Attached files

file filename
EX-99 - EX-99 - OAKRIDGE ENERGY INCa10-11200_1ex99.htm
EX-23 - EX-23 - OAKRIDGE ENERGY INCa10-11200_1ex23.htm
EX-32 - EX-32 - OAKRIDGE ENERGY INCa10-11200_1ex32.htm
EX-31.(I) - EX-31.(I) - OAKRIDGE ENERGY INCa10-11200_1ex31di.htm
EX-31.(II) - EX-31.(II) - OAKRIDGE ENERGY INCa10-11200_1ex31dii.htm

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.  20549

 


 

Form 10-K

 


 

(Mark One)

 

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

 

For the fiscal year ended February 28, 2010

 

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

 

For the transition period from                to                .

 

Commission file number 000-08532

 


 

OAKRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

 


 

Utah

 

87-0287176

(State or other jurisdiction of incorporation or

 

(I.R.S. Employer

organization)

 

Identification No.)

 

4613 Jacksboro Highway

 

 

Wichita Falls, Texas

 

76302

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code: (940) 322-4772

 


 

Securities registered pursuant to Section 12(b) of the Act: None

 

Securities registered pursuant to Section 12(g) of the Act:

 

Common Stock, $.04 par value

(Title of class)

 


 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o  No x

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o  No x

 

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o  No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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.

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company x

(Do not check if a 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

 

The aggregate market value of common stock, par value $0.04 per share, held by nonaffiliates of the registrant, based on the average bid and asked prices of the common stock on August 31, 2009 (the last business day of the registrant’s most recently completed second fiscal quarter) was approximately $3.8 million.  For purposes of this computation, all officers, directors and 10% beneficial owners of the registrant are deemed to be affiliates.  Such determination should not be deemed an admission that such officers, directors or 10% beneficial owners are, in fact, affiliates of the registrant.

 

As of May 25, 2010, there were 4,068,927 shares of common stock outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

None

 



Table of Contents

 

TABLE OF CONTENTS

 

 

 

Page

 

 

 

PART I

 

3

 

 

 

ITEM 1.       BUSINESS

 

3

 

 

 

Oil and Gas Operations

 

3

 

 

 

Gravel Operations

 

4

 

 

 

Carbon Junction Coal Mine

 

4

 

 

 

Real Estate Held for Sale

 

6

 

 

 

Competition and Markets

 

8

 

 

 

Regulation

 

8

 

 

 

Environmental and Health Controls

 

9

 

 

 

Operating Hazards and Uninsured Risks

 

9

 

 

 

Employees

 

9

 

 

 

ITEM 1B.    UNRESOLVED STAFF COMMENTS

 

9

 

 

 

ITEM 2.       PROPERTIES

 

10

 

 

 

Oil and Gas Properties

 

10

 

 

 

Coal and Gravel Properties

 

12

 

 

 

Real Estate

 

13

 

 

 

Office Building

 

13

 

 

 

ITEM 3.       LEGAL PROCEEDINGS

 

13

 

 

 

ITEM 4.       RESERVED

 

13

 

 

 

PART II

 

14

 

 

 

ITEM 5.       MARKET FOR REGISTRANT’S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

14

 

 

 

ITEM 7.       MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

14

 

 

 

Results of Operations

 

14

 

 

 

Financial Condition and Liquidity

 

16

 

 

 

Critical Accounting Policies and Estimates

 

17

 

 

 

Forward-Looking Statements

 

18

 

 

 

ITEM 8.       FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

19

 

 

 

ITEM 9.       CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

36

 

i



Table of Contents

 

ITEM 9A(T). CONTROLS AND PROCEDURES

 

36

 

 

 

Disclosure Controls and Procedures

 

36

 

 

 

Changes in Internal Control Over Financial Reporting

 

36

 

 

 

Management’s Annual Report on Internal Control Over Financial Reporting

 

36

 

 

 

ITEM 9B.    OTHER INFORMATION

 

37

 

 

 

PART III

 

38

 

 

 

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

38

 

 

 

Directors and Executive Officers

 

38

 

 

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

38

 

 

 

Audit Committee

 

39

 

 

 

Audit Committee Financial Expert

 

39

 

 

 

Nomination Procedures

 

39

 

 

 

Code of Ethics

 

39

 

 

 

ITEM 11.     EXECUTIVE COMPENSATION

 

39

 

 

 

ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

40

 

 

 

ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

 

41

 

 

 

Related Party Transactions

 

41

 

 

 

Director Independence

 

41

 

 

 

ITEM 14.     PRINCIPAL ACCOUNTING FEES AND SERVICES

 

42

 

 

 

Audit Fees

 

42

 

 

 

Audit-Related Fees

 

42

 

 

 

Tax Fees

 

42

 

 

 

All Other Fees

 

42

 

 

 

Pre-Approval Policies and Procedures

 

42

 

 

 

PART IV

 

43

 

 

 

ITEM 15.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

43

 

 

 

SIGNATURES

 

44

 

 

 

EXHIBITS

 

45

 

ii



Table of Contents

 

PART I

 

ITEM 1.                                          BUSINESS

 

Oakridge Energy, Inc. (the “Company”) is engaged in the exploration for and development, production and sale of oil and gas primarily in Texas.  The Company also holds approximately 1,866 acres of land in La Plata County, Colorado for sale, which lands cover gas, coal and other mineral deposits. See “Oil and Gas Operations” and “Real Estate Held for Sale” below and “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

The Company is a Utah corporation incorporated in 1969.  The Company’s executive offices are located at 4613 Jacksboro Highway, Wichita Falls, Texas 76302.  The Company’s telephone number is (940) 322-4772.

 

Overview

 

The Company has restricted its oil and gas exploration activities in recent fiscal years as it has conserved its limited resources for utilization on (i) a secondary recovery water-flood project on its principal oil and gas producing property in Madison County, Texas, (ii) its proposed real estate development project adjacent to Durango, Colorado in La Plata County (the “Durango Property”), and (iii) reclamation of its Carbon Junction Coal Mine in La Plata County, Colorado, which was substantially completed in fiscal 2009.  In fiscal 2010, the Company continued its participation in the water-flood project started in the last quarter of fiscal 2003, as well as its other oil and gas operations.

 

During mid-2004, Sandra Pautsky, the Company’s Chief Executive Officer received treatment for cancer that was diagnosed in late 2003.  In late 2007, Ms. Pautsky underwent a second major procedure for her disease, responded well but continues to receive treatment.  Ms. Pautsky has been the principal force pushing the Company’s proposed real estate development of the Durango Property.  Because of concerns regarding Ms. Pautsky’s health, the project size, the significant financial requirement by the Company, the number of years to complete the project, and the risk to the Company in committing so much of its limited financial resources to one project, the Company decided during the first quarter of fiscal 2005 to attempt to sell the Company’s approximately 1,866 acres of land located in La Plata County, Colorado.

 

The Company has entered into two previous contracts to sell the Durango Property that were unsuccessful.  The nationwide downturn of the real estate market has had a dampening effect on interest from potential buyers of the Durango Property. However, the Company continues to market the Durango Property, and recently the level of interest from potential buyers has improved.  On January 25, 2010, the Company entered into a non-binding letter of intent with La Plata County, Colorado, which proposes that La Plata County build and maintain two connector roads across the Durango Property to be dedicated and constructed in two phases: the Grandview Connector as Phase I and the Highway 160 Dominguez Drive Connection (also commonly known in La Plata County as the “Wal-Mart Intersection”) as Phase II.  See “Real Estate Held for Sale-Decision to Sell the Durango Property” below and “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

Oil and Gas Operations

 

General:  The Company’s oil and gas operations are primarily conducted in Madison County, Texas and other North Texas counties and, to a lesser extent, Freestone, Red River, Panola, Gregg and Smith Counties of Texas, as well as counties in Oklahoma, Colorado and Mississippi. The Company is the operator of only the leases in North Texas, not including its lease in Madison County.  All other oil and gas interests owned are participation interests whereby the Company owns a working or royalty interest in a property that is operated and maintained by another interest owner under an operating agreement.  For the participation interests, the Company receives payment for its oil and gas sales from the purchaser or the operator and is billed by the operator for its ownership percentage of joint expenses for getting the oil and/or gas from the wells to the point of sale.

 

The Company drilled a development well on one of its North Texas properties in fiscal 2010, which was in the process of being completed at the fiscal year end. The well was a low cost shallow well and based on the performance of this well to date, the Company expects to drill two additional wells during fiscal 2011.  Ms. Pautsky and Danny Croker, the Company’s Vice President, select the exploration and development prospects in which the Company participates.

 

Madison County, Texas Property:  The Company’s principal producing oil and gas property for the past eleven fiscal years has been its 25% working interest in the BSR (Sub-Clarksville) Field in Madison County, Texas (the “Madison County, Texas Property”).  The Madison County, Texas Property was responsible for approximately 58.3% and 57.1% of the Company’s total oil and gas revenues for fiscal years 2009 and 2010, respectively.  The property consists of 23 producing

 

3



Table of Contents

 

wells, four water injection wells (which include one converted injection well on November 1, 2008), and one water supply well.

 

The Madison County, Texas Property was discovered in 1994 by Barrow Shaver Resources (“BSR”), the operator of the Madison County, Texas Property.  The BSR (Sub-Clarksville) Field is a stratigraphically trapped oil accumulation of 20MMBOIP (millions of barrels of oil in place) and is fully developed for its primary oil and gas reserves. As the Madison County, Texas Property aged and production declined, a secondary recovery project was installed on the property. In fiscal 2003, the Texas Railroad Commission approved the waterflooding project, the property was unitized and the water-flooding project commenced effective as of December 1, 2002. The waterflooding project is ongoing.

 

Madison County, Texas Property revenues:  The Madison County, Texas Property revenues for fiscal 2010 and 2009 were $582,459 and $958,054, respectively, which represents a decrease of $375,595 (39.2%) for fiscal 2010 as compared to fiscal 2009.  The average oil prices received in fiscal 2010 and 2009 were $63.46 and $91.80 per barrel, respectively, which represents a decrease of $28.34 per barrel (30.9%) for fiscal 2010 as compared to fiscal 2009.  The volume of oil sold in fiscal 2010 decreased in the amount of 1,063 barrels (11.0%) as compared to fiscal 2009.  The decrease in the price of oil and the decrease in the volume of oil sold for fiscal 2010 as compared to fiscal 2009 are the primary reasons for decreased revenue from the Madison County, Texas Property for fiscal 2010. In addition, the average gas prices received in fiscal 2010 and 2009 were $3.56 and $6.59 per mcf, respectively, which represents a decrease of $3.03 per mcf (46.0%) for fiscal 2010 as compared to fiscal 2009.  Gas sales volumes remained virtually unchanged at 10,538 mcf and 10,557 mcf for fiscal 2010 and 2009, respectively. Sales of immaterial amount of other petroleum products were also included in total revenue from the field.

 

Gravel Operations

 

Surface ownership, gravel mining contract and surface lease:  The Company’s gravel property is located on approximately 63.5 acres of the approximately 1,866 acres of land owned by the Company in La Plata County, Colorado.  Pursuant to a contract and surface lease effective January 1, 1994, Four Corners Materials (“FCM”) mined sand, gravel and rock products from the Ewing Mesa Pit #1 for a term of eight years. After the expiration of the contract, FCM continued mining gravel pursuant to an oral agreement between the Company and FCM.  FCM ceased mining on the property in fiscal 2004.

 

Permit and permitted acres: The Ewing Mesa Pit #1 gravel permit area covered approximately 63.5 acres.  Aggregate gravel permits usually do not have an expiration date.

 

Reclamation and financial warranty: During the term of the gravel mining, FCM submitted financial warranties to the Colorado Division of Reclamation, Mining, and Safety (the “CDRMS”) for its mining permit. In fiscal 2006, FCM substantially reclaimed its mining operation, at which time the CDRMS released a portion of FCM’s financial warranty with regard to reclamation, retaining approximately $104,000 in financial warranties awaiting CDRMS confirmation that environmental responses, vegetation and re-growth had stabilized. In fiscal 2009, CDRMS records indicated that FCM requested a release of financial warranties and termination of the gravel permit, which the CDRMS denied. According to the CDRMS, the CDRMS continues to retain the financial warranty because FCM has not reclaimed (i) its sediment pond and overburden pile within the gravel permit area, (ii) a couple of lengths of diversion ditch, (iii) the electrical substation and has not topsoiled and seeded those areas.

 

Current activity and inspection:  Regular inspection of the gravel mine-site and its records are conducted by the CDRMS who reports to FCM regarding compliance requirements under the permit as a result of the inspection.  Inspections and resulting compliance operations will continue until the complete release of the financial warranty.  The CDRMS continues to hold $104,000 for completion of the gravel mine reclamation.

 

The Company would consider leasing the property again for gravel operations but has no intention of conducting gravel mining operations itself on the property.

 

Carbon Junction Coal Mine

 

Surface ownership and coal leases:  In 1990 and 1991, the Company purchased the lands that comprise the Durango Property for the purpose of mining coal.  In addition to acquiring the surface estate of the lands, the Company obtained the exclusive rights to sign coal leases and a 75% interest in the coal deposits.  Of the lands purchased in 1990, the Company obtained coal leases on the remaining 25% interest in the coal deposits.  The leases require no annual delay rentals or advanced minimum royalties have primary terms of 25 years and, unless renewed, will expire in 2015.  No coal leases

 

4



Table of Contents

 

were obtained on the remaining 25% interest in the coal deposits on the approximate 190 acres purchased in 1991.  In fiscal 1994, however, an appraisal by a third party engineer determined that the coal deposits under the Durango Property (the “Carbon Junction Coal Mine”) could not be mined and marketed profitably.  Therefore, in accordance with the rules of the Securities and Exchange Commission (the “SEC”), the Company records no reserves or economic value for coal deposits.

 

Coal mining permit expires September 22, 2013:   Coal deposits held in the Carbon Junction Coal Mine have been minimally permitted and disturbed by mining operations.  Of the 192.77 permitted acres, approximately 59 were disturbed, 55 have been reclaimed and 3.5 remain disturbed at the fiscal 2010 year end.  The Carbon Junction Coal Mine permit was renewed September 22, 2008, for a period of five years and will expire September 22, 2013.  The permit covers reclamation or disposition of existing surface coal mining related disturbance within the permit area.

