RESERVE PETROLEUM CO - Quarter Report: 2012 September (Form 10-Q)

Unassociated Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2012

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 0-8157

THE RESERVE PETROLEUM COMPANY

(Exact Name of Registrant as Specified in Its Charter)

DELAWARE		73-0237060
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
6801 BROADWAY EXT., SUITE 300 OKLAHOMA CITY, OKLAHOMA 73116-9037 (405) 848-7551
(Address and telephone number, including area code, of registrant’s principal executive offices)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of November 9, 2012, 160,915.64 shares of the Registrant’s $.50 par value common stock were outstanding.

PART I – FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

THE RESERVE PETROLEUM COMPANY

BALANCE SHEETS

ASSETS

	September 30,		December 31,
	2012		2011
	(Unaudited)		(Derived from audited financial Statements)

Current Assets:
Cash and Cash Equivalents	$	10,221,666	$	10,150,742
Available-for-Sale Securities		6,652,196		6,654,838
Trading Securities		396,833		398,964
Refundable Income Taxes		438,540		816,125
Receivables		1,786,596		1,903,862
		19,495,831		19,924,531
Investments:
Equity Investment		571,811		521,852
Other		151,839		151,839
		723,650		673,691
Property, Plant and Equipment:
Oil and Gas Properties, at Cost, Based on the Successful Efforts Method of Accounting – Unproved Properties		893,783		1,179,882
Proved Properties		38,019,059		32,441,403
		38,912,842		33,621,285

Less – Accumulated Depreciation, Depletion, Amortization and Valuation Allowance		23,138,533		21,177,541
		15,774,309		12,443,744
Other Property and Equipment, at Cost		422,598		417,526

Less – Accumulated Depreciation		258,223		227,895
		164,375		189,631
Total Property, Plant and Equipment		15,938,684		12,633,375
Other Assets		361,606		361,802
Total Assets	$	36,519,771	$	33,593,399

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY

BALANCE SHEETS

LIABILITIES AND STOCKHOLDERS’ EQUITY

	September 30,		December 31,
	2012		2011
	(Unaudited)		(Derived from audited financial Statements)

Current Liabilities:
Accounts Payable	$	337,392	$	276,017
Other Current Liabilities – Deferred Income Taxes and Other		345,279		292,166
		682,671		568,183

Long-Term Liabilities:
Asset Retirement Obligation		1,125,599		990,074
Dividends Payable		1,427,108		1,419,884
Deferred Tax Liability		3,413,772		2,726,978
		5,966,479		5,136,936
Total Liabilities		6,649,150		5,705,119

Stockholders’ Equity:
Common Stock		92,368		92,368
Additional Paid-in Capital		65,000		65,000
Retained Earnings		30,562,895		28,563,474
		30,720,263		28,720,842

Less – Treasury Stock, at Cost		849,642		832,562
Total Stockholders’ Equity		29,870,621		27,888,280
Total Liabilities and Stockholders’ Equity	$	36,519,771	$	33,593,399

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Operating Revenues:
Oil and Gas Sales	$	3,061,322	$	3,162,945	$	9,407,923	$	9,010,262
Lease Bonuses and Other		167,063		85,327		399,375		344,364
		3,228,385		3,248,272		9,807,298		9,354,626
Operating Costs and Expenses:
Production		595,196		516,527		1,736,733		1,486,727
Exploration		86,141		16,306		185,095		55,022
Depreciation, Depletion, Amortization and Valuation Provisions		717,724		757,135		2,330,648		1,802,037
General, Administrative and Other		366,790		317,444		1,197,722		1,088,282
		1,765,851		1,607,412		5,450,198		4,432,068

Income from Operations		1,462,534		1,640,860		4,357,100		4,922,558
Other Income, Net		19,933		708,180		514,128		1,008,260
Income before Provision for Income Taxes		1,482,467		2,349,040		4,871,228		5,930,818
Provision for Income Taxes:
Current		14,009		396,590		627,604		999,900
Deferred		316,727		279,621		634,907		628,100
Total Provision for Income Taxes		330,736		676,211		1,262,511		1,628,000
Net Income	$	1,151,731	$	1,672,829	$	3,608,717	$	4,302,818
Per Share Data
Net Income, Basic and Diluted	$	7.16	$	10.39	$	22.42	$	26.70

