total
provision for income tax expressed as a percentage of income before income tax
was 28% in 2007 and 25% in 2006. These amounts differ from the
amounts computed by applying the statutory US Federal income tax rate of 34% for
2007 and 2006 to income before income tax as summarized in the following
reconciliation:
|
|
|
Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Computed
Federal Tax
|
|
|
|
|
|
|
|
Provision
|
|
$
|
3,553,556
|
|
|
$
|
1,950,599
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(Decrease) in Tax From:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowable
Depletion in Excess of Basis
|
|
|
(696,697
|
)
|
|
|
(501,642
|
)
|
|
Dividend
Received Deduction
|
|
|
(439
|
)
|
|
|
(408
|
)
|
|
State
Income Tax Provision
|
|
|
20,992
|
|
|
|
13,600
|
|
|
Other
|
|
|
46,346
|
|
|
|
13,986
|
|
|
Provision
for Income Tax
|
|
$
|
2,923,758
|
|
|
$
|
1,476,135
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective
Tax Rate
|
|
|
28
|
%
|
|
|
25
|
%
|
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, 2007 includes two tax
positions that should be disclosed as a result of the implementation of FIN 48.
One position concerns the recognition of income relating to estimated revenue
accruals. The other position concerns the deductibility of expense
relating to leasehold cost depletion. 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. Assuming 100% probability
of disallowance, the interest and penalties that could result would be
immaterial to the current operating results.
The
Company recognizes interest and penalties related to unrecognized tax benefits
in income tax expense. As of December 31, 2006 and 2007, the Company had an
approximate $50,000 tax liability accrued for this contingency.
|
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 %
|
|
|
2007
|
|
|
2006
|
|
|
Broadway
Sixty-Eight, Ltd.
|
|
|
33%
|
|
|
|
378,624
|
|
|
$
|
336,476
|
|
|
JAR
Investment, LLC
|
|
|
25%
|
|
|
|
(6,901
|
)
|
|
|
(151
|
)
|
|
Millennium
Golf Properties, LLC
|
|
|
9%
|
|
|
|
-
|
|
|
|
49,862
|
|
|
OKC
Industrial Properties, L.L.C.
|
|
|
10%
|
|
|
|
51,655
|
|
|
|
54,293
|
|
|
|
|
|
|
|
|
$
|
423,378
|
|
|
$
|
440,480
|
|
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.
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, 2007 and 2006.
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 $148,419 at December 31, 2007. This loan matures
November 27, 2008. Because the guarantee of the M-E loan has
not been modified subsequent to December 31, 2002, no liability for the fair
value of the obligation is required to be recorded by the
Company. The maximum potential amount of future payments
(undiscounted) the Company could be required to make under the M-E guarantee at
December 31, 2007 (based on the original loan amount) is $169,750 plus costs and
expenses related to enforcement and collection.
In late
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, the JAR bank loan secured by the property being
sold was paid off and the Company’s guarantee agreement relating to this loan
was terminated.
In
December 2007, the Company sold its 9% ownership in Millennium Golf Properties,
LLC an Oklahoma limited liability company to the remaining owners for $225,000.
The sale resulted in a gain of $175,458 recorded in the 2007 results of
operations.
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,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Acquisition
of Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved
|
|
$
|
531,971
|
|
|
$
|
388,653
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
Costs
|
|
$
|
1,148,093
|
|
|
$
|
2,006,234
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
Costs
|
|
$
|
2,592,319
|
|
|
$
|
806,886
|
|
Note 9
-
FINANCIAL
INSTRUMENTS
The
following table includes various estimated fair value information as of December
31, 2007 and 2006, which pertains to the Company's financial instruments and
does not purport to represent the aggregate net fair value of the
Company. The carrying amounts in the table below are the amounts at
which
the financial
instruments are reported in the financial statements.
All of
the Company's financial instruments are held for purposes other than trading,
except for trading securities.
The
following methods and assumptions were used to estimate the fair value of each
class of financial instruments for which it is practicable to estimate that
value:
1.
Cash and Cash
Equivalents
The
carrying amount approximates fair value because of the short maturity and highly
liquid nature of those instruments.
2.
Available for Sale
Securities
The
estimated fair values are based upon quoted market prices.
3.
Trading
Securities
The
estimated fair values are based upon quoted market prices.
4.
Dividends
Payable
The
carrying amount approximates fair value. Fair value is the amount
that will be paid on demand at the reporting date.