 

Reclamation liability and financial warranties of $405,834 at fiscal 2010 year end:  The Company’s original bond amount for the reclamation of the Carbon Junction Coal Mine was $816,526 for a permitted area of approximately 192.77 acres containing approximately 59 disturbed acres.  Following partial reclamation of its Carbon Junction Coal Mine, on July 8, 2005 the Company submitted Technical Revision No. 13 to the CDRMS to update the Reclamation Liability Estimate.  On September 7, 2006, the CDRMS approved Technical Revision No.13 reducing the reclamation liability by $121,090, revising the financial warranty liability for reclamation of the Carbon Junction Coal Mine to $695,436 and removing 18.34 acres from the disturbed area of the permit.

 

On August 25, 2006, the Company applied for a Phase I Bond Release of the financial warranty, and approval of the bond release became final on May 23, 2008.  Approval criteria for a Phase I Bond Release states that “up to sixty percent of the applicable bond amount shall be released when the permittee has successfully completed backfilling, regrading, and drainage control in accordance with the approved reclamation plan.”  The amount of financial warranty applicable to the bond release area was $524,848.  Therefore the Phase I Bond Release amount was $314,909 (60% x $524,848), requiring a remaining financial warranty in the amount of $380,527.  A discrepancy in calculation by the CDRMS regarding the Company’s remaining financial warranty resulted in a request on December 12, 2008 by the CDRMS that the Company increase its current financial warranty from $380,527 to $405,834.

 

On November 19, 2007, the Company submitted Technical Revision No. 15 for approval of sediment pond removal.  On January 28, 2008, the sediment pond removal was approved with conditions and in December 2008, reclamation of the sediment control system at the Carbon Junction Coal Mine was completed, with final revegetation of the reclaimed areas completed in April 2009.

 

On July 30, 2008, the Company submitted a Phase III bond release application seeking a monetary release of $237,356 of the then current $380,527 financial warranty.  As of the Company’s fiscal 2010 year end, approximately 3.5 disturbed acres remained to be reclaimed; however, the acreage is contained in topsoil piles that are in excess to the requirements of reclamation of the mine site. The CDRMS has expressed a willingness to revise the current reclamation permit requirements to exclude the topsoil stock piles from being redisturbed or reclaimed and the Company filedTechnical Revision No. 16 Application to the Carbon Junction Coal Mine permit for leaving topsoil piles 4 and 7 in place. The Company has been notified by the CDRMS that the application was considered adequate and they expect to have a decision by July 13, 2010.  However, the CDRMS has expressed concerns that an adequate demonstration of residential, industrial, commercial, and /or recreational post-mining land use in accordance with Technical Revision No. 5 has not been implemented.  The full release of the Company’s financial warranty is subject to the CDRMS’s confirmation that either post-mining land uses have been implemented or environmental responses, ground cover, vegetative habitat and re-growth have stabilized. In May 2009, the CDRMS advised the Company that it did not believe that residential post-mining land use had been “substantially commenced and is likely to be achieved” and that the Company’s Phase III bond release application would be held pending further information from the Company.  The Company is continuing to evaluate its options with regard to obtaining approval from the CDRMS of the Phase III bond release application. Phase II and Phase III Bond Releases are eligible for complete and final bond release after sediment control structures are reclaimed, and Sediment Ponds #1 and #2 were reclaimed between December 2008 and April 2009.  The Company did not submit a Phase II Bond Release application, however, because the Phase III Bond Release has not been approved based on the Company not adequately demonstrating approved post-mining land use.

 

Current mining activities and inspections: The Company substantially completed its reclamation activities in fiscal 2009, and renewed its Carbon Junction Coal Mine permit, which covers reclamation or disposition of existing surface coal mining related disturbance within the modified permit area.  Inspections are conducted regularly by the CDRMS to determine that terms and conditions of the existing permit are being satisfactorily met. As needed in response to the inspections, the Company then performs compliance operations to conform to the CDRMS requirements cited in its report.

 

5



Table of Contents

 

The Company expects that inspections and operations will continue until the complete release of the reclamation liability and warranty. See “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

Real Estate Held for Sale

 

Location:  According to an Alta Survey, the Durango Property consists of approximately 1,866 acres of land located in La Plata County, Colorado.  The major highways intersecting the City of Durango and La Plata County are US Highway 550 running North and South and US Highway 160 running East and West.  The Durango Property is aligned with US Highway 160 and is located on a mesa adjacent to and above the City of Durango.  The Durango Property is not currently within the city limits; however, certain portions of the Durango Property have common boundaries to the city.

 

Background:   The Company originally leased the Durango Property for coal mining purposes beginning in 1979, and in 1989 the lease expired. In October 1990, the Company purchased approximately 1,800 acres on which the Carbon Junction Coal Mine is situated and contains 192.77 acres permitted for coal mining purposes.  In fiscal 1995, following a third party appraisal that resulted in the Company’s coal reserves being classified as uneconomic to produce competitively in the marketplace, the Company’s focus for the Durango Property changed from energy related to real estate opportunities.

 

Letter of Intent by and between La Plata County, Colorado and the Company dated January 25, 2010:    On January 25, 2010, the Company signed a non-binding Letter of Intent with La Plata County, Colorado (the “Letter of Intent”) to dedicate and develop county roads on the Durango Property.  In the Letter of Intent, La Plata County generally agrees that the Company will have direct and convenient access to any county roads dedicated and developed on the Durango Property, that the Company (and its utility providers) will be given the opportunity to locate utilities within any dedicated right of way, and that La Plata County accepts maintenance for the portions of county roads dedicated until maintenance is assumed by another government entity.  The Letter of Intent states that La Plata County will be responsible for the construction and development of the county roads.  The Letter of Intent anticipates two separate dedications of rights of way on the Company’s property, the Grandview Connector and the Highway 160 Connector, to be completed no later than seven and nine years, respectively, from the date of formal agreement.  The Letter of Intent is not a definitive agreement and is subject to the delivery and execution of a final written agreement of the parties as well as certain conditions such as the availability of public funds.  The Company can provide no assurance that a final written agreement will be agreed upon or entered into by the parties or that the roads will be constructed timely or at all.

 

Area plan and plan approval process:  In September 2000, the Company filed an annexation application and conceptual plan with the City of Durango for approximately 1,100 acres of its property.  The Company became aware that, prior to any action by the city regarding annexation, a plan had to be developed and approved by the city for the area in which the Durango Property is located (the “Area Plan”).  The Area Plan evaluates land uses within a specific area to determine whether the uses will be compatible with each other.  Properties adjacent and nearby that may be impacted by the landowner requesting annexation are studied.  Impacts to resources of minerals, coal, oil and gas, as well as wildlife, archeological, geologic and environmental hazards, traffic, public facilities and infrastructure are reviewed.  Public hearings on the Area Plan provide a forum for neighborhood discussion and comment. Public meetings were held in fiscal years 2001, 2002 and 2003. The ideas, issues and concerns of the property owners, the Durango community, and city staff were used to prepare the Area Plan.  The Area Plan provides guidance for decisions in developing lands within the Area Plan consistent with the community’s larger vision for Durango.

 

Public access and density issues were the primary issues that arose during the approval process of the Area Plan. The City Planning Department desired greater density and multiple routes for public access through the Durango Property. However, no paved secondary access road serving the Durango Property is required in accordance with the Area Plan until a traffic study determines the average daily traffic volume to and from the area will exceed 5,000 vehicle trips per day. The Area Plan supports approximately 1,500 to 3,000 residential units.

 

Approval of Area Plan:  The Area Plan, contemplating that approximately 1,202 acres of the Durango Property would be annexed, was adopted by the City of Durango’s Planning Commission in December 2003 and by the City Council in January 2004.

 

Annexation:  The next step in the process is for the City of Durango, when requested by the Company or any new owner (see “Decision to Sell the Durango Property,” below), to approve the Company’s annexation application. An annexation impact report is required to address the physical analysis of the annexation issue.  The current requirement is for the applicant to submit to the City of Durango an annexation application, a master plan for infrastructure, and a plan for its initial phase of development.  The city planners then review, hold public hearings, and prepare a recommendation to the City

 

6



Table of Contents

 

Council to approve, approve with conditions or deny the annexation application and plan for development.   The Company is currently unable to estimate the timetable for the annexation process.

 

Durango Property division into thirty-five acre lots:   The Durango Property is located within La Plata County. In August 2007, La Plata County adopted a new land use code to originally have an effective date of January 6, 2008.  The new code would place serious restrictions within La Plata County on the creation of new parcels, location of building envelopes, view shed protections, hillside and ridge top limits on development, and stricter standards related to roads and water availability. In response to the expected changes to La Plata County land use codes, the Company established fifty-four 35 acre parcels on the Durango Property and filed the plats with the La Plata County Clerk’s office.    Although the Board of County Commissioners delayed the effective date of the new code, it remains likely that it will be put into effect in substantially the same form in the future.

 

The platting of the parcels established building envelopes that are intended to ensure the right to build in the identified areas with fewer restrictions than the new code will require. The platting of the Durango Property into 35 acre parcels allows the ability to build one home on each of the parcels without approval of the Board of County Commissioners. In the event a decision is made by the Company or a new owner that annexation of the lands contained within the Area Plan into the City of Durango and development under the requirements of the City is not advantageous, 35 acre parcels provide development options for the Company or any purchaser of the Durango Property. In addition to but located outside the Area Plan, approximately 600 or more acres of the Durango Property are mountainous. These mountainous acres are expected to remain within La Plata County jurisdiction and are a part of the 35 acre lots filings.

 

Plan concept:  Conceptual plans are subject to change.  The guidelines within the Area Plan reflect the principles found in traditional neighborhood developments as well as mixed-use development concept where residential villages would be within convenient walking or biking distance to nearby neighborhood squares intended as transitional areas of light business uses where shopping, services or office spaces would be provided to the nearby neighborhoods.  Small community parks, houses of worship and day care would be conveniently sited.  Residential densities would shift from high-density in the center of the village to medium or less density as the golf course or rims of the mesa are approached.  The Area Plan approved by the City of Durango incorporates areas of open space and preserves hillsides, gulches and other natural features of the terrain, while allowing residential, commercial and resort development opportunities around the proposed golf course and other recreational properties.  A substantial business park is envisioned to attract corporate home offices and local businesses to the area.

 

Decision to sell the Durango Property:  After obtaining approval of the Area Plan, the Company concluded, during the first quarter of fiscal 2005, that it would be prudent for it to attempt to sell the Durango Property.  The Company’s decision was based on several principal factors, one being the developments with respect to the health of Ms. Pautsky, the Chief Executive Officer and principal shareholder, who is the moving force behind the efforts to advance the Durango Property towards development. In fiscal 2004, Ms. Pautsky was diagnosed with a life-threatening form of cancer. In mid-2004, Ms. Pautsky received specialized treatment for her disease.  In November 2007, Ms. Pautsky received a second specialized treatment for her disease, responded well, but continues to receive treatment. Because of concerns regarding Ms. Pautsky’s health, the project size, the significant financial requirement by the Company, the number of years to complete and the risk involved to the Company in committing so much of its limited financial resources to one project, the Company decided to attempt to sell the Durango Property.  The Company’s officers, other than Ms. Pautsky, have not been actively involved with the Durango Property; however, in the event that the Company should not sell the Durango Property, the Company anticipates that Arbie Ray, Ms. Pautsky’s daughter and long-term employee of the Company, would assume primary responsibility for the Durango Property.  Ms. Ray has been actively involved historically and to date with the Company’s actions in Colorado.

 

On April 4, 2006, the Company signed a contract to sell the Durango Property for $40,000,000, which contained an election by the buyer to terminate its contract in accordance with provisions in the agreement.  On June 12, 2006, the Company was notified of the buyer’s election to terminate its contract.

 

On October 18, 2006, the Company entered into a contract with another buyer for $35,000,000, with no provision to terminate the contract with the exception of proof of title.  On November 29, 2006, the Company announced the failure of the buyer to make good delivery of installment earnest money deposits following the death of the buyer’s principal that resulted in the buyer’s contract default. During fiscal year ended February 2009, the Company learned that the value of the buyer’s estate is not sufficient for payment of the earnest money deposits provided for in the contract.

 

Although discussions with potential buyers of the Durango Property continue, the Company has not entered into any further contracts to sell the Durango Property. The Company is not a distressed seller and continues to have strong

 

7



Table of Contents

 

expectations for the Durango Property.  However, the downturn of the real estate market environment nationwide has affected the marketability of the Durango Property.  See “Competition and Markets” below.

 

Competition and Markets

 

Real estate market conditions:  The economic downturn of the real estate market arguably began as subprime mortgage lenders subsidized by Fannie Mae and Freddie Mac made loans available to low income home buyers with low interest rates and low monthly payments. When these subprime loans began to fail as interest rates began to increase and mortgage payment terms could not be met, this subprime environment collapsed and Fannie Mae and Freddie Mac began to experience financial issues as a result of their subsidies.  As home mortgage loan failures began to multiply, financial institutions began to fail and the lending environment became more stringent. Home owners experienced foreclosure of their homes, the residential sales market became saturated, prices fell as supply increased and sellers had difficulty realizing a price when they sold their home that would cover their remaining loan cost.  Real estate prices have been forced downward as distressed sellers compete for the limited buyers available as a result of stricter lending requirements being implemented by banks and lending institutions.

 

Real estate competitive conditions:  Two other Durango area developments are of significant size and could compete with the Durango Property development project. Three Springs is a 681 acre development that includes approximately 300 acres of open space.  It is being developed as a traditional neighborhood and its master plan provides for a multi-phase build-out that may stretch into the year 2030.  The development includes commercial space and is the home of a regional medical center and medical office complex.  Edgemont Ranch is another development located near Durango.  Edgemont Ranch is situated to the northeast of Durango and is expected to include approximately 1,000 homes on 1,400 acres.  Because of the size and the proximity of these projects to the Durango Property, they may compete with the Durango Property development project.