Cash Dividends Declared and/or Paid	$	—	$	—	$	10.00	$	10.00

Weighted Average Shares Outstanding, Basic and Diluted		160,920		161,074		160,946		161,147

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
	2012			2011

Net Cash Provided by Operating Activities	$	6,698,435		$	6,112,313

Cash Flows Applied to Investing Activities:
Purchases of Available-for-Sale Securities		(6,652,196	)		(12,893,876	)
Maturity of Available-for-Sale Securities		6,654,838			14,988,500
Proceeds from Disposal of Property, Plant and Equipment		493,763			1,207,329
Purchase of Property, Plant and Equipment		(5,504,763	)		(4,728,049	)

Net Cash Applied to Investing Activities		(5,008,358	)		(1,426,096	)

Cash Flows Applied to Financing Activities:
Dividends Paid to Stockholders		(1,602,073	)		(1,611,399	)
Purchase of Treasury Stock		(17,080	)		(40,000	)

Total Cash Applied to Financing Activities		(1,619,153	)		(1,651,399	)

Net Change in Cash and Cash Equivalents		70,924			3,034,818

Cash and Cash Equivalents, Beginning of Period		10,150,742			2,940,967

Cash and Cash Equivalents, End of Period	$	10,221,666		$	5,975,785

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY

NOTES TO FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

Note 1 – BASIS OF PRESENTATION

The accompanying balance sheet as of December 31, 2011, which has been derived from audited financial statements, the unaudited interim financial statements and these notes, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain disclosures normally included in financial statements prepared in accordance with the accounting principles generally accepted in the United States of America (“GAAP”) have been omitted. The accompanying financial statements and notes thereto should be read in conjunction with the financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

In the opinion of Management, the accompanying financial statements reflect all adjustments (consisting only of normal recurring accruals), which are necessary for a fair statement of the results of the interim periods presented. The results of operations for the current interim periods are not necessarily indicative of the operating results for the full year.

Note 2 – OTHER INCOME, NET

The following is an analysis of the components of Other Income, Net for the three months and nine months ended September 30, 2012 and 2011:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Net Realized and Unrealized Loss on Trading Securities	$	(12,102	)	$	(87,549	)	$	(3,278	)	$	(85,526	)
Gain on Asset Sales		12,682			807,438			447,255			1,076,670
Interest Income		8,479			3,561			24,595			15,896
Equity Earnings in Investee		11,799			10,376			49,959			34,847
Other Income		6,604			491			22,477			9,536
Interest and Other Expenses		(7,529	)		(26,137	)		(26,880	)		(43,163	)
Other Income, Net	$	19,933		$	708,180		$	514,128		$	1,008,260

Note 3 –

INVESTMENTS AND RELATED COMMITMENTS AND CONTINGENT LIABILITIES, INCLUDING GUARANTEES

Equity Investment consists of a 33% ownership interest in Broadway Sixty-Eight, Ltd. (the “Partnership”), an Oklahoma limited partnership, which owns and operates an office building in Oklahoma City, Oklahoma. Although the Company invested as a limited partner, it agreed, jointly and severally, with all other limited partners to reimburse the general partner for any losses suffered from operating the Partnership. The indemnity agreement provides no limitation to the maximum potential future payments. To date, no monies have been paid with respect to this agreement.

Note 4 – PROVISION FOR INCOME TAXES

In 2012 and 2011, the effective tax rate was less than the statutory rate, primarily as a result of allowable depletion for tax purposes in excess of the cost basis in oil and gas properties and the corporate graduated tax rate structure.

Excess federal percentage depletion, which is limited to certain production volumes and by certain income levels reduces estimated taxable income projected for any year. The federal excess percentage depletion estimates will be updated throughout the year until finalized with the detail well-by-well calculations at year-end. When a provision for income taxes is recorded, federal excess percentage depletion benefits decrease the effective tax rate. The benefit of federal excess percentage depletion is not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where a recorded pre-tax income is relatively small, the proportional effect of these items on the effective tax rate may be significant.