The
carrying amounts and estimated fair values of the Company's financial
instruments are as follows:
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Carrying
|
|
|
Estimated
|
|
|
Carrying
|
|
|
Estimated
|
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Amount
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
1,232,376
|
|
|
$
|
1,232,376
|
|
|
$
|
1,321,707
|
|
|
$
|
1,321,707
|
|
|
Available
for Sale Securities
|
|
|
12,445,531
|
|
|
|
12,445,531
|
|
|
|
7,473,252
|
|
|
|
7,473,252
|
|
|
Trading
Securities
|
|
|
337,201
|
|
|
|
337,201
|
|
|
|
289,729
|
|
|
|
289,729
|
|
|
Financial
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
Payable
|
|
|
(324,930)
|
|
|
|
(324,930)
|
|
|
|
(230,879)
|
|
|
|
(230,879)
|
|
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 $67,745 for the year
ended December 31, 2007 and $597,751 for the year ended December 31, 2006 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 2007 and 2006:
|
|
|
2007
|
|
|
2006
|
|
|
Net
Realized and Unrealized Gain On Trading Securities
|
|
$
|
44,680
|
|
|
$
|
33,641
|
|
|
Gain
on Asset Sales
|
|
|
193,094
|
|
|
|
148,886
|
|
|
Interest
Income
|
|
|
498,430
|
|
|
|
326,598
|
|
|
Settlements
of Class Action Lawsuits
|
|
|
468
|
|
|
|
2,925
|
|
|
Agricultural
Rental Income
|
|
|
5,600
|
|
|
|
5,600
|
|
|
Dividend
and Other Income
|
|
|
1,791
|
|
|
|
3,193
|
|
|
Interest
and Other Expenses
|
|
|
(4,247)
|
|
|
|
(4,287)
|
|
|
Other
Income, Net
|
|
$
|
739,816
|
|
|
$
|
516,556
|
|
Note 12 -
CERTAIN RELATIONSHIPS
AND RELATED TRANSACTIONS.
The
Company is affiliated by common management and ownership with Mesquite Minerals,
Inc., (Mesquite), Mid-American Oil Company (Mid-American), Lochbuie Limited
Partnership (LLTD) and Lochbuie Holding Company (LHC). The Company also owns
interests in certain producing and non-producing oil and gas properties as
tenants in common with Mesquite, Mid-American and LLTD.
Mesquite,
Mid-American and LLTD share facilities and employees, including executive
officers, with the Company. The Company has been reimbursed for
services, facilities and miscellaneous business expenses incurred during 2007 by
payment to the Company in the amount of $129,539 by Mesquite, $129,539 by
Mid-American and $129,539 by LLTD. Reimbursements for 2006 were $196,011 by
Mesquite, $138,361 by Mid-American and $92,241 by LLTD. Included in
the 2007 amounts, Mesquite paid $85,109, Mid-American $85,109 and LLTD $85,109
for their share of salaries. In 2006, the share of salaries paid by
Mesquite was $127,441, Mid-American $89,959, and LLTD $59,972.
UNAUDITED
SUPPLEMENTAL FINANCIAL INFORMATION
SUPPLEMENTAL
SCHEDULE 1
THE
RESERVE PETROLEUM COMPANY
WORKING
INTERESTS RESERVE QUANTITY INFORMATION
(Unaudited)
|
|
|
Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Oil
& Natural Gas Liquids (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
Developed and Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning
of Year
|
|
|
232,438
|
|
|
|
112,639
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of Previous Estimates
|
|
|
(23,101
|
)
|
|
|
(4,831
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Extensions
and Discoveries
|
|
|
143,505
|
|
|
|
93,250
|
|
|
|
|
|
|
|
|
|
|
|
|
Improved
Recovery
|
|
|
-
|
|
|
|
58,315
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(61,853
|
)
|
|
|
(26,935
|
)
|
|
|
|
|
|
|
|
|
|
|
|
End
of Year
|
|
|
290,989
|
|
|
|
232,438
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning
of Year
|
|
|
232,438
|
|
|
|
112,639
|
|
|
|
|
|
|
|
|
|
|
|
|
End
of Year
|
|
|
290,989
|
|
|
|
232,438
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(MCF)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
Developed and Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning
of Year
|
|
|
1,710,576
|
|
|
|
1,637,881
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of Previous Estimates
|
|
|
71,721
|
|
|
|
50,425
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions
and Discoveries
|
|
|
227,161
|
|
|
|
349,555
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(345,098
|
)
|
|
|
(327,285
|
)
|
|
|
|
|
|
|
|
|
|
|
|
End
of Year
|
|
|
1,664,360
|
|
|
|
1,710,576
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning
of Year
|
|
|
1,710,576
|
|
|
|
1,637,881
|
|
|
|
|
|
|
|
|
|
|
|
|
End
of Year
|
|
|
1,664,360
|
|
|
|
1,710,576
|
|
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 13,181 Bbls of oil and 1,052,063 MCF of gas for the
year ended December 31, 2007, and 15,418 Bbls of oil and
794,760 MCF of gas for the year ended December 31,
2006.
|
|
|
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, 2007 and
2006. 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.
|
|
|
4.
|
The
oil reserves added in 2006 due to “Improved Recovery” represent reserves
added as a result of a production response to secondary recovery efforts
in a South Dakota waterflood
unit.