 

Oil and gas competitive conditions:  A large number of companies and individuals are engaged in the exploration for oil and gas, and most of the companies so engaged possess substantially greater technical and financial resources than the Company.  Competition for desirable leases and suitable prospects, including obtaining services and materials for oil and gas operations, favors larger companies. In fiscal 2009 and 2010, the Company did not experience any difficulty in obtaining services and materials because of its limited exploration and development activities.

 

Coal and gravel competitive conditions: The coal and gravel industries are also highly competitive.  Principal competitive factors in both industries are the vertical thickness of the over-burden above and between seams, product price and transportation costs.  In addition, with regard to coal, its quality is regulated by the Clean Air Act of 1990.  Also, the selling company must have the financial and organizational ability to meet long-term coal delivery requirements.  The Company has been unable to market its coal competitively and in accordance with regulations of the SEC does not account for coal reserves in its financial records.  The Company would consider leasing the Durango Property for gravel operations but has no intention of conducting gravel mining operations itself on the Durango Property.

 

Oil and gas market conditions:  The Company’s ability to produce and market oil and gas profitably depends upon a number of factors which are beyond the control of the Company, the effect of which cannot be accurately predicted or anticipated.  Factors affecting the marketing of oil and gas include, but are not limited to, imports, refining capacities, current worldwide events, unpredictable pricing and actions by foreign producing nations.

 

Oil and gas prices were generally on an upward trend from the first quarter of fiscal 2003 until June 2008.  Higher oil and gas prices had a materially positive effect on the Company’s revenues.  In fiscal 2009 and 2010, the Company’s average oil price received was $91.17 and $63.85, respectively, which represents a decrease of $27.32 per barrel (30.0%) in fiscal 2010 as compared to fiscal 2009.  The Company’s average gas price received was $7.01 and $3.77 in fiscal 2009 and 2010, respectively, which represents a decrease of $3.24 per mcf (46.2%) in fiscal 2010 as compared to fiscal 2009.  The Company generated most of its revenue from oil production.

 

While certain of the Company’s gas properties experience seasonal variations in demand, the Company was not experiencing any significant curtailment, or an inability to sell all of its deliverable gas, on an overall basis at February 28, 2010. See “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

Regulation

 

Oil and gas:  The production of oil and gas is subject to extensive Federal and state laws, rules, orders and regulations governing a wide variety of matters, including the drilling and spacing of wells, allowable rates of production,

 

8



Table of Contents

 

prevention of waste and pollution and protection of the environment.  In addition to the direct costs borne in complying with such regulations, operations and revenues may be impacted to the extent that certain regulations limit oil and gas production allowables to below economic levels.  The regulations are generally designed to ensure that oil and gas operations are carried out in a safe and efficient manner and to ensure that similarly situated operators are provided with reasonable opportunities to produce their respective fair shares of available oil and gas reserves.  Since these regulations generally apply to all oil and gas producers, the Company believes that these regulations do not put the Company at a material disadvantage to other oil and gas producers.

 

Certain sales, transportation and re-sales of natural gas by the Company are subject to both Federal and state laws and regulations, including, but not limited to, the Natural Gas Act (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”) and regulations promulgated by the Federal Energy Regulatory Commission (“FERC”) under the NGA, the NGPA and other statutes.  The provisions of the NGA and the NGPA, as well as the regulations thereunder, are complex and can affect all who produce, resell, transport, purchase or consume natural gas.

 

Although FERC transportation regulations do not directly apply to the Company because it is not engaged in rendering jurisdictional transportation services, these regulations do affect the operations of the Company by virtue of the need to deliver its gas production to markets served by interstate or intrastate pipelines.

 

Coal and gravel:  The Company’s coal operations in the past have been subject to extensive regulation under the Surface Mining Control and Reclamation Act of 1977 and the Colorado law of a similar nature and the Clean Air Act of 1990.  The effects of such regulations have been (i) to make it more costly for the coal to be marketed, (ii) to limit the customers for the coal to certain types of power plants and (iii) that economics are determined by quality parameters for coal. As a result of these limiting factors, the Company has been unable to market its coal competitively and in accordance with SEC regulations does not account for coal reserves in its financial records. The Company’s gravel reserves are subject to comparable regulation, but compliance standards are less rigid.

 

Environmental and Health Controls

 

The Company’s operations are subject to numerous Federal, state and local laws and regulations relating to environmental and health protection.  These laws and regulations require the acquisition of a permit before drilling commences, restrict the type, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas and impose substantial liabilities for pollution resulting from oil and gas operations.  These laws and regulations may also restrict air or other discharges resulting from the operation of pipeline systems and other facilities in which the Company may own an interest.  Although the Company believes that compliance with environmental laws and regulations will not have a material adverse effect on operations or earnings, risks of substantial costs and liabilities are inherent in oil and gas operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as stricter environmental laws and regulations or claims for damages to property or persons resulting from the Company’s operations, could result in substantial costs and liabilities.

 

Operating Hazards and Uninsured Risks

 

The Company’s oil and gas operations are subject to all of the risks normally incident to the oil and gas exploration and production business, including blowouts, cratering, explosions, pollution and other environmental damage, any of which could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities and other property, clean-up responsibilities, regulatory investigations and penalties and suspensions of operations.  As is common in the oil and gas industry, the Company is not fully insured against certain of these risks either because insurance is not available or because the Company has elected not to insure due to high premium costs.  The Company maintains comparable insurance coverage for its coal and gravel operations.

 

Employees

 

As of May 25, 2010, the Company had four full-time employees and one part-time employee.  Three of the employees are located at the Company’s executive offices and two are field employees located in North Texas.  The Company considers its relations with its employees to be satisfactory.

 

ITEM 1B.             UNRESOLVED STAFF COMMENTS

 

None.

 

9



Table of Contents

 

ITEM 2.               PROPERTIES

 

Oil and Gas Properties

 

Reserves:  Reference is made to “Supplemental Oil and Gas Data (Unaudited)” included as supplemental information to the Company’s financial statements for additional information concerning:  (i) certain cost and revenue information pertaining to the Company’s oil and gas producing activities; (ii) estimates of the Company’s oil and gas reserves and changes in such reserves; and (iii) a standardized measure of the discounted future net cash flows from the Company’s oil and gas reserves and the changes in such standardized measure.  The engineering report with respect to the Company’s proved oil and gas reserves as of February 28, 2010 was prepared by Stephens Engineering, independent petroleum engineers, based in Wichita Falls, Texas (“Stephens Engineering”) and is filed as Exhibit 99 to this annual report.  Stephens Engineering is a Consultant Engineering firm specializing in valuations, oil and gas reservoir studies and supervision of secondary tertiary recovery programs.  The firm provides services primarily in Texas, Oklahoma and New Mexico and is experienced in a total of twenty States and Canada.  At February 28, 2010, all of the Company’s oil and gas reserves were located in the States of Texas, Mississippi, Colorado and Oklahoma.  The technical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

 

Management maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations provided by the SEC.  As stated above, the Company retained Stephens Engineering to prepare estimates of the Company’s oil and gas reserves.  Management works closely with this firm, and is responsible for providing accurate operating and technical data to it.  Management reviews the final reserves estimate and, if necessary, discusses the process used and findings with representatives from the independent petroleum engineering firm.  Ms. Pautsky is primarily responsible for overseeing the preparation of the reserve estimates and has over 40 years of experience in the oil and gas industry and has extensive geological knowledge.  Numerous uncertainties exist in estimating quantities of proved reserves.  Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available.  Furthermore, estimates of oil and gas reserves are projections based on engineering data.  There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production.  The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgement.

 

No reserve reports pertaining to the Company’s proved net oil or gas reserves were filed with or included in reports to any Federal governmental authority or agency during the fiscal year ended February 28, 2010, and no major discovery is believed to have caused a significant change in the Company’s estimates of proved reserves since that date.

 

The following table reflects Stephens Engineering’s estimate of those quantities of oil and gas as of February 28, 2010 that can be produced from the Company’s proved developed reserves during the fiscal year ending February 28, 2011 using equipment installed and under economic and operating conditions existing at February 28, 2010:

 

Oil (Bbls)

 

14,470

 

Gas (mcf)

 

25,261

 

 

Summary of Oil and Gas Reserves as of Fiscal-Year End Based on Average Fiscal-Year Prices:  The following table reflects Stephens Engineering’s estimate of oil and gas reserves as of February 28, 2010 using prices and costs under existing economic conditions:

 

 

 

Reserves as of February 28, 2010

 

 

 

Oil (Bbls)

 

Gas (MCF)

 

Proved developed

 

110,458

 

220,082

 

Proved undeveloped

 

554,636

 

 

Total proved reserves

 

665,094

 

220,082

 

 

10



Table of Contents

 

Proved Undeveloped Reserves:  The following table reflects Stephens Engineering’s estimate of proved undeveloped reserves as of February 28, 2009 and 2010:

 

Proved undeveloped reserves

 

Oil (Bbls)

 

As of February 28, 2009

 

599,059

 

Change in estimate

 

(44,423

)

As of February 28, 2010

 

554,636

 

 

All of the estimated 554,636 barrels of oil of proved undeveloped reserves as of the end of fiscal 2010 are attributed to the Madison County, Texas Property.  Other than a change in estimate, no material changes to proved undeveloped reserves were made during fiscal 2010.  As a minority working interest owner, the Company is unable to determine the amount or timing of efforts to recover the proved undeveloped reserves or convert them to developed reserves.

 

The Company is not obligated to provide a fixed and determinable quantity of oil and gas in the future under any of its existing contracts or arrangements.  The Company has been able to meet all significant delivery commitments in each of the last three fiscal years.

 

Production:  The following table shows for each of the last three fiscal years the total production attributable to the Company’s oil and gas interests:

 

Fiscal Year Ended
February 28(9),

 

Oil
(Bbls)

 

Gas
(mcf)

 

2010

 

13,049

 

19,805

 

2009

 

16,088

 

19,860

 

2008

 

17,293

 

20,843

 

 

Lifting costs and average sales prices:  The Company’s average production (lifting) costs and average sales prices received during each of the last three fiscal years are shown in the following table:

 

 

 

Fiscal Year
Ended February 28(9),

 

 

 

2010

 

2009

 

2008

 

Average Production (Lifting) Costs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Per equivalent unit (Bbls)

 

$

46.21

 

$

55.64

 

$

44.20

 

 

 

 

 

 

 

 

 

Average Sales Prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

63.85

 

$

91.17

 

$

76.57

 

Gas (per mcf)

 

$

3.77

 

$

7.01

 

$

6.63

 

 

Sales contracts and major customers:  The Company does not own any refining facilities and sells its oil under short-term contracts at freight on board field prices posted by the principal purchasers of oil in the areas where the Company’s producing properties are located.  During the fiscal year ended February 28, 2010, the Company sold approximately 66.4% of its oil to Teppco Crude Oil, L.P. (“Teppco”) and approximately 25.5% to Sunoco, Inc.  During fiscal 2010, the Company sold approximately 60.0% of its gas under short-term contracts to Orion Pipeline, L.L.C. (“Orion”), approximately 18.6% to Targa North Texas LP, and approximately 10.5% to Chevron U.S.A., Inc.

 

Substantially all of the Company’s oil sales to Teppco and its gas sales to Orion were from the Company’s Madison County, Texas Property.

 

In the opinion of management, the termination of any of the Company’s sales contracts would not adversely affect the Company’s ability to sell its oil and gas production at comparable prices.

 

Developed acreage and productive wells:  As of February 28, 2010, the Company owned working and overriding royalty interests in 8,492 gross (2,566 net) acres of developed oil and gas leases and 50 gross (16.45 net) productive oil and gas wells.

 

11



Table of Contents

 

The following table summarizes the Company’s developed acreage and productive wells as of February 28, 2010:

 

 

 

Developed Acreage(1)

 

Productive Wells(1)(3)

 

 

 

Gross(2)

 

Net(2)

 

Gross(2)

 

Net(2)

 

 

 

Oil

 

Gas

 

Oil

 

Gas

 

Oil

 

Gas

 

Oil

 

Gas

 

Texas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Madison County

 

4,515

 

 

1,129

 

 

23

 

 

5.75

 

 

All Other Counties

 

2,608

 

1,047

 

1,193

 

239

 

21

 

3

 

9.64

 

1.00

 

Mississippi

 

40

 

 

.26

 

 

1

 

 

0.01

 

 

Colorado

 

 

242

 

 

4

 

 

1

 

 

0.02

 

Oklahoma

 

40

 

 

1

 

 

1

 

 

0.03

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

7,203

 

1,289

 

2,323

 

243

 

46

 

4

 

15.43

 

1.02

 

 


(1)

 

Reversionary interests which may increase or decrease the interest shown have been disregarded for purposes of this table.

 

 

 

(2)

 

“Gross,” as it applies to acreage or wells, refers to the number of wells or acres in which an interest is owned by the Company. “Net,” as it applies to acreage or wells, refers to the sum of the fractional ownership interests owned by the Company in gross wells or gross acres.

 

 

 

(3)

 

Excludes 22 gross (12.38 net) shut-in wells; excludes eight gross (3.30 net) water injection wells and one gross (.25 net) water supply well.

 

Undeveloped acreage:  The following table shows the gross and net acres of undeveloped oil and gas leases held by the Company at February 28, 2010:

 

State

 

Gross Acres (1)

 

Net Acres(1)

 

Greg County, Texas Teal Prospect

 

78.65

 

26.19

 

 


(1)

 

“Gross,” as it applies to acreage, refers to the number of acres in which an interest is owned by the Company.  “Net,” as it applies to acreage, refers to the sum of the fractional ownership interests owned by the Company in gross acres.

 

In the absence of drilling activity which establishes commercial reserves sufficient to justify retention or renewal of leases, 100% of the Company’s leases will expire in fiscal 2011.  As a minority working interest owner, the Company cannot determine when or if the conversion to developed acres will occur.

 

Present activities:  The Company drilled one gross (.58 net) development well in fiscal 2010 on one of its North Texas properties.  As of February 28, 2010, the Company was in the process of completing the well. Completion was hampered by adverse weather conditions, which also delayed the drilling of a second well on the same property. The Company did not participate in drilling any development wells during fiscal 2009 or 2008.