Note 5 – ASSET RETIREMENT OBLIGATION

The Company records the fair value of its estimated liability to retire its oil and natural gas producing properties in the period in which it is incurred (typically the date of first sale). The estimated liability is calculated by obtaining current estimated plugging costs from the well operators and inflating it over the life of the property. Current year inflation rate used is 4.08%. When the liability is first recorded, a corresponding increase in the carrying amount of the related long-lived asset is also recorded. Subsequently, the asset is amortized to expense over the life of the property and the liability is increased annually for the change in its present value which is currently 3.25%.

A reconciliation of the Company’s asset retirement obligation liability is as follows:

Balance at December 31, 2011	$	990,074
Liabilities incurred for new wells		113,204
Accretion expense		22,321
Balance at September 30, 2012	$	1,125,599

Note 6 – FAIR VALUE MEASUREMENTS

Inputs used to measure fair value are organized into a fair value hierarchy based on the observability of the inputs. Level 1 inputs consist of quoted prices in active markets for identical assets. Level 2 inputs are inputs, other than quoted prices, for similar assets that are observable. Level 3 inputs are unobservable inputs.

Recurring Fair Value Measurements

Certain of the Company’s assets are reported at fair value in the accompanying balance sheets on a recurring basis. The Company determined the fair value of the available-for-sale securities using quoted market prices for securities with similar maturity dates and interest rates. At September 30, 2012 and December 31, 2011, the Company’s assets reported at fair value on a recurring basis are summarized as follows:

	September 30, 2012
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for Sale Securities – U.S. Treasury Bills Maturing in 2012	$	—	$	6,652,196	$	—
Trading Securities:
Domestic Equities	$	267,394	$	—	$	—
International Equities	$	86,801	$	—	$	—
Others	$	42,638	$	—	$	—

	December 31, 2011
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for Sale Securities – U.S. Treasury Bills Maturing in 2012	$	—	$	6,654,838	$	—
Trading Securities:
Domestic Equities	$	275,516	$	—	$	—
International Equities	$	95,223	$	—	$	—
Others	$	28,225	$	—	$	—

Non-Recurring Fair Value Measurements

The Company’s asset retirement obligation annually represents a non-recurring fair value liability. The fair value of the non-financial liability incurred in the nine months ended September 30, was $113,204 in 2012 and $83,625 in 2011 and was calculated using Level 3 inputs. See Note 5 above for more information about this liability and the inputs used for calculating fair value.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, trade receivables, marketable securities, trade payables and dividends payable. At September 30, 2012 and December 31, 2011, the historical cost of cash and cash equivalents, trade receivables, trade payables and dividends payable are considered to be representative of their respective fair values due to the short-term maturities of these items.

Note 7 – SUBSEQUENT EVENTS

On November 8, 2012 the Company received $1,773,223 as a bonus for a lease of 3,733 net acres of owned minerals in Austin and Colorado Counties, Texas. This amount will be reflected as lease bonus revenue in the 2012 fourth quarter results included in the Company’s Form 10-K Annual Report for the year ending December 31, 2012.

Management plans to recommend to the Company’s Board of Directors the payment of an extra dividend of $10.00 per share to current shareholders prior to the end of November, 2012.

Note 8 – NEW ACCOUNTING PRONOUNCEMENTS

There were no accounting pronouncements issued and none that became effective since December 31, 2011 that were directly applicable to the Company.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This discussion and analysis should be read with reference to a similar discussion in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011 as filed with the Securities and Exchange Commission and the Form 10-K/A as filed with the Securities and Exchange Commission on September 25, 2012 (collectively referred to as the “2011 Form 10-K”), as well as the financial statements included in this Form 10-Q.

Forward Looking Statements

This discussion and analysis includes 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 give the Company’s current expectations of future events. They include statements regarding the drilling of oil and gas wells, the production that may be obtained from oil and gas wells, cash flow and anticipated liquidity and expected future expenses.

Although management believes the expectations in these and other forward looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that would cause actual results to differ materially from expected results are described under “Forward Looking Statements” on page 8 of the 2011 Form 10-K.

We caution you not to place undue reliance on these forward looking statements, which speak only as of the date of this report, and we undertake no obligation to update this information. You are urged to carefully review and consider the disclosures made in this and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect our business.