|
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,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
Future
Cash Inflows
|
|
$
|
35,190,438
|
|
|
$
|
24,863,088
|
|
|
|
|
|
|
|
|
|
|
|
|
Future
Production and Development Costs
|
|
|
(8,837,987
|
)
|
|
|
(7,264,337
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Future
Income Tax Expense
|
|
|
(6,360,828
|
)
|
|
|
(4,074,274
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Future
Net Cash Flows
|
|
|
19,991,623
|
|
|
|
13,524,477
|
|
|
|
|
|
|
|
|
|
|
|
|
10%
Annual Discount for Estimated Timing of Cash Flows
|
|
|
(7,189,387
|
)
|
|
|
(4,623,498
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
Measure of Discounted Future Net Cash Flows
|
|
$
|
12,802,236
|
|
|
$
|
8,900,979
|
|
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,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Standardized
Measure, Beginning of Year
|
|
$
|
8,900,979
|
|
|
$
|
7,581,451
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
and Transfers, Net of Production Costs
|
|
|
(5,192,909
|
)
|
|
|
(2,976,797
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
Change in Sales and Transfer Prices, Net of Production
Costs
|
|
|
3,248,497
|
|
|
|
(2,151,180
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Extensions,
Discoveries and Improved Recoveries, Net of Future Production and
Development Costs
|
|
|
5,585,157
|
|
|
|
5,248,422
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of Quantity Estimates
|
|
|
730,817
|
|
|
|
86,611
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion
of Discount
|
|
|
1,120,315
|
|
|
|
1,051,479
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Change in Income Taxes
|
|
|
(1,771,303
|
)
|
|
|
631,164
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in Production Rates(Timing) and Other
|
|
|
180,682
|
|
|
|
(570,171
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
Measure, End of Year
|
|
$
|
12,802,235
|
|
|
$
|
8,900,979
|
|
|
ITEM
8.
|
CH
ANGE
S IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
|
None
.
I
TEM 8A(T). CO
NTRO
LS 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, 2007.
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, 2007 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, 2007.
This
Annual Report on Form 10-KSB 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-KSB.
|
/s/ Mason McLain
|
|
/s/ James L. Tyler
|
|
Mason
McLain, President
|
|
James
L. Tyler, 2
nd
Vice President
|
|
Principal
Executive Officer
|
|
Principal
Financial Officer
|
|
March
26, 2008
|
|
March
26, 2008
|
PART
III
|
ITEM
9.
|
DI
REC
TORS, EXECUTIVE OFFICERS, PROMOTERS, CONTROL PERSONS AND
CORPORATE GOVERNANCE;
COMPLIANCE
WITH SECTION 16(a) OF THE EXCHANGE ACT.
|
|
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
10.
|
EX
ECUTI
VE COMPENSATION.
|
Information
regarding executive compensation in the Proxy Statement is incorporated herein
by reference.
|
ITEM
11.
|
SEC
URITY
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
12.
|
C
ERTAI
N RELATIONSHIPS AND RELATED
TRANSACTIONS.
|
See Item
6, “Management’s Discussion and Analysis or Plan of Operations” and Item 7, Note
12 to Financial Statements. Information regarding the independence of
our directors in the Proxy Statement is incorporated herein by
reference.
The
following documents are exhibits to this Form 10-KSB. Each document
marked by an asterisk is filed electronically herewith.
|
Exhibit
Number
|
|
Description
|
|
|
|
|
|
3.1
|
|
Restated
Certificate of Incorporation dated November 1, 1988 is incorporated by
reference to Exhibit 3.1 of The Reserve Petroleum Company’s Annual Report
on Form 10-KSB (Commission File No. 0-8157) filed March 28,
1997.
|
|
|
|
|
|
3.2
|
|
Amended
By-Laws dated November 16, 2004 are incorporated by reference to Exhibit
3.2 of The Reserve Petroleum Company’s Annual Report on Form 10-KSB
(Commission File No. 0-8157) filed March 30, 2006.
|
|
|
|
|
|
14
|
|
Code
of Ethics incorporated by reference to Exhibit 14 of The Reserve Petroleum
Company’s Annual Report on Form 10-KSB (Commission File No. 0-8157) filed
March 30, 2006.
|
|
|
|
|
|
|
|
Certification
of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a)
under the Securities Exchange Act of 1934, as amended.
|
|
|
|
|
|
|
|
Certification
of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a)
under the Securities Exchange Act of 1934, as amended.
|
|
|
|
|
|
|
|
Certification
of Principal Executive Officer and Principal Financial Officer Pursuant to
18 U.S.C. Section 1350.
|
|
ITEM
14.
|
PRIN
CIPA
L 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.
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
26, 2008
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
26, 2008
|
|
March
26, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Robert L. Savage
|
|
/s/ William M. Smith
|
|
|
Robert
L. Savage (Director)
|
|
William
M. Smith (Director)
|
|
|
March
26, 2008
|
|
March
26, 2008
|
|
48
Reserve Petroleum (PK) (USOTC:RSRV)
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Reserve Petroleum (PK) (USOTC:RSRV)
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