 

Drilling activities:  The following table shows the number of net productive and dry exploratory wells and the number of net productive and dry development wells drilled by the Company in each of the last three fiscal years:

 

 

 

Fiscal Year
Ended February 28(9),

 

 

 

2010

 

2009

 

2008

 

Net productive and dry exploratory wells

 

 

 

 

Net productive and dry development wells

 

.58

 

 

 

 

Coal and Gravel Properties

 

Coal leases:  Leases covering coal deposits beneath the Durango Property in the Carbon Junction Coal Mine were acquired in October 1990 and have primary terms of 25 years, and unless renewed, expire in the year 2015. The Company’s leases cover a 25% interest in the coal.  The Company owns a 75% interest in the coal and the surface estate of approximately 1,640 acres.  The Company has the executive rights (i.e., the exclusive right to sign coal leases) on the leased 25% interest. No annual delay rentals or advance minimum royalties are required.  In 1991, the Company purchased the surface estate, the

 

12



Table of Contents

 

75% interest in the coal and the executive rights to the remaining 25% interest in the coal of approximately 190 additional acres in La Plata County adjacent to the approximately 1,640 acres previously purchased.  The Company has not leased the remaining 25% interest in the coal.  By virtue of its fee and lease ownership and the executive rights it holds, the Company controls 100% of the above described tracts.

 

Coal mining permit approved by the CDRMS expires September 22, 2013:  Coal deposits held in the Carbon Junction Coal Mine have been minimally permitted and disturbed by mining operations.  Of the approximately 1,830 acres owned and leased, approximately 192.77 acres were permitted by the CDRMS and only 3.5 acres remain disturbed.  The term of the Company’s permit is five years and the current permit expires September 22, 2013.  The Carbon Junction Coal Mine permit covers reclamation or disposition of existing surface coal mining related disturbance within the permit area. See “Item 1 - Business - Carbon Junction Coal Mine.”

 

The Company also owns 55% of the gravel, oil, gas and other mineral rights with respect to the approximate 1,640 acre tract in La Plata County, Colorado and has the executive rights on the remaining 45%.  The permit to mine gravel held by FCM, previous operator of the gravel mine, contains 63.5 acres.  In fiscal 2006, FCM substantially reclaimed its gravel mining operation. The CDRMS released a portion of FCM’s financial warranty with regard to reclamation retaining approximately $104,000 in financial warranties.  In fiscal 2009, CDRMS records indicate that FCM requested a release of financial warranty and termination of the permit, which the CDRMS denied.  According to the CDRMS, the CDRMS continues to retain the financial warranty because FCM has not reclaimed (i) its sediment pond and overburden pile within the gravel permit area, (ii) a couple of lengths of diversion ditch, (iii) the electrical substation and has not topsoiled and seeded those areas. Aggregate permits generally do not have a termination date.  See “Item 1. Business - Gravel Operations” and “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

Real Estate

 

The Durango Property held for sale by the Company contains 1,866 acres covering coal, gas and other minerals including gravel as described above in “Coal and Gravel Properties.”  Approximately 1,202 acres of the Durango Property is the subject of a planned mixed use development by the Company.  In the opinion of management, the Durango Property is adequately covered by insurance.  See “Item 1.Business - Real Estate Held for Sale.”

 

Office Building

 

The Company owns a one-story office building situated at 4613 Jacksboro Highway in Wichita Falls, Texas in which its executive offices are located.  The building is located on .519 acres of land and contains 5,117 square feet of space. The building was built in 1974 and is in good overall condition.  In the opinion of management, the office building is adequately covered by insurance.

 

ITEM 3.               LEGAL PROCEEDINGS

 

The Company is not a party to any pending litigation.  To the best knowledge of the Company, there are no legal proceedings to which any director, officer or affiliate of the Company, any owner of record or beneficially of more than five percent (5%) of any class of voting securities of the Company, or any associate of any such director, officer or security holder is a party adverse to the Company or has a material interest adverse to the Company.

 

ITEM 4.               RESERVED

 

13



Table of Contents

 

PART II

 

ITEM 5.               MARKET FOR REGISTRANT’S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

The Company’s common stock, $0.04 par value, is traded in the over-the-counter market.  The following table shows the range of bid quotations for the common stock during the two fiscal years ended February 28, 2009 and February 28, 2010 by quarters.  Such quotations were furnished to the Company by the National Quotation Bureau, LLC and were supplied by The National Association of Securities Dealers (“NASD”) through the NASD OTC Bulletin Board, the NASD’s automated system for reporting NON-NASDAQ quotes and the National Quotation Bureau’s Pink Sheets.  The quotations represent prices between dealers and do not include retail markups, markdowns or commissions and do not necessarily represent actual transactions.

 

Period

 

High

 

Low

 

 

 

 

 

 

 

Fiscal Year Ended February 28, 2009

 

 

 

 

 

Quarter Ended May 31, 2008

 

$

10.50

 

$

6.00

 

Quarter Ended August 31, 2008

 

10.50

 

7.00

 

Quarter Ended November 30, 2008

 

7.50

 

4.00

 

Quarter Ended February 28, 2009

 

4.50

 

2.25

 

 

 

 

 

 

 

Fiscal Year Ended February 28, 2010:

 

 

 

 

 

Quarter Ended May 31, 2009

 

4.65

 

1.00

 

Quarter Ended August 31, 2009

 

4.90

 

1.05

 

Quarter Ended November 30, 2009

 

4.90

 

1.50

 

Quarter Ended February 28, 2010

 

4.65

 

1.65

 

 

As of May 27, 2010, the Company had approximately 402  holders of record of its common stock.

 

The Company did not pay any dividends during fiscal 2009 or 2010.  There are currently no restrictions upon the Company’s ability to pay dividends.

 

The following table shows all purchases of the Company’s shares of common stock made by the Company during the fourth quarter of fiscal 2010:

 

Purchases of Equity Securities

 

Period

 

Total Number of
Shares Purchased
(1)

 

Average Price
Paid Per Share

 

December 1, 2009 through February 28, 2010

 

7,000

 

2.50

 

 


(1)         The Company repurchased 7,000 shares of its common stock in a private transaction based upon the stock price on the closing day of the transaction.

 

The Company has no publicly announced plans or programs to purchase its shares of common stock.

 

ITEM 7.               MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The following discussion and analysis should be read in conjunction with the Financial Statements and Notes thereto included in Item 8.

 

Results of Operations

 

The Company had a net loss of $232,347 ($0.06 per share) in the fiscal year ended February 28, 2010 as compared to a net loss of $652,703 ($0.15 per share) in the fiscal year ended February 28, 2009.

 

Oil and gas revenues decreased $623,812 (37.9%) in fiscal 2010 as compared to fiscal 2009.  The primary reasons for this decline in revenue were decreased average oil and gas prices received and decreased sales volumes for the 2010 fiscal

 

14



Table of Contents

 

year as compared to the 2009 fiscal year.  Fees in the amount of $36,600 received by the Company both in fiscal 2010 and 2009 for serving as operator of most of the Company’s North Texas area properties are included in oil and gas revenues.

 

The following table compares the Company’s oil and gas revenues and average prices received by the Company and its sales volumes of oil and gas during fiscal 2010 with those of fiscal 2009:

 

 

 

Fiscal 2010

 

Fiscal 2009

 

Percentage
Change

 

Oil:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

899,691

 

$

1,434,279

 

-

37.3

%

Volume (Bbls.)

 

14,092

 

15,732

 

-

10.4

%

Average Price (per Bbl.)

 

$

63.85

 

$

91.17

 

-

30.0

%

 

 

 

 

 

 

 

 

 

Gas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

83,869

 

$

170,619

 

-

50.8

%

Volume (mcf)

 

22,266

 

24,345

 

-

8.5

%

Average Price (per mcf)

 

$

3.77

 

$

7.01

 

-

46.2

%

 

Non-material amounts of natural gas liquids revenues and sales volumes for fiscal 2009 are excluded from the foregoing table.

 

Oil and gas prices received were very volatile in fiscal 2009.  For the first seven months of fiscal 2009, the Company received unprecedented prices in excess of $100.00 per barrel of oil topping out at approximately $133.00 per barrel.  During the last five months of fiscal 2009, the oil prices received by the Company declined dramatically and bottomed-out at approximately $35.00 per barrel of oil sold.  Fiscal 2010 saw a rebuilding from the low price of approximately $35.00 per barrel to a high of approximately $75.00 per barrel of oil sold.  The 30.0% decline in the average oil price received in fiscal 2010 as compared to fiscal 2009 was a primary contributor to the Company’s lower revenue in fiscal 2010 as compared to fiscal 2009. A 1,640 barrel (10.4%) decrease in oil sales volumes also contributed to lower revenue for fiscal 2010 as compared to fiscal 2009.  Average gas prices received decreased by $3.24 per mcf (46.2%) from $7.01 per mcf to $3.77 per mcf during fiscal 2010 as compared to fiscal 2009 and gas sales volumes decreased 2,079 mcf (8.5%) during fiscal 2010 as compared to fiscal 2009 from 24,345 mcf to 22,266 mcf.

 

The Company’s revenues in fiscal 2010 from the Madison County, Texas Property decreased $375,595 (39.2%) as compared to fiscal 2009 as average oil prices received from the property decreased $28.34 per barrel (30.9%) from $91.80 per barrel to $63.46 per barrel and oil sales volumes from the property decreased 1,063 barrels (11.0%) from 9,651 barrels in fiscal 2009 to 8,588 barrels in fiscal 2010.

 

Oil and gas operating expense decreased $1,021,737 (55.1%) in fiscal 2010 as compared to fiscal 2009. A primary reason for the reduced oil and gas operating expense was a $550,418 (98.5%) decrease in impairment costs for oil and gas properties in fiscal 2010 as compared to fiscal 2009.  In fiscal 2009, the Company recorded an impairment and partial write off of the Madison County, Texas Property.  The price of oil per barrel and gas per mcf plummeted in February 2009 to $32.82 and $3.26, respectively, which prices were used to calculate reserve value.  In fiscal 2009, SEC S-X Rule 4-10 provided that reserves that are a part of a natural resource occurrence which can be economically and legally extracted at a profit based on the price received at the time of the reserve determination are recordable to the Company.  However, in fiscal 2010, the ruling changed to where the price used to estimate reserves is a twelve month average price rather than a single day spot price.  No impairment of the Madison County, Texas Property was recorded in fiscal 2010 as a result of increases in the prices received by the Company for its oil and gas production.

 

The Company had a decrease of $65,617 (99.43%) in write offs of abandoned leasehold interests in fiscal 2010 as compared to fiscal 2009.  The Company also recognized a gain in fiscal 2010 related to the completion of a plugging program on certain previously abandoned North Texas oil and gas properties in the amount of $38,707.  No such gain was recognized in fiscal 2009.  The Company also had a decrease in the change in estimate related to the asset retirement obligation in the amount of $42,553 for fiscal 2010 as compared to fiscal 2009.

 

15



Table of Contents

 

The table below shows by property certain of the changes in expenses incurred in the Company’s oil and gas operations in fiscal 2010 as compared to fiscal 2009.

 

Changes in:

 

Madison
County,
Texas

 

North
Texas

 

Smith
County,
Texas

 

Red River
County,
Texas

 

Operating expenses

 

$

(296,633

)

$

(23,310

)

$

(10,536

)

$

14,744

 

Asset retirement obligation and accretion

 

8,137

 

(10,921

)

(3,703

)

(591

)

Depletion and depreciation expense

 

2,472

 

7,072

 

(708

)

(416

)

Total change in oil and gas operating expenses

 

$

(286,024

)

$

(27,159

)

$

(14,947

)

$

13,737

 

 

The expenses of the Company’s coal and gravel operations decreased $113,525 (81.3%) in fiscal 2010 as compared to fiscal 2009 primarily due to reduced reclamation costs and testing and permitting costs.

 

Real estate development expense decreased $42,970 (18.1%) in fiscal 2010 as compared to fiscal 2009 primarily due to decreased ad valorem taxes in the amount of $76,077 partially offset by increased legal and other expenses regarding ad valorem taxes in the amount of $30,328.

 

General and administrative expenses decreased $31,709 (5.8%) primarily due to decreased costs for professional fees and expenses for compliance with Federal laws and regulations in the amount of $27,259 and decreased letter of credit fees in the amount of $10,959, partially offset by increased employee insurance benefits in the amount of $9,330.

 

The Company had gains on sale of property in the amount of $79,082 in fiscal 2010 and $208,611in fiscal 2009, representing a decrease of $129,529 (62.1%) for fiscal 2010 as compared to fiscal 2009.  The 2010 gains were for equipment sold from certain previously abandoned North Texas oil and gas properties which were plugged during the year.  The gains on sale of property for fiscal 2009 were from the sale of a workover rig and the salvage of remaining coal mining equipment.

 

Other income (expense) increased $165,627 (693.7%) in fiscal 2010 as compared to fiscal 2009. Other income (expense) consists of four primary components: (i) interest and dividend income, (ii) gains on sales of marketable securities, (iii) impairment loss on investments and (iv) other income (expense), primarily partnership gains and losses and changes in estimates. Lower interest rates and slightly lower portfolio values resulted in decreased interest income in the amount of approximately $59,889 (76.3%) and decreased dividend income of $7,215 (83.4%).  However, the Company experienced a gain on the sale of marketable securities available for sale of $125,343 in fiscal 2010 with no such gain realized in fiscal 2009.  The write-down of an investment security which was considered permanently impaired in fiscal 2009 resulted in an expense in the amount of $124,143 for that period with no comparable expense in fiscal 2010.  As to the remaining other expense components, the Company’s income relating to its interest in a limited partnership which operates a small gas pipeline in the East Texas area was $16,755 less in fiscal 2010 than in fiscal 2009.

 

The Company’s provision for income taxes was a benefit in both fiscal 2010 and 2009.  The income tax benefit decreased $201,871 (68.0%) in fiscal 2010 as compared to fiscal 2009.  This provision includes U.S. Federal corporate and state income taxes.

 

The Company made no purchases of its common stock in fiscal 2009.  In fiscal 2010, the Company purchased 174,128 shares of its common stock.  There were 4,086,114 shares of common stock outstanding at the February 28, 2010 fiscal year end.