Financial Conditions and Results of Operations

Liquidity and Capital Resources

Please refer to the Balance Sheets and the Condensed Statements of Cash Flows in this Form 10-Q to supplement the following discussion. In the first nine months of 2012, the Company continued to fund its business activity through the use of internal sources of cash. The Company had cash provided by operations of $6,698,435 and cash provided by the maturities of available-for-sale securities of $6,654,838. Additional cash of $493,763 was provided by property dispositions for total cash provided of $13,812,175. The Company utilized cash for the purchase of available-for-sale securities of $6,652,196; property additions of $5,504,763 and financing activities of $1,619,153 for total cash applied of $13,741,251. Cash and cash equivalents increased $70,924 to $10,221,666.

Discussion of Significant Changes in Working Capital. In addition to the changes in cash and cash equivalents discussed above, there were other changes in working capital line items from December 31, 2011. A discussion of these items follows.

Refundable income taxes declined $377,585 (46%) from $816,125 to $438,540. This decrease was due primarily to the current income tax provision for the nine months ended September 30, 2012 of $627,604 offset by estimated tax payments of $250,000 for the same period.

Receivables decreased $117,266 (6%) to $1,786,596 from $1,903,862. This decline was the net result of a sales receivable decline of approximately $132,000 offset by an increase of other receivables of approximately $15,000. Sales variances are discussed in the “Results of Operations” section below.

Accounts payable increased $61,375 (22%) to $337,392 from $276,017. This increase was due primarily to increased drilling activity at September 30, 2012 versus December 31, 2011.

Deferred income taxes and other liabilities increased $53,113 (18%) to $345,279 from $292,166. The increase is primarily due to an increase of $105,000 in ad valorem tax accruals. Ad valorem (property) taxes are primarily for Texas properties and are accrued for the first three quarters each year to be paid in the fourth quarter. This increase was offset by a decline in current deferred income taxes of $51,887.

Discussion of Significant Changes in the Condensed Statements of Cash Flows. As noted in the first paragraph above, net cash provided by operating activities was $6,698,435 in 2012, an increase of $586,122 (10%) from the comparable period in 2011. The increase was primarily due to increased oil and gas sales revenue and lower current income tax expense for 2012 compared to 2011. For more information see “Operating Revenues” and “Operating Costs and Expenses” below.

Net cash provided by the purchase and sale of available-for-sale securities in 2012 was $2,642 compared to net cash provided in 2011 of $2,094,624.

Purchases of available-for-sale securities were $6,652,196 in 2012, a decrease of $6,241,680 (48%) from the comparable period in 2011. The decline was the result of investing a portion of the proceeds from maturing securities in the fourth quarter of 2011 in money market accounts with higher interest rates than the short-term treasury bill rates.

Property disposal proceeds in 2012 were $493,763, a decrease of $713,566 from the comparable period in 2011. The decrease was primarily due to 2011 sales of non-producing leaseholds in Oklahoma and Kansas with fewer similar sales in 2012.

Cash applied to the purchase of property, plant and equipment in 2012 was $5,504,763, an increase of $776,714 (16%) from cash applied in 2011 of $4,728,049. In both 2012 and 2011, cash applied to property, plant and equipment additions was mostly related to oil and gas exploration and development activity. The change is due to increased drilling activity in 2012 compared to 2011. See the subheading “Exploration Costs” in the “Results of Operations” section below for additional information.

Conclusion. Management is unaware of any additional material trends, demands, commitments, events or uncertainties, which would impact liquidity and capital resources to the extent that the discussion presented in the 2011 Form 10-K would not be representative of the Company’s current position.

Material Changes in Results of Operations Nine Months Ended September 30, 2012, Compared with Nine Months Ended September30, 2011

Net income decreased $694,101 (16%) to $3,608,717 in 2012 from $4,302,818 in 2011. Net income per share, basic and diluted, decreased $4.28 to $22.42 in 2012 from $26.70 in 2011.

A discussion of revenue from oil and gas sales and other significant line items in the statements of income follows.

Operating Revenues. Revenues from oil and gas sales increased $397,661 (4%) to $9,407,923 in 2012 from $9,010,262 in 2011. Of the $397,661 increase, crude oil sales increased $1,661,626; natural gas sales decreased $1,281,769; and miscellaneous oil and gas product sales increased $17,804.