 

Financial Condition and Liquidity

 

During fiscal 2010, the Company generally tried to restrict its expenditures; however, the Company did drill one gross (.58 net) development well on one of its North Texas properties which was in the process of being completed at the fiscal year end.  Related drilling, completion and equipment costs are included in investing activities.  In fiscal 2010, investing activities were net providers of cash in the amount of approximately $2,432,000 due mainly to proceeds received from maturities of certificates of deposit of $2,632,000.  In fiscal 2010, operating activities and financing activities, namely purchases of the Company’s treasury stock, were net users of cash in the approximate amounts of $785,000 and $374,000, respectively resulting in an increase in cash and cash equivalents for fiscal 2010 of approximately $1,274,000.

 

The Company’s decision to attempt to sell the Durango Property should eliminate the need for any substantial drawdown of the Company’s cash reserves or the need to obtain additional debt or equity financing. The Company expects to fund its contemplated oil and gas plugging and abandonment operations during fiscal 2011 and any purchases of the

 

16



Table of Contents

 

Company’s stock that it makes from its cash and cash equivalents,  cash flow from its oil and gas properties, and sale of salvage from the abandoned wells.

 

The Company’s oil products received an average price of $63.85 in fiscal 2010 for all properties.  The Company has no assurance that its average price received for oil and gas in fiscal 2011 will be equivalent to or exceed those received during fiscal 2010.  The Company believes it has sufficient funds available for its use in operations for the next 12 months.

 

Critical Accounting Policies and Estimates

 

The foregoing discussion and analysis of the Company’s results of operations and financial condition and liquidity is based upon the Company’s financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America.  The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses.  The Company’s significant accounting policies are described in Note B of the notes to the Company’s financial statements.  In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure about Critical Accounting Policies,” the Company has identified certain of these policies as being of particular importance to the portrayal of the Company’s results of operations and financial position and which require the application of significant judgment by management.  The Company analyzes its estimates, including those related to oil and gas revenues, oil and gas properties, income taxes, contingencies and litigation, and bases its estimates on historical experience and various other assumptions that the Company believes to be reasonable under the circumstances.  Actual results may differ from these estimates under different assumptions or conditions.  The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of the Company’s financial statements:

 

Successful efforts method of accounting:  The Company accounts for its natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting.  Under this method, costs of productive exploratory wells, development dry holes and productive wells, costs to acquire mineral interests and three-dimensional (3-D) seismic costs are capitalized.  Exploration costs, including personnel costs, certain geological and geophysical expenses including two-dimensional (2-D) seismic costs and delay rentals for oil and gas leases, are charged to expense as incurred.  Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

 

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred.  The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience.  Wells may be completed that are assumed to be productive but actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date.  Wells may be drilled that target geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results.  The evaluation of oil and gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area.  Drilling activities in an area by other companies may also effectively condemn leasehold positions.

 

The successful efforts method of accounting can have a significant impact on the operational results reported when the Company is entering a new exploratory area in hopes of finding an oil and gas field that will be the focus of future development drilling activity.  The initial exploratory wells may be unsuccessful and would be expensed.

 

Reserve estimates:  The Company’s estimates of oil and gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures.  Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure.  The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment.  Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results.  The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic.  For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom may vary substantially.  Any significant

 

17



Table of Contents

 

variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and/or the rate of depletion of the oil and gas properties.  Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates and such variances may be material.

 

Impairment of oil and gas properties:  The Company reviews its oil and gas properties for impairment at least annually and whenever events and circumstances indicate a decline in the recoverability of their carrying value.  The Company estimates the expected future cash flows of its oil and gas properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable.  If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to their fair value.  The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

 

Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require the Company to record an impairment of the recorded book values associated with oil and gas properties.  In fiscal 2009, the Company recorded an impairment and partial write off of the Madison County, Texas Property. The price of oil per barrel and natural gas per mcf plummeted in February 2009 to $32.82 and $3.26, respectively, which prices were used to calculated reserve value.  In fiscal 2009, SEC S-X Rule 4-10 provided that reserves that are a part of a natural resource occurrence which can be economically and legally extracted at a profit based on the price received at the time of the reserve determination are recordable to the Company. However, in fiscal 2010, the price used to estimate reserves changed to a twelve month average price rather than a single day spot price.  No impairment of the Madison County, Texas Property was recorded in fiscal 2010 as a result of increases in the prices received by the Company for its oil and gas production.

 

Asset retirement obligations:  The Company’s recorded asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate the producing properties at the end of their productive lives, in accordance with state laws, as well as the estimated costs associated with the reclamation of the property surrounding and including the Company’s previous coal mining operations. The Company determines the asset retirement obligations by calculating the present value of estimated cash flows related to the liability. The asset retirement obligations are recorded as a liability at the estimated present value as of the asset’s inception, with an offsetting increase to producing properties. Periodic accretion of the discount related to the estimated liability is recorded as an expense in the statement of operations.

 

The estimated liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells, and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations. Revisions to the asset retirement obligations are recorded with an offsetting change to producing properties, resulting in prospective changes to depletion and depreciation expense and accretion of the discount.  Because of the subjectivity of assumptions and the relatively long lives of most of the wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.

 

Forward-Looking Statements

 

Certain information included in this annual report on Form 10-K and other materials filed by the Company with the SEC contain forward-looking statements relating to the Company’s operations and the oil and gas industry.  Such forward-looking statements are based on management’s current projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “believes,” “estimates,” “anticipates” and similar words.  These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict.  Therefore, actual results may differ materially from what is expressed in such forward-looking statements.

 

Among the factors that could cause actual results to differ materially are crude oil and natural gas price fluctuations, failure to achieve expected production and the timing of the receipt of revenues from existing and future exploration and development projects (including, particularly, the secondary recovery project on the Madison County, Texas Property), higher than estimated oil and gas and coal reclamation costs and delays with respect to, or failure to obtain, governmental permits and approvals necessary to proceed with real estate development.  In addition, these forward-looking statements may be affected by general domestic and international economic and political conditions.

 

18




Table of Contents

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Stockholders of

Oakridge Energy, Inc.:

 

We have audited the accompanying balance sheets of Oakridge Energy, Inc. (the “Company”) as of February 28, 2010 and February 28, 2009, and the related statements of operations, changes in 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  An audit includes 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 Company as of February 28, 2010 and February 28, 2009, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

 

/s/ Whitley Penn LLP

 

 

 

 

 

Fort Worth, Texas

 

June 1, 2010

 

 

20



Table of Contents

 

OAKRIDGE ENERGY, INC.

 

BALANCE SHEETS

 

 

 

February 28,

 

February 28,

 

 

 

2010

 

2009

 

 

 

 

 

 

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

 1,480,775

 

$

 207,244

 

Trade accounts receivable

 

129,797

 

131,686

 

Investment securities available for sale

 

128,030

 

72,992

 

Prepaid expenses and other

 

16,715

 

16,851

 

Certificates of deposit

 

204,399

 

2,483,931

 

Total current assets

 

1,959,716

 

2,912,704

 

 

 

 

 

 

 

Oil and gas properties, at cost, using the successful efforts method of accounting:

 

 

 

 

 

Proved developed and undeveloped properties

 

7,189,713

 

7,280,164

 

Less accumulated depletion and depreciation

 

6,886,657

 

7,001,515

 

Proved developed and undeveloped properties, net

 

303,056

 

278,649

 

Unproved properties

 

43,521

 

43,899

 

Net oil and gas properties

 

346,577

 

322,548

 

 

 

 

 

 

 

Coal and gravel properties, at cost:

 

 

 

 

 

Undeveloped properties

 

5,850,424

 

5,850,424

 

Less accumulated depletion and depreciation

 

5,589,936

 

5,589,936

 

Net coal and gravel properties

 

260,488

 

260,488

 

 

 

 

 

 

 

Other property and equipment, net of accumulated depreciation of $291,948 and $280,337, respectively

 

107,132

 

118,743

 

 

 

 

 

 

 

Real estate held for sale

 

3,168,107

 

3,168,107

 

 

 

 

 

 

 

Deferred income taxes

 

754,499

 

670,464

 

 

 

 

 

 

 

Other non-current assets

 

446,367

 

424,723

 

 

 

 

 

 

 

Total assets

 

$

 7,042,886

 

$

 7,877,777

 

 

See accompanying notes to financial statements.

 

21



Table of Contents

 

 

 

February 28,

 

February 28,

 

 

 

2010

 

2009

 

 

 

 

 

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

210,784

 

$

381,297

 

Accrued expenses

 

45,172

 

39,946

 

Current portion of asset retirement obligations

 

81,696

 

88,696

 

Total current liabilities

 

337,652

 

509,939

 

 

 

 

 

 

 

Asset retirement obligations

 

413,149

 

505,904

 

Total liabilities

 

750,801

 

1,015,843

 

 

 

 

 

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Common stock, par value $.04 per share, 20,000,000 shares authorized, 10,157,803 shares issued

 

406,312

 

406,312

 

Additional paid-in capital

 

805,092

 

805,092

 

Retained earnings

 

15,809,759

 

16,042,106

 

Accumulated other comprehensive gain (loss)

 

13,913

 

(22,326

)

Stockholders’ equity before treasury stock

 

17,035,076

 

17,231,184

 

Less treasury stock, at cost; 6,071,689 shares and 5,897,561 shares, respectively

 

10,742,991

 

10,369,250

 

Total stockholders’ equity

 

6,292,085

 

6,861,934

 

 

 

 

 

 

 

Total liabilities and stockholders’ equity

 

$

7,042,886

 

$

7,877,777

 

 

See accompanying notes to financial statements.

 

22



Table of Contents

 

OAKRIDGE ENERGY, INC.

 

STATEMENTS OF OPERATIONS

 

 

 

For Fiscal Year Ended February 28,

 

 

 

2010

 

2009

 

Oil and gas revenues

 

$

1,020,160

 

$

1,643,972

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

Oil and gas:

 

 

 

 

 

Impairment of oil and gas properties

 

8,568

 

558,986

 

Depletion, depreciation and accretion

 

33,613

 

36,690

 

Lease operating

 

791,158

 

1,259,400

 

Total oil and gas

 

833,339

 

1,855,076

 

 

 

 

 

 

 

Coal and gravel

 

26,057

 

139,582

 

Real estate development

 

194,165

 

237,135

 

General and administrative

 

514,994

 

546,703

 

Gain on sale of property

 

(79,082

)

(208,611

)

Total operating expenses

 

1,489,473

 

2,569,885

 

 

 

 

 

 

 

Loss from operations

 

(469,313

)

(925,913

)

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

Interest and dividend income

 

20,071

 

87,175

 

Gain on sale of marketable securities available for sale

 

125,343

 

 

Impairment of marketable securities available for sale

 

 

(124,143

)

Other income (expense)

 

(3,663

)

13,092

 

 

 

141,751

 

(23,876

)

 

 

 

 

 

 

Loss before income taxes

 

(327,562

)

(949,789

)

 

 

 

 

 

 

Income tax benefit

 

(95,215

)

(297,086

)

 

 

 

 

 

 

Net loss

 

$

(232,347

)

$

(652,703

)

 

 

 

 

 

 

Basic and diluted loss per common share:

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

$

(0.06

)

$

(0.15

)

 

 

 

 

 

 

Weighted average shares outstanding

 

4,160,545

 

4,260,242

 

 

See accompanying notes to financial statements.

 

23



Table of Contents

 

OAKRIDGE ENERGY, INC.

 

STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

 

Fiscal Years Ended February 28, 2010 and 2009

 

 

 

Common
Stock

 

Additional
Paid-in
Capital

 

Retained
Earnings

 

Accumulated
Other
Comprehensive
Gain (Loss)

 

Treasury
Stock

 

Total

 

Comprehensive
Loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at March 1, 2008

 

$

406,312

 

$

805,092

 

$

16,694,809

 

$

(54,216

)

$

(10,369,250

)

$

7,482,747

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

 

 

(652,703

)

 

 

(652,703

)

$

(652,703

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Change in unrealized gain on investment securities, net of income taxes

 

 

 

 

31,890

 

 

31,890

 

31,890

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive loss for year

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(620,813

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at February 28, 2009

 

406,312

 

805,092

 

16,042,106

 

(22,326

)

(10,369,250

)

6,861,934

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases of treasury stock

 

 

 

 

 

(373,741

)

(373,741

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

 

 

(232,347

)

 

 

(232,347

)

$

(232,347

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Change in unrealized gain on investment securities, net of income taxes

 

 

 

 

36,239

 

 

36,239

 

36,239

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive loss for year

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(196,108

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at February 28, 2010

 

$

406,312

 

$

805,092

 

$

15,809,759

 

$

13,913

 

$

(10,742,991

)

$

6,292,085

 

 

 

 

See accompanying notes to financial statements.

 

24



Table of Contents

 

OAKRIDGE ENERGY, INC.