The $1,661,626 (31%) increase in oil sales to $7,032,227 in 2012 from $5,370,601 in 2011 was the result of an increase in the volume sold offset by a decline in the average price per barrel (Bbl). The volume of oil sold increased 19,010 Bbls to 79,388 Bbls in 2012, resulting in a positive volume variance of $1,690,939. The average price per Bbl decreased $0.37 to $88.58 per Bbl in 2012, resulting in a negative price variance of $29,313. The increase in oil volumes sold was mostly due to production of 24,700 Bbls from new wells in Oklahoma, Texas and Kansas, offset partially by production declines from older wells.

The $1,281,769 (38%) decline in gas sales to $2,128,436 in 2012 from $3,410,205 in 2011 was the result of a decrease in the average price per thousand cubic feet (MCF) and the volume sold. The volume of gas sold declined 22,323 MCF to 783,564 MCF from 805,887 MCF in 2011, for a negative volume variance of $94,426. This net decrease was due to 125,500 MCF of production from several new working and royalty interest wells, offset by a decline in sales from older properties. Robertson County, Texas royalty interest properties and Arkansas working and royalty interest wells accounted for 104,400 MCF (70%) of the decrease in sales volumes. The average price per MCF decreased $1.51 to $2.72 per MCF from $4.23 per MCF in 2011, resulting in a negative price variance of $1,187,343.

Sales from the Robertson County, Texas royalty interest properties provided approximately 35% of the Company’s first nine months 2012 gas sales volumes and about 44% of the gas sales volumes for the same period in 2011. See discussion on page 12 of the 2011 Form 10-K, under the subheading “Operating Revenues,” for more information about these properties.

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.

Sales of miscellaneous oil and gas products were $247,260 in 2012 compared to $229,456 in 2011.

The Company received lease bonuses of $179,245 in the first nine months of 2012 for leases on its owned minerals. Lease bonuses for the first nine months of 2011 were $184,368.

Coal royalties were $220,130 for the first nine months of 2012 compared to $159,996 for 2011 for coal mined during these periods on North Dakota leases. See subheading “Operating Revenues” on page 12 of the 2011 Form 10-K for more information about this property.

Operating Costs and Expenses. Operating costs and expenses increased $1,018,130 to $5,450,198 in 2012 from $4,432,068 in 2011. Material line item changes are discussed and analyzed in the following paragraphs.

Production Costs. Production costs increased $250,006 (17%) in 2012 to $1,736,733 from $1,486,727 in 2011. Lease operating expense and transportation and compression expense increased $205,411 in 2012 to $1,300,321 from $1,094,910 in 2011. Production taxes increased $44,595 to $436,412 in 2012 from $391,817 in 2011. This increase was due primarily to higher oil sales revenue.

Exploration Costs. Total exploration expense increased $130,073 (236%) to $185,095 in 2012 from $55,022 in 2011. The increase is due primarily to increased dry hole costs. Dry hole costs increased $135,552 in 2012 to $185,095 from $49,543 in 2011. Geological and geophysical expense decreased $5,479 to partially offset the dry hole cost increase.

The following is a summary as of November 1, 2012, updating both exploration and development activity from December 31, 2011, for the period ended September 30, 2012.

The Company participated with its 18% working interest in the completion of three development wells as commercial oil and gas producers on a Barber County, Kansas prospect (these wells were drilled in 2011). The Company participated in five additional development wells on the prospect and in the drilling of a salt water disposal well. One of these wells was completed as a commercial oil and gas producer and another as a marginal gas producer. Completions are in progress on the other three wells. Two additional development wells will be drilled starting in November 2012. Capitalized costs for the period were $615,987, including $181,447 in prepaid drilling costs.

The Company participated in the drilling of five step-out wells on a Woods County, Oklahoma prospect (12%, 8%, 16%, 16% and 16% working interests). Four of these wells were completed as commercial oil and gas producers and a completion is in progress on the fifth. The Company will participate with working interests of 16%, 14% and 14% in the drilling of three additional step-out wells starting in November 2012. Capitalized costs for the period were $420,999, including $198,100 in prepaid drilling costs.

The Company participated with a 4.6% working interest in the drilling of a step-out well on a Woods County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Total capitalized costs for the period were $38,439.

The Company participated with a 17.3% working interest in the drilling of a development well on a Woods County, Oklahoma prospect. The well was completed as a marginal oil and gas producer. The Company will participate with working interests of 18%, 13.7% and 13.7% in the drilling of three additional development wells starting in November 2012. Capitalized costs for the period were $120,102.

The Company participated with its 16% working interest in the completion of a step-out well and an exploratory well as commercial oil producers on a Hodgeman County, Kansas prospect (these wells were drilled in 2011). The Company also participated in the drilling of eight additional exploratory wells on the prospect. Three of these wells were completed as commercial oil producers and the other five as dry holes. Capitalized costs for the period were $269,989, including $173,620 in prepaid drilling costs. Dry hole costs were $104,686 for the period.

The Company participated with a 9.4% working interest in the completion of an exploratory well on a Grady County, Oklahoma prospect (the well was drilled in 2011). The well is currently shut in awaiting pipeline connection. Capitalized costs for the period were $120,393.

The Company participated with its 4.1% working interest in the drilling of an additional horizontal well in a Harding County, South Dakota waterflood unit. It was completed as an oil well but will eventually be converted to a water injection well. Capitalized costs for the period were $117,227.

The Company participated with its 18% working interest in the drilling of an exploratory well on a Ness County, Kansas prospect. Completion attempts have been unsuccessful and $65,525 was charged to dry hole costs.

The Company participated with its 18% working interest in the drilling of an exploratory well on a Ness and Hodgeman Counties, Kansas prospect. The well was completed as a commercial oil producer. The Company also participated in the drilling of a salt water disposal well and will participate in an additional exploratory well in November 2012. Capitalized costs for the period were $118,251, including $28,604 in prepaid drilling costs.

The Company participated with 10.5% and 6.6% working interests in the drilling of two step-out horizontal wells on a Garfield County, Oklahoma prospect. Both wells were completed as commercial oil and gas producers. The Company also participated in the drilling of a salt water disposal well and will participate in an additional step-out horizontal well (10.5% interest) starting in November or December 2012. Capitalized costs for the period were $1,045,014, including $860,247 in prepaid drilling costs.

The Company participated with its 7% interest in the re-entry and conversion to salt water disposal of a plugged well on a Custer County, Oklahoma prospect. Capitalized costs for the period were $74,510.

The Company participated with a 9.3% working interest in the completion of an exploratory horizontal well as a marginal oil producer on a Grayson County, Texas prospect (the well was drilled in 2011). The Company will participate with its 7% working interest in the drilling of two additional exploratory horizontal wells in the first quarter of 2013. Capitalized costs for the period were $92,085.

The Company participated with its 18% working interest in the drilling of an exploratory well on a McClain County, Oklahoma prospect. The well was completed as a commercial oil producer. Capitalized costs for the period were $209,035.

The Company participated with its 18% working interest in the completion of a horizontal development well as a marginal oil producer on a Comanche County, Kansas prospect (the well was drilled in 2011). The Company also participated in the fracking of a marginal well on the prospect, which remained marginal, and in the drilling of a salt water disposal well. The Company is participating in a vertical development well that has been drilled and is awaiting completion. Capitalized costs for the period were $244,123, including $43,200 in prepaid drilling costs, and an impairment of $200,000 was taken on the horizontal well.

The Company participated with a fee mineral interest in the drilling of an exploratory horizontal well in Beaver County, Oklahoma. The Company has a 10.2% interest in the well, which was completed as a commercial oil producer. Capitalized costs for the period were $246,514.

The Company is participating with a fee mineral interest in the drilling of an exploratory horizontal well in Beaver County, Oklahoma. The Company has a 12.6% interest in the well.

The Company participated with 6.2%, 5.7% and 5.2% working interests in the drilling of three exploratory horizontal wells on a Dewey County, Oklahoma prospect. Two of these wells were completed as commercial oil and gas producers and the other is awaiting completion. Capitalized costs for the period were $733,282.

The Company is participating with a fee mineral interest in six horizontal development wells in Van Buren County, Arkansas (6.6%, 7.1%, 7.2%, 3.1%, 9.3% and 9.3% interests). Four of these wells have been completed as commercial gas producers and completions are in progress on the other two. Capitalized costs for the period were $886,125, including $266,292 in prepaid drilling costs.