 

STATEMENTS OF CASH FLOWS

 

 

 

Fiscal Year Ended February 28,

 

 

 

2010

 

2009

 

Operating Activities

 

 

 

 

 

Net loss

 

$

(232,347

)

$

(652,703

)

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

 

 

 

 

 

Impairment of oil and gas properties

 

8,568

 

558,986

 

Depletion and depreciation

 

30,128

 

28,430

 

Accretion of discount on asset retirement obligations

 

15,096

 

24,891

 

Change in estimate of asset retirement obligation

 

(29,006

)

13,547

 

Gain on sale of marketable securities available for sale

 

(125,343

)

 

Gain on sale of oil and gas properties

 

(79,082

)

 

Gain on sales of coal and gravel property

 

 

(20,000

)

Gain on sales of other property and equipment

 

 

(188,611

)

(Gain) loss on investment in limited partnership

 

3,663

 

(13,092

)

Deferred income taxes

 

(102,704

)

(303,720

)

Impairment of marketable securities available for sale

 

 

124,143

 

Change in reclamation bond liability

 

(25,307

)

435,999

 

Abandoned leaseholds

 

377

 

65,994

 

Changes in operating assets and liabilities:

 

 

 

 

 

Trade accounts receivable

 

1,889

 

146,036

 

Prepaid expenses and other

 

136

 

748

 

Accounts payable and accrued expenses

 

(165,287

)

201,999

 

Asset retirement obligation

 

(85,845

)

(13,547

)

Net cash provided by (used in) operating activities

 

(785,064

)

409,100

 

 

 

 

 

 

 

Investing Activities

 

 

 

 

 

Additions to investment securities available for sale

 

(196,663

)

(69,410

)

Additions to oil and gas properties

 

(53,679

)

(147,205

)

Additions to real estate held for sale

 

 

(33,034

)

Purchases of certificates of deposit

 

(353,007

)

(4,476,262

)

Proceeds from maturities of certificates of deposit

 

2,632,000

 

1,990,000

 

Proceeds from sales of investment securities available for sale

 

322,415

 

 

Proceeds from sales of oil and gas properties

 

81,270

 

 

Proceeds from sales of coal and gravel property and equipment

 

 

20,000

 

Proceeds from sales of other property and equipment

 

 

190,000

 

Proceeds from sales of other non-current assets

 

 

15,000

 

Net cash provided by (used in) investing activities

 

2,432,336

 

(2,510,911

)

 

 

 

 

 

 

Financing Activity

 

 

 

 

 

Purchases of treasury stock

 

(373,741

)

 

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

1,273,531

 

(2,101,811

)

Cash and cash equivalents at beginning of year

 

207,244

 

2,309,055

 

 

 

 

 

 

 

Cash and cash equivalents at end of year

 

$

1,480,775

 

$

207,244

 

 

 

 

 

 

 

Supplemental Disclosure of Cash Flow Information

 

 

 

 

 

Income taxes paid

 

$

7,894

 

$

6,634

 

 

 

 

 

 

 

Supplemental Disclosure of Non-Cash Information

 

 

 

 

 

Change in unrealized gain on investment securities, net of income taxes

 

$

36,239

 

$

31,890

 

 

 

 

 

 

 

Additions to asset retirement obligation

 

$

2,631

 

$

68,935

 

 

See accompanying notes to financial statements.

 

25



Table of Contents

 

OAKRIDGE ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

February 28, 2010 and 2009

 

A.   Nature of Business

 

Oakridge Energy, Inc. (the “Company”) is engaged in the exploration for and development, production, and sale of oil and gas primarily in Texas.  The Company has received lease and royalty income from gravel deposits in Colorado and holds certain real estate in Colorado for sale.  The Company was incorporated in Utah in 1969 and its executive offices are located in Wichita Falls, Texas.

 

B.   Summary of Significant Accounting Policies

 

A summary of the Company’s significant accounting policies consistently applied in the preparation of the accompanying financial statements follows:

 

(a)   Basis of Accounting

 

The accounts are maintained and the financial statements have been prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America.

 

(b)  Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect certain reported amounts in the financial statements and accompanying notes.  Actual results could differ from these estimates and assumptions.

 

(c)  Comprehensive Income

 

The Company reports comprehensive income in accordance with the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 220, Comprehensive Income (“ASC 220”).  ASC 220 established standards for reporting and presentation of comprehensive income and its components in a full set of financial statements.  Comprehensive income (loss) consists of net income (loss) and net unrealized gains (losses) on securities and is presented in the statements of changes in stockholders’ equity.  ASC 220 requires only additional disclosures in the financial statements; it does not affect the Company’s financial position or results of operations.

 

(d)  Fair Value of Financial Instruments

 

In accordance with the reporting requirements of FASB ASC Topic 825, Financial Instruments, the Company calculates the fair value of its assets and liabilities which qualify as financial instruments under this statement and includes this additional information in the notes to financial statements when the fair value is different than the carrying value of those financial instruments.  The estimated fair value of cash equivalents, accounts receivable, and accounts payable approximates their carrying amounts due to the relatively short maturity of these instruments.

 

(e)  Cash and Cash Equivalents

 

The Company considers all cash and highly liquid investments with original maturities of three months or less to be cash equivalents.

 

(f)  Trade Accounts Receivable

 

The Company performs ongoing credit evaluations of its customers’ financial condition and extends credit to virtually all of its customers.  Credit losses to date have not been significant and have been within management’s expectations.  In the event of complete non-performance by the Company’s customers, the maximum exposure to the Company is the outstanding accounts receivable balance at the date of non-performance.

 

26



Table of Contents

 

(g)  Investment Securities

 

The Company reports investments in accordance with FASB ASC Topic 320, Investments - Debt and Equity Securities.  The Company’s investments are classified at the time of purchase into one of three categories as follows:

 

·                  Held to Maturity Securities - Debt securities that the Company has the positive intent and ability to hold to maturity are reported at amortized cost, adjusted for the amortization or accretion of premiums and discounts.

 

·                  Trading Securities - Debt and equity securities that are bought and held principally for the purpose of selling them in the near term are reported at fair value, with unrealized gains and losses included in earnings.

 

·                  Available for Sale Securities - Debt and equity securities not classified as held to maturity securities or trading securities are reported at fair value, with unrealized gains and losses excluded from earnings and reported as a separate component of stockholders’ equity (net of tax effects).

 

The Company did not have any securities classified as held to maturity or trading as of February 28, 2010 and 2009.

 

A decline in the market value of any available for sale security below cost that is deemed to be other than temporary results in a reduction of the carrying amount to fair value.  The impairment is charged to earnings and a new cost basis for the security is established.  In fiscal 2009, management determined that a security held as available for sale had been permanently impaired.  Therefore, an impairment charge of $124,143 is reflected in the accompanying statement of operations for 2009.  No such impairment charges were incurred in fiscal 2010.

 

Dividend and interest income are recognized when earned.  Gains and losses on securities sold are computed under the specific identification method.  A gain on sale of marketable securities available for sale in the amount of $125,343 was recognized in fiscal 2010.  No such gain was recognized in fiscal 2009.

 

(h)  Oil and Gas Properties

 

The Company uses the successful efforts method of accounting for oil and gas producing activities.  Costs to acquire mineral interests in oil and gas properties, to drill exploratory wells that find proved reserves, and to drill and equip development wells are capitalized.  Geological and geophysical costs, costs to drill exploratory wells that do not find proved reserves, and non-producing leasehold abandonments are expensed as incurred. Unproved oil and gas properties are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance.  Capitalized costs of producing oil and gas properties are depleted and depreciated by the units-of-production method based on proved oil and gas reserves as estimated by an independent petroleum reservoir engineering firm.

 

Upon sale or retirement of a proved property, the cost and related accumulated depletion and depreciation are eliminated from the property accounts, and any resulting gain or loss is recognized.

 

(i)            Coal and Gravel Properties

 

Costs attributable to the acquisition and development of coal and gravel properties are capitalized, while costs incurred to maintain the properties are expensed.  Undeveloped coal and gravel properties, which are individually significant, are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Capitalized costs of producing properties are depleted on a property-by-property basis using the units-of-production method.

 

Depreciation on mining and service equipment is calculated using accelerated and straight-line methods over the estimated useful lives of the assets. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts and any gains or losses thereon are recognized.

 

(j)  Other Property and Equipment

 

Depreciation on other property and equipment is calculated using accelerated and straight-line methods over the estimated useful lives of the assets. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts and any gains or losses thereon are recognized.

 

27



Table of Contents

 

(k)  Real Estate Held for Sale

 

Real estate held for sale is carried at cost, which does not exceed net realizable value. Real estate development and construction costs directly identifiable with such property are capitalized.  The cost of the property remains as a non-current asset since the Company may proceed with the development if it is unable to complete a sales transaction.

 

(l)  Impairment of Long-Lived Assets

 

The carrying value of property and equipment is periodically evaluated under the provisions of FASB ASC Topic 360, Property, Plant, and Equipment (“ASC 360”).  ASC 360 requires long-lived assets and certain identifiable intangibles to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value.

 

Under ASC 360, the Company evaluates impairment of proved oil and gas properties on a field-by-field basis.  On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows.  The Company recorded $8,568 and $558,986 in impairment losses related to its proved oil and gas properties, in fiscal 2010 and 2009, respectively.  If estimated future cash flows are not achieved with respect to certain fields, additional write-downs may be required.

 

(m)  Investment in Partnership

 

The Company uses the equity method of accounting for its investment in a partnership.  The investment in partnership of approximately $41,000 and $44,000 at February 28, 2010 and 2009, respectively, are included in other non-current assets in the accompanying balance sheets.  The Company recognized income (loss) pertaining to its interest in the partnership of approximately $(4,000) and $13,000 during fiscal 2010 and 2009, respectively, which are included in other income in the accompanying statements of operations.

 

(n)  Asset Retirement Obligations

 

The Company accounts for asset retirement obligations under FASB ASC Topic 410, Asset Retirement and Environmental Obligations (“ASC 410”).  ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred.  Oil and gas producing companies incur this liability upon acquiring or drilling a well.  Under ASC 410, an asset retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties on the accompanying balance sheet which is allocated to expense over the useful life of the asset.  Periodic accretion of the discount on asset retirement obligations is recorded as an expense in the accompanying statement of operations.

 

(o)  Revenue Recognition

 

The Company utilized the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells.  Crude oil inventories are immaterial and are not recorded.  Gas imbalances are accounted for using the sales method.  Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers.  However, the Company has no history of significant gas imbalances.

 

(p)  Income Taxes

 

Deferred income taxes are determined using the liability method in accordance with FASB ASC Topic 740, Income Taxes.  Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.

 

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

 

28



Table of Contents

 

(q)  Earnings or Loss per Common Share

 

Basic earnings (loss) per common share is calculated by dividing net income (loss) (available to common stockholders) by the weighted average number of common shares outstanding for the period.  Diluted earnings (loss) per common share reflects the potential dilution that could occur if accounts or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the Company.  For the years and quarters presented herein, basic and diluted earnings (loss) per common share are the same as the Company has no common stock equivalents.

 

(r)  Reclassifications

 

Certain 2009 amounts have been reclassified to conform to the 2010 presentation.

 

(s)  Impact of Recently Issued Accounting Standards

 

On December 31, 2008, the SEC issued Modernization of Oil and Gas Reporting updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include changes to the pricing used to estimate reserves utilizing a 12-month average price rather than a single day spot price, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC requires companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 15, 2009. Early adoption was not permitted. The Company has adopted this issued pronouncement as of this filing and results of this adoption are included in the report.

 

In June 2009, FASB issued a new Statement of Financial Accounting Standards (“SFAS”) No. 168, The FASB Accounting Standards Codification (“ASC”) and the Hierarchy of Generally Accepted Accounting Principles.  The FASB ASC became the single source of authoritative nongovernmental U.S. generally accepted accounting principles (“GAAP”), superseding existing FASB, American Institute of Certified Public Accountants (“AICPA”), Emerging Issues Task Force (“EITF”), and related accounting literature.  The new codification system reorganizes the thousands of GAAP pronouncements into roughly 90 accounting topics and displays them using a consistent structure.  Also included is relevant SEC guidance organized using the same topical structure in separate sections.  This standard, which is now considered FASB ASC Topic 105, became effective for financial statements issued for reporting periods that ended after September 15, 2009.

 

C.   Fair Value

 

Effective March 1, 2008, the Company adopted SFAS No.157, Fair Value Measurements currently classified in FASB ASC Topic 820 (“ASC 820”).  ASC 820 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.  As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability.

 

ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value:

 

·                  Level 1 — Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

·                  Level 2 — Other inputs that are directly or indirectly observable in the marketplace.

·                  Level 3 — Unobservable inputs which are supported by little or no market activity.

 

The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  The Company’s cash equivalents and marketable securities are classified within Level 1.  Assets measured at fair value are summarized below:

 

29



Table of Contents

 

 

 

 

 

Fair Value Measurement at February 28, 2010 Using:

 

 

 

February 28, 2010

 

Quoted Prices In
Active Markets
For Identical Assets
(Level 1)

 

Significant Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

 

Assets:

 

 

 

 

 

 

 

 

 

Money market funds

 

$

1,401,601

 

$

1,401,601

 

$

 

$

 

Investment securities available for sale

 

128,030

 

128,030

 

 

 

Certificates of deposit

 

204,399

 

204,399

 

 

 

Non-current certificates of deposit

 

405,834

 

405,834

 

 

 

 

 

$

2,139,864

 

$

2,139,864

 

$

 

$

 

 

 

 

 

 

Fair Value Measurement at February 28, 2009 Using:

 

 

 

February 28, 2009

 

Quoted Prices In Active Markets
For Identical Assets
(Level 1)

 

Significant Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

 

Assets:

 

 

 

 

 

 

 

 

 

Money market funds

 

$

144,825

 

$

144,825

 

$

 

$

 

Investment securities available for sale

 

72,992

 

72,992

 

 

 

Certificates of deposit

 

2,483,931

 

2,483,931

 

 

 

Non-current certificates of deposit

 

380,527

 

380,527

 

 

 

 

 

$

3,082,275

 

$

3,082,275

 

$

 

$

 

 

D.   Investment Securities

 

As of February 28, 2010, the amortized cost and fair value of the Company’s investment securities available for sale, was approximately $107,000 and $128,000, respectively.  As of February 28, 2009, the amortized cost and fair value of the Company’s investment securities available for sale was approximately $104,000 and $73,000, respectively.

 

E.   Asset Retirement Obligations

 

Pursuant to FASB ASC Topic 410, Asset Retirement and Environmental Obligations, the Company has recognized the fair value of its asset retirement obligations related to the plugging, abandonment, and remediation of oil and gas producing properties as well as the reclamation of the property surrounding the Company’s previous coal mining operations.  The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets, which approximated $344,000.

 

The liability has been accreted to its present value as of the end of each year.  The Company evaluated 72 wells, and has determined a range of abandonment dates between February 2010 and February 2060.

 

The following represents a reconciliation of the asset retirement obligations for the fiscal years ended February 28, 2010 and 2009:

 

 

 

2010

 

2009

 

Asset retirement obligations at beginning of year

 

$

594,600

 

$

500,774

 

Revision to estimate

 

(29,006

)

13,547

 

Additions to asset retirement obligation

 

2,631

 

68,935

 

Liabilities settled during the year

 

(88,476

)

(13,547

)

Accretion of discount

 

15,096

 

24,891

 

Asset retirement obligations at end of year

 

$

494,845

 

$

594,600

 

 

30



Table of Contents

 

F.   Income Taxes

 

The Company’s income tax expense (benefit) attributable to loss from operations consists of the following:

 

 

 

Current

 

Deferred

 

Total

 

Fiscal year ended February 28, 2010:

 

 

 

 

 

 

 

U.S. Federal

 

$

 

$

(102,704

)

$

(102,704

)

State and local

 

7,489

 

 

7,489

 

Income tax expense (benefit)

 

$

7,489

 

$

(102,704

)

$

(95,215

)

 

 

 

 

 

 

 

 

Fiscal year ended February 28, 2009:

 

 

 

 

 

 

 

U.S. Federal

 

$

 

$

(303,720

)

$

(303,720

)

State and local

 

6,634

 

 

6,634

 

Income tax expense (benefit)

 

$

6,634

 

$

(303,720

)

$

(297,086

)

 

Income tax expense (benefit) for the fiscal years presented differs from the “expected” Federal income tax benefit for those years, computed by applying the statutory U.S. Federal corporate tax rate of 34% to pre-tax loss, as a result of the following:

 

 

 

2010

 

2009

 

Computed “expected” tax benefit

 

$

(111,372

)

$

(322,928

)

State and local income taxes, net of Federal income tax

 

(9,729

)

 

Marketable securities

 

(17,878

)

 

Other, primarily revision of prior year provision estimate

 

43,764

 

25,842

 

Income tax expense (benefit)

 

$

(95,215

)

$

(297,086

)

 

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities, at February 28, 2010 and 2009 are presented below:

 

 

 

2010

 

2009

 

Deferred tax assets:

 

 

 

 

 

Net operating loss carryforward

 

$

553,972

 

$

388,626

 

Contributions

 

2,672

 

 

Alternative minimum tax credit carryforward

 

98,033

 

98,033

 

Marketable securities

 

35,040

 

52,918

 

Asset retirement obligations

 

168,248

 

202,164

 

Total deferred tax assets

 

857,965

 

741,741

 

 

 

 

 

 

 

Deferred tax liabilities:

 

 

 

 

 

Oil, gas and coal properties and other property and equipment, principally due to depletion and depreciation

 

(99,062

)

(67,709

)

Property and equipment

 

(4,404

)

(3,568

)

Total deferred tax liabilities

 

(103,466

)

(71,277

)

Net deferred tax asset

 

$

754,499

 

$

670,464

 

 

 

 

2010

 

2009

 

Included in the balance sheet as:

 

 

 

 

 

Deferred income taxes, current

 

$

 

$

 

Deferred income taxes, non-current

 

754,499

 

670,464

 

Net deferred tax asset

 

$

754,499

 

$

670,464

 

 

Based on the future reversal of existing taxable temporary differences and future earnings expectations, management of the Company believes it is more likely than not that deferred tax assets will be realized or settled, and accordingly, no valuation allowance has been recorded.

 

At February 28, 2010, the Company has an alternative minimum tax credit carryforward of approximately $98,000, which has no expiration date and is available to reduce the Company’s future taxable income.  Additionally, at February 28, 2010, the Company has a net operating loss carryforward for Federal taxes of approximately $1,629,000 which is available to offset the Company’s future taxable income.  The net operating loss carryforward for Federal taxes will expire as follows:

 

31


 


Table of Contents

 

 

 

Approximate amount of net operating loss carryforward
for federal taxes which will expire

 

Percentage of total net operating loss
carryforward for federal taxes

 

2027

 

$

739,000

 

45.4

%

2029

 

404,000

 

24.8

%

2030

 

486,000

 

29.8

%

 

G. Segment Information

 

The following information is presented in accordance with FASB ASC Topic 280, Segment Reporting. The Company is engaged in oil and gas, coal and gravel activities and real estate development. The Company has identified such segments based on management responsibility and the nature of the Company’s products, services and costs. There are no major distinctions in geographical areas served as all operations are in the United States. The Company measures segment profit (loss) as income (loss) from operations. Business segment assets are those assets controlled by each reportable segment. The following table sets forth certain information about the financial information of each segment for the fiscal years ended February 28, 2010 and 2009:

 

 

 

2010

 

2009

 

Business segment revenue:

 

 

 

 

 

Oil and gas

 

$

1,020,160

 

$

1,643,972

 

 

 

 

 

 

 

Business segment profit (loss):

 

 

 

 

 

Oil and gas

 

$

265,903

 

$

(22,493

)

Coal and gravel

 

(26,057

)

(119,582

)

Real estate development

 

(194,165

)

(237,135

)

General corporate

 

(514,994

)

(546,703

)

Loss from operations

 

(469,313

)

(925,913

)

Other income (loss)

 

141,751

 

(23,876

)

Loss before income taxes

 

$

(327,562

)

$

(949,789

)

 

 

 

 

 

 

Depreciation, depletion, and amortization:

 

 

 

 

 

Oil and gas

 

$

18,517

 

$

11,800

 

Coal and gravel

 

 

 

Real estate development

 

 

 

General corporate

 

11,611

 

16,630

 

Total depreciation, depletion and amortization

 

$

30,128

 

$

28,430

 

 

 

 

2010

 

2009

 

Capital expenditures:

 

 

 

 

 

Oil and gas

 

$

53,679

 

$

147,205

 

Real estate development

 

 

33,034

 

General corporate

 

 

 

Total capital expenditures

 

$

53,679

 

$

180,239

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

Oil and gas

 

$

3,084,610

 

$

3,933,061

 

Coal and gravel

 

260,488

 

260,488

 

Real estate development

 

3,168,107

 

3,168,107

 

General corporate

 

529,681

 

516,121

 

Total assets

 

$

7,042,886

 

$

7,877,777

 

 

H.   Related Party Transactions

 

In the normal course of business, the Company owns interests in various oil and gas properties in which certain stockholders and related parties also own interests.

 

32



Table of Contents

 

I. Commitment and Contingency

 

As of February 28, 2010 and 2009, the Company has pledged interest-bearing cash deposits of $405,834 and $380,527, respectively, to secure letters of credit in favor of the Colorado Bureau of Land Management for state requirements regarding land reclamation with respect to the Carbon Junction Coal Mine. These pledged cash deposits are included in other non-current assets in the accompanying balance sheets.

 

J.   Risk Concentrations

 

The Company considers all highly liquid investments with a maturity of three months or less at the time of purchase to be cash equivalents. The Company maintains deposits primarily in two financial institutions, which deposits may at times exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”) or the Securities Insurance Protection Corporation (“SIPC”). The Company has not experienced any losses related to amounts in excess of FDIC or SIPC limits.

 

Oil sales to two customers, which accounted for more than 10% of the Company’s total oil sales, approximated $597,000 (66.4%) and $229,000 (25.5%) for the fiscal year ended February 28, 2010. Two customers accounted for approximately $971,000 (67.5%) and $355,000 (24.8%) of the Company’s total oil sales for the fiscal year ended February 28, 2009. Gas sales to three customers approximated $50,000 (60.0 %), $16,000 (18.6 %), and $9,000 (10.5 %) of the Company’s total gas sales for the fiscal year ended February 28, 2010. Three customers accounted for approximately $99,000 (57.8%), $31,000 (18.4%), and $23,000 (13.3%) of the Company’s total gas sales for the fiscal year ended February 28, 2009. Lease operating payments primarily made to a principal operator on its oil and gas producing properties approximated $657,000 and $926,000 in fiscal 2010 and 2009, respectively.

 

K.   Quarterly Operating Results (Unaudited)

 

Quarterly results of operations for fiscal 2010 and 2009 were as follows:

 

Fiscal 2010

 

First
Quarter

 

Second
Quarter

 

Third
Quarter

 

Fourth
Quarter

 

Full Fiscal
Year

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

$

227,102

 

$

267,506

 

$

259,844

 

$

265,708

 

$

1,020,160

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from operations

 

(151,973

)

(201,084

)

(121,368

)

5,112

 

(469,313

)

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(87,555

)

$

(125,900

)

$

(75,812

)

$

56,920

 

$

(232,347

)

 

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted income (loss) per common share

 

$

(0.02

)

$

(0.03

)

$

(0.02

)

$

0.01

 

$

(0.06

)

 

Fiscal 2009

 

First
Quarter

 

Second
Quarter

 

Third
Quarter

 

Fourth
Quarter

 

Full Fiscal
Year

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

$

509,693

 

$

598,182

 

$

359,095

 

$

177,002

 

$

1,643,972

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from operations

 

2,013

 

(59,766

)

(190,921

)

(677,239

)

(925,913

)

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

31,313

 

$

(24,345

)

$

(67,432

)

$

(592,239

)

$

(652,703

)

 

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted income (loss) per common share

 

$

0.01

 

$

(0.01

)

$

(0.02

)

$

(0.13

)

$

(0.15

)

 

33



Table of Contents

 

OAKRIDGE ENERGY, INC,

 

L. SUPPLEMENTAL OIL AND GAS DATA (UNAUDITED)

 

The following tables set forth supplementary disclosures for oil and gas producing activities in accordance with FASB ASC Topic 932, Extractive Activities - Oil and Gas (“ASC 932”).

 

Costs Incurred

 

A summary of costs incurred in oil and gas property acquisition, development, and exploration activities (both capitalized and charged to expense) for the fiscal years ended February 28, 2010 and 2009, as follows:

 

 

 

2010

 

2009

 

Acquisition of proved properties

 

$

53,679

 

$

142,014

 

Acquisition of unproved properties

 

$

 

$

5,191

 

Exploration costs

 

$

377

 

$

65,994

 

 

Results of Operations for Producing Activities

 

The following table presents the results of operations for the Company’s oil and gas producing activities for the fiscal years ended February 28, 2010 and 2009:

 

 

 

2010

 

2009

 

Revenues

 

$

1,020,160

 

$

1,643,972

 

Production costs

 

(790,781

)

(1,193,406

)

Depletion, depreciation, accretion and valuation provisions

 

(42,181

)

(595,676

)

Exploration costs

 

(377

)

(65,994

)

 

 

186,821

 

(211,104

)

Income tax (expense) benefit

 

(63,519

)

71,775

 

Results of operations for producing activities (excluding corporate overhead and interest costs)

 

$

123,302

 

$

(139,329

)

 

Reserve Quantity Information

 

The following table presents the Company’s estimate of its proved oil and gas reserves all of which are located in the United States. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of reserves related to new discoveries are more imprecise than those for producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared with the assistance of an independent petroleum reservoir engineering firm. Oil reserves, which include condensate and natural gas liquids, are stated in barrels and gas reserves are stated in thousands of cubic feet.

 

 

 

Oil
(Bbls)

 

Gas
(mcf)

 

Proved developed and undeveloped reserves:

 

 

 

 

 

Balance at March 1, 2008

 

675,695

 

233,998

 

Revisions of previous estimates

 

(15,807

)

(134,168

)

Production

 

(16,088

)

(19,860

)

Balance at February 28, 2009

 

643,800

 

79,970

 

Revisions of previous estimates

 

34,343

 

159,917

 

Production

 

(13,049

)

(19,805

)

Balance at February 28, 2010

 

665,094

 

220,082

 

 

 

 

 

 

 

Proved developed reserves:

 

 

 

 

 

February 29, 2008

 

210,810

 

233,998

 

February 28, 2009

 

44,741

 

79,970

 

February 28, 2010

 

110,458

 

220,082

 

 

34



Table of Contents

 

Standardized Measure of Discounted Future Net Cash Flow and Changes Therein Relating to Proved Oil and Gas Reserves

 

The following table, which presents a standardized measure of discounted future cash flows and changes therein relating to proved oil and gas reserves, is presented pursuant to ASC 932. In computing this data, assumptions other than those required by the Financial Accounting Standards Board could produce different results. Accordingly, the data should not be construed as being representative of the fair market value of the Company’s proved oil and gas reserves.

 

Effective fiscal 2010, the SEC reporting rules require that year end reserve calculations and future cash inflows be based on the average market prices for sales of oil and gas on the first calendar day of each month during the year. The average prices used for fiscal 2010 under these new rules were $62.20 per barrel of oil and $3.54 per mcf of natural gas for proved developed reserves and $62.02 per barrel of oil for proved undeveloped reserves. There are no proved undeveloped gas reserves for either fiscal 2010 or 2009. For fiscal 2009, future cash inflows were computed by applying year end prices of oil and natural gas to year end quantities of proved oil and natural gas reserves. Prices used in computing year end 2009 future cash inflows were $33.33 per barrel of oil and $2.89 per mcf of natural gas for proved developed reserves and $31.31 per barrel of oil for proved undeveloped reserves. Future price changes were considered to the extent provided by contractual arrangements in existence at year end. Future development and production costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year end costs. Future income tax expenses were computed by applying the year end statutory tax rates with consideration of future tax rates already legislated as well as tax credits and allowances relating to the Company’s proved oil and gas reserves to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. The standardized measure of discounted future cash flows at February 28, 2010 and 2009, which represents the present value of estimated future cash flows using a discount rate of 10% a year, follows:

 

 

 

2010

 

2009

 

Future cash inflows

 

$

41,672,090

 

$

20,478,971

 

Future production and development costs

 

(9,105,352

)

(7,999,638

)

Future income tax expenses

 

(4,981,776

)

(1,844,054

)

Future net cash flows

 

27,584,962

 

10,635,279

 

10% annual discount for estimated timing of cash flows

 

(8,493,410

)

(3,143,919

)

Standardized measure of discounted future net cash flows related to proved reserves

 

$

19,091,552

 

$

7,491,360

 

 

 

 

 

 

 

 

 

Beginning of year

 

$

7,491,360

 

$

26,310,140

 

Sales of oil and gas, net of production costs

 

(229,379

)

(450,566

)

Extensions, discoveries, and improved recoveries, less related costs

 

347,030

 

341,415

 

Accretion of discount

 

749,136

 

2,631,014

 

Net change in sales and transfer prices, net of production costs

 

11,543,232

 

(18,625,400

)

Changes in estimated future development costs

 

(5,615

)

 

Net change in income taxes

 

(4,313,800

)

6,970,252

 

Changes in production rates (timing and other)

 

1,691,849

 

(9,263,735

)

Revisions of previous quantities

 

1,817,739

 

(421,760

)

End of year

 

$

19,091,552

 

$

7,491,360

 

 

35



Table of Contents

 

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

The Company did not change its independent registered public accounting firm or have any disagreements with them on accounting and financial disclosure issues in the fiscal year ended February 28, 2010.