Depreciation, Depletion, Amortization and Valuation Provision (DD&A). DD&A increased $528,611 (29%) in 2012 to $2,330,648 from $1,802,037 in 2011. The change was mostly the net result of an increase of about $505,000 in depreciation expense on oil and gas properties; an increase of $200,000 for impairment of long-lived assets; and a decrease of about $198,000 in the provision for impairment of leaseholds.

General, Administrative and Other (G&A). G&A increased $109,440 (10%) to $1,197,722 in 2012 from $1,088,282 in 2011. The increase is the net result of increases in salaries expense of $45,360; directors’ fees of $14,000; medical insurance expense of $32,155; legal and professional and fees of about $30,000 and dues and subscriptions of about $17,000; offset by a decline in ad valorem tax expense of about $25,000.

Other Income, Net. This line item decreased $494,132 (49%) to $514,128 in 2012 from $1,008,260 in 2011. See Note 2 to the accompanying financial statements for an analysis of the components of this item. Explanations for variances of the more significant components follow.

Trading securities losses in 2012 were $3,277 as compared to losses of $85,526 in 2011, a decrease of $82,249. In 2012, the Company had unrealized losses of $8,681 from adjusting securities, held at September 30, to estimated fair market value and net realized trading gains of $5,404. In 2011, the Company had unrealized losses of $93,166 and net realized trading gains of $7,640.

Gain on asset sales decreased $629,415 to $447,255 in 2012 from $1,076,670 in 2011. The decrease was due to fewer sales of the Company’s interest in non-producing leaseholds.

Provision for Income Taxes. The provision for income taxes decreased $365,489 (22%) to $1,262,511 in 2012 from $1,628,000 in 2011. This decrease was due primarily to the $1,059,590 (18%) decline in pretax income to $4,871,228 in 2012 from $5,930,818 in 2011. Of the 2012 income tax provision, the estimated current tax expense was $627,604 and the estimated deferred tax expense was $634,907. Of the 2011 income tax provision, the estimated current and deferred expenses were $999,900 and $628,100, respectively. See Note 4 to the accompanying financial statements for a discussion of the provision for income taxes.

Material Changes in Results of Operations Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011.

Net income decreased $521,098 to $1,151,731 in 2012 from $1,672,829 in 2011. The significant changes in the statements of income are discussed below.

Operating Revenues. Revenues from oil and gas sales decreased $101,623 (3%) to $3,061,322 in 2012 from $3,162,945 in 2011. The decrease was the net result of a decrease in gas sales of $353,209 (32%) to $736,105; an increase in oil sales of $289,162 (15%) to $2,243,204; and a decrease in miscellaneous oil and gas product sales of $37,576 to $81,782.

The decrease in gas sales was the net result of a decrease in the average price of $1.66 per MCF to $2.67, for a negative price variance of $456,090, offset by an increase in the volume of gas sold of 23,760 MCF to 275,403 MCF, for a positive volume variance of $102,881. See “Operating Revenues” in the “Results of Operations” section above for additional discussion of gas sales variances.

The increase in oil sales was the result of an increase in the average price received of $0.54 per Bbl to $84.49, for a positive price variance of $14,226, and an increase in the volume of oil produced by 3,275 Bbls to 26,550 Bbls, for a positive volume variance of $274,936. See the “Results of Operations” section above for the nine months for additional discussion of the oil sales increase.

Other operating revenues increased $81,736 to $167,063, primarily due to an increase in lease bonuses of $132,474 to $159,037 for 2012. This increase was partially offset by a decrease in coal royalties of $50,738 to $8,026 for 2012.

Operating Costs and Expenses. Operating costs and expenses increased $158,439 (10%) to $1,765,851 in 2012 from $1,607,412 in 2011. The increase was the net result of an increase in production costs of $78,669; an increase in exploration costs charged to expense of $69,835; a decrease in depreciation, depletion, amortization and valuation provisions (DD&A) of $39,411; and an increase in general administrative and other expense (G&A) of $49,346. The significant changes in these line items are discussed below.

Production Costs. Production costs increased $78,669 to $595,196 in 2012 from $516,527 in 2011. Most of the increase is due to higher lease operating expenses for 2012 versus 2011, related primarily to the new wells that first produced after September 30, 2011. For more information about these changes, see the production costs discussion in the “Results of Operations” section above for the nine months.

Exploration Costs. Exploration costs charged to operations increased $69,835 to $86,141 in 2012 from $16,306 in 2011 as a result of more dry hole costs. See the exploration costs discussion in the “Results of Operations” section above for the nine months.

Depreciation, Depletion & Amortization (DD&A). DD&A decreased $39,411 to $717,724 from $757,135 in 2011. See DD&A discussion in the “Results of Operations” section above for the nine months for an explanation of the increase.

Other Income, Net. See Note 2 to the accompanying financial statements for an analysis of the components of other income, net. In 2012, this line item decreased $688,247 to income of $19,933 from $708,180 in 2011. Explanations for variances of the more significant components follow.

Trading securities losses in 2012 were $12,102 compared to losses of $87,549 in 2011. The losses were primarily unrealized.

Gain on asset sales decreased $794,755 to $12,683 in 2012 from $807,438 in 2011. The decrease was due entirely to fewer sales of the Company’s interest in non-producing leaseholds.

Provision for Income Taxes. The provision for income taxes decreased $345,475 to $330,736 in 2012 from $676,211 in 2011 due to the $866,573 decline in pretax income in 2012 from 2011. See discussions above in the “Results of Operations” section and Note 4 to the accompanying financial statements for additional explanation of the changes in the provision for income taxes.

There were no additional material changes between the quarters, which were not covered in the discussion in the “Results of Operations” section above for the nine months ended September 30, 2012.

Off-Balance Sheet Arrangements

The Company’s off-balance sheet arrangement relates to Broadway Sixty-Eight, Ltd., an Oklahoma limited partnership. The Company does not have actual or effective control of this entity. Management of this entity could at any time make decisions in its own best interest, which could materially affect the Company’s net income or the value of the Company’s investment. For more information about this entity, see Note 3 to the accompanying financial statements.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 4.

CONTROLS AND PROCEDURES

As defined in Rule 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. Based on this evaluation, they concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2012.

Internal Control over Financial Reporting

As defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act, the term “internal control over financial reporting” means a process designed by, or under the supervision of, the issuer’s principal executive and principal financial officers, or persons performing similar functions, and effected by the issuer’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles and includes those policies and procedures that:

	(1)	Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;

	(2)	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 issuer are being made only in accordance with authorizations of management and directors of the issuer; and

	(3)	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer’s assets that could have a material adverse effect on the financial statements.

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. There were no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

During the third quarter ended September 30, 2012, the Company did not have any material legal proceedings brought against it or its properties.

ITEM 1A.

RISK FACTORS

Not applicable.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs1		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs1
July 1 to July 31, 2012		5	$	180.00		—		—
August 1 to August 31, 2012		0	$	180.00		—		—
September 1 to September 30, 2012		3	$	180.00		—		—
Total		8	$	180.00		—		—

1The Company has no formal equity security purchase program or plan. The Company acts as its own transfer agent, and most purchases result from requests made by stockholders receiving small odd lot share quantities as the result of probate transfers.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.

OTHER INFORMATION

None.

ITEM 6.

EXHIBITS

The following documents are exhibits to this Form 10-Q. Each document marked by an asterisk is filed electronically herewith.

Exhibit Number		Description
31.1*		Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.

31.2*		Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.

32*		Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350.

101.INS*#		XBRL Instance Document

101.SCH*#		XBRL Taxonomy Extension Schema Document

101.CAL*#		XBRL Taxonomy Calculation Linkbase Document

101.LAB*#		XBRL Taxonomy Label Linkbase Document

101.PRE*#		XBRL Taxonomy Presentation Linkbase Document
		_________________________________________
		* Filed electronically herewith.

		# Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.

	THE RESERVE PETROLEUM COMPANY
	(Registrant)

Date: November 13, 2012	/s/ Cameron R. McLain
	Cameron R. McLain,
	Principal Executive Officer

Date: November 13, 2012	/s/ James L. Tyler
	James L. Tyler
	Principal Financial Officer