 

ITEM 9A(T).

CONTROLS AND PROCEDURES

 

Disclosure Controls and Procedures

 

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”). This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC. In designing and evaluating our disclosure controls and procedures, management recognized that disclosure controls and procedures, no matter how well conceived and operated, can provide only reasonable assurance of achieving the desired control objectives, and we necessarily are required to apply our judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures.

 

Our management, namely our Chief Executive and Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this annual report. Based upon that evaluation, our Chief Executive and Financial Officer has concluded that our disclosure controls and procedures were not effective as of the end of the period covered by this annual report because of certain deficiencies involving internal control over financial reporting that constituted material weaknesses as discussed below.

 

Changes in Internal Control Over Financial Reporting

 

There has not been any change in the Company’s internal control over financial reporting during the fourth quarter of fiscal 2010 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Management’s Annual Report on Internal Control over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control system was designed 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. Because of inherent limitations, a system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

Our management, namely our Chief Executive and Financial Officer, conducted an evaluation of the effectiveness of our internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on its evaluation, our management concluded that there is a material weakness in our internal control over financial reporting. A material weakness is a deficiency, or a combination of control deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

 

The material weakness identified was that the Company does not have the required technical expertise to properly calculate complex oil and gas required disclosures for ASC 740 income taxes and relies on outside sources for that calculation.

 

We have not implemented a control to mitigate the material weakness related to ASC 740 calculations and disclosures. At any time, if it appears that a control can be implemented to mitigate such material weaknesses, the Company expects to implement the control. This annual report on Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the SEC that permit the Company to provide only management’s report in this annual report on Form 10-K.

 

36



Table of Contents

 

This report shall not be deemed to be filed for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

 

ITEM 9B.               OTHER INFORMATION

 

None.

 

37



Table of Contents

 

PART III

 

ITEM 10.               DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

Directors and Executive Officers

 

The following table provides certain information pertaining to the Company’s directors and executive officers:

 

Name and Age

 

Business Experience
and Current Positions
With Company

 

Year First
Became Director

 

 

 

 

 

Sandra Pautsky — 68

 

Chairperson of the Board of Directors of the Company since July 1998, President and Chief Executive Officer since June 1998 and Secretary-Treasurer since May 1992

 

1986

Danny Croker — 60

 

Member of the Board of Directors, Vice President and Assistant Secretary - Treasurer of the Company since May 1992 and owner of Exlco, Inc., oil and gas operations since 1980

 

1992

Randy Camp — 57

 

Member of the Board of Directors, partner in the firm of Moore, Camp, Phillips & Patterson, L.L.P. (or its predecessor firms), Certified Public Accountants, Wichita Falls, Texas since 1980

 

1992

 

Mr. Croker is Ms. Pautsky’s stepbrother. There are no other family relationships among any of the directors or executive officers of the Company. Ms. Pautsky may be considered to be the controlling stockholder of the Company by virtue of her beneficial ownership of approximately 30.8% of the Company’s outstanding common stock and her positions with the Company. See “Item 12.-Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.” Each of the directors and executive officers holds office from the date of his or her election for a period of one year or until his or her successor has been elected. None of the directors or executive officers is involved, nor has been involved during the past ten years, in any legal proceedings in which he or she is a party adverse or has a material interest adverse to the Company. None of the directors or executive officers has been involved in any legal proceedings which are material to an evaluation of his or her ability or integrity.

 

Sandra Pautsky currently serves as Chairperson of the Board of Directors, President, Chief Executive Officer and Secretary-Treasurer of the Company. Ms. Pautsky has over forty years experience in the oil and gas industry, has been intimately involved in the operations of the Company and became responsible for the daily administration of the Company in 1988. Ms. Pautsky has studied extensively in the geologic field at a local university.

 

Danny Croker currently serves as a member of the Board of Directors, Vice President and Assistant Secretary Treasurer of the Company. Mr. Croker is also an independent oil and gas business man with experience in numerous phases of the industry. He has been employed by the Company for 32 years executing field and exploration activities. His knowledge of the day-to-day operations, completion and workover procedures as well as his supervision skills continues to benefit the Company. Mr. Croker received a B.S. degree from Midwestern State University.

 

Randy Camp serves as a member of the Board of Directors. Mr. Camp is an independent director as defined in Rule 5605 (a)(2) of the NASDAQ listing rules. He is a partner in the firm of Moore, Camp, Phillips & Patterson, L.L.P., Certified Public Accountants. He has been with this firm since 1980. Mr. Camp has unique knowledge of accounting and its relation to the oil and gas industry.

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

Section 16(a) of the Exchange Act requires the Company’s executive officers, directors and persons who beneficially own more than 10% of the Company’s common stock to file with the SEC initial reports of beneficial ownership and reports of changes in beneficial ownership of the Company’s common stock. The rules promulgated by the SEC under Section 16(a) of the Exchange Act require those persons to furnish the Company with copies of all reports filed with the SEC pursuant to Section 16(a).

 

Based solely on the Company’s review of copies of forms it received and on written representations from the foregoing persons, the Company believes that during the fiscal year ended February 28, 2010 all filing requirements under Section 16(a) of the Exchange Act were met on a timely basis by such persons.

 

38



Table of Contents

 

Audit Committee

 

The Company does not have a separately-designated standing audit committee. Instead, the entire Board of Directors acts as the audit committee for the Company.

 

Audit Committee Financial Expert

 

Although the Company does not have a separately-designated audit committee, a member of the Company’s Board of Directors, Mr. Camp, meets the requirements to be considered an audit committee financial expert and is independent as defined in Rules 5605(a)(2) and 5605 (c)(2) of the NASDAQ listing rules.

 

Nomination Procedures

 

The Company has not made any changes to the procedures by which security holders may recommend nominees to the Company’s Board of Directors since the Company last provided disclosure to security holders in response to the requirements of Item 7 of Schedule 14A of the Exchange Act.

 

Code of Ethics

 

The Company has adopted a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer and controller, or persons performing similar functions. Pursuant to the requirements of Item 406 of Regulation S-K, the Company’s “Code of Ethical Conduct for Senior Officers,” which is currently in effect, is filed as Exhibit 14 to this annual report on Form 10-K.

 

ITEM 11.               EXECUTIVE COMPENSATION

 

The following table sets forth information regarding compensation for services in all capacities to the Company for each of the last three fiscal years of the Company’s Chief Executive Officer. No other executive officer of the Company received total annual salary and bonus exceeding $100,000 in any of such years.

 

 

 

Summary Compensation Table

 

Name and

Principal Position

 

Year

 

Salary

 

Bonus

 

All Other

Compensation(1)

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

Sandra Pautsky

 

2010

 

$

125,000

 

$

10,417

 

$

217

 

$

135,634

 

President and Chief Executive Officer

 

2009

 

125,000

 

10,417

 

195

 

$

135,612

 

 

2008

 

125,000

 

10,417

 

163

 

$

135,580

 

 


(1)           All other compensation consisted of Company paid life insurance premiums.

 

The Company does not have employment agreements with any of its executive officers, has no material bonus, profit-sharing or stock option plans or pension or retirement benefits. The Company has a group health insurance plan which it makes available to all employees of the Company and their family members on a non-discriminatory basis. Pursuant to such plan, $25,000 in life insurance benefits are provided for all employees of the Company, with the exception of Ms. Pautsky who would receive a benefit of $18,750 as benefits decrease as certain age levels are reached.

 

Executive officers of the Company who are also directors do not receive any fee or remuneration for services as members of the Board of Directors. Mr. Camp, the only director who is not an employee of the Company, received an annual fee of $3,000 for serving as a director in the fiscal year ended February 28, 2010.

 

39



Table of Contents

 

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

The following table shows the beneficial ownership of the Company’s common stock as of May 28, 2010 by: (i) each person known by the management of the Company to own more than 5% of the Company’s outstanding common stock; (ii) each executive officer and director; and (iii) the executive officers and directors of the Company as a group.

 

Name and Address of
Beneficial Owner

 

Amount
Beneficially
Owned

 

Percent
of
Class

 

Sandra Pautsky

 

1,253,181

(1)

30.80

%

4613 Jacksboro Highway

 

 

 

 

 

Wichita Falls, Texas 76302

 

 

 

 

 

 

 

 

 

 

 

Flem Noel Pautsky, Jr.

 

1,026,690

 

25.23

%

4613 Jacksboro Highway

 

 

 

 

 

Wichita Falls, Texas 76302

 

 

 

 

 

 

 

 

 

 

 

West Coast Asset Management

 

617,317

 

15.17

%

2151 Alessandro Drive

 

 

 

 

 

Ventura, CA 93001

 

 

 

 

 

 

 

 

 

 

 

Noel Pautsky Trust

 

536,062

 

13.17

%

4613 Jacksboro Highway

 

 

 

 

 

Wichita Falls, Texas 76302

 

 

 

 

 

 

 

 

 

 

 

Danny Croker

 

 

 

4613 Jacksboro Highway

 

 

 

 

 

Wichita Falls, Texas 76302

 

 

 

 

 

 

 

 

 

 

 

Randy Camp

 

100

 

*

 

1400 Eleventh St.

 

 

 

 

 

Wichita Falls, Texas 76301

 

 

 

 

 

 

 

 

 

 

 

Executive officers and directors as a group (three persons)

 

1,253,281

(2)

30.80

%

 


*

Represents less than 1% of outstanding common stock.

 

 

 

 

(1)

Includes: (i) 576,655 shares owned directly by Ms. Pautsky; (ii) 536,062 owned by the Noel Pautsky Trust of which Ms. Pautsky is the Trustee and one of four beneficiaries and (iii) 140,464 shares owned by the Noel Pautsky Marital Trust, of which Ms. Pautsky is the Trustee. Ms. Pautsky disclaims any beneficial ownership of the shares owned by the Noel Pautsky Trust in excess of 125,000 shares. Ms. Pautsky also disclaims any beneficial ownership of the shares owned by the Noel Pautsky Marital Trust, except to the extent of her pecuniary interest therein.

 

 

 

 

(2)

Includes all shares beneficially owned by Ms. Pautsky, Mr. Croker and Mr. Camp.

 

 

The Company does not have any securities authorized for issuance under equity compensation plans.

 

40



Table of Contents

 

ITEM 13.               CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

 

Related Party Transactions

 

Flem Noel Pautsky, Jr. is a beneficial owner of in excess of 5% of the Company’s outstanding common stock.  On July 8, 2009, the Company purchased 92,255 shares of the common stock held by Flem Noel Pautsky, Jr. in a private transaction for $2.20 per share, for a total purchase price of $202,961.

 

West Coast Asset Management is a beneficial owner of in excess of 5% of the Company’s outstanding common stock.  On July 29, 2009, the Company purchased 55,472 shares of the common stock held by West Coast Asset Management in a private transaction for $2.20 per share, for a total purchase price of $122,038.

 

Director Independence

 

The Company’s Board of Directors consists of Sandra Pautsky, Danny Croker and Randy Camp.  Mr. Camp is an independent director as defined in Rule 5605(a)(2) of the NASDAQ listing rules.

 

41



Table of Contents

 

ITEM 14.               PRINCIPAL ACCOUNTING FEES AND SERVICES

 

The independent registered public accounting firm of Whitley Penn LLP (“Whitley Penn”) audited the financial statements of the Company for the fiscal year ended February 28, 2010.

 

Audit Fees

 

Fees billed by Whitley Penn for the fiscal year 2009 and 2010 audits of the Company’s financial statements and the reviews of quarterly reports on Form 10-Q during such years were $59,888 and $60,861, respectively.

 

Audit-Related Fees

 

The Company did not incur any audit-related fees from Whitley Penn during the fiscal year ended February 28, 2009 or 2010.

 

Tax Fees

 

Fees billed by Whitley Penn to the Company for preparation of the Company’s Federal income tax return for the fiscal year 2009 and fiscal year  2010 were $14,000 and $12,900, respectively.

 

All Other Fees

 

The Company did not incur any other fees from Whitley Penn during the fiscal year 2009 or 2010.

 

Pre-Approval Policies and Procedures

 

The Company does not have a separately-designated audit committee and the Board of Directors of the Company acts in that capacity.  Prior to the Company’s engagement of Whitley Penn to render the audit and non-audit services set forth above, the engagement was approved by the Company’s Board of Directors.

 

42



Table of Contents

 

PART IV

 

ITEM 15.               EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

Exhibit No.

 

Document Description

3(i)(a)

 

Articles of Incorporation of the Company dated May 9, 1969 filed as Exhibit A (1) to the Company’s Form 10 and incorporated herein by reference.

 

 

 

3(i)(b)

 

Amendment to Articles of Incorporation of the Company dated October 22, 1982 filed as Exhibit 3. (I)(B) Form 10-KSB for the period ending February 28, 2005 and incorporated herein by reference.

 

 

 

3(ii)

 

By-Laws of the Company dated May 23, 1975 filed as Exhibit A (4) to Form 10 and incorporated herein by reference.

 

 

 

14

 

Code of Ethical Conduct of Senior Officers filed as Exhibit 14 to the Company’s Form 10-KSB for the period ending February 28, 2005 and incorporated herein by reference.

 

 

 

23

 

Consent of Independent Petroleum Engineers and Geologists (filed herewith).

 

 

 

31(i)

 

Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

 

 

 

31(ii)

 

Certifications of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

 

 

 

32

 

Certifications of Chief Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

 

 

 

99

 

Stephens Engineering engineering report with respect to the Company’s proved oil and gas reserves (filed herewith).

 

43



Table of Contents

 

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

OAKRIDGE ENERGY, INC.

 

By:

/s/ Sandra Pautsky

 

 

Sandra Pautsky, President

 

 

DATE: June 1, 2010

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

By:

/s/ Sandra Pautsky

 

By:

/s/ Danny Croker

 

Sandra Pautsky, President,

 

 

Danny Croker, Director, Vice President and

 

Chief Executive Officer, Principal Financial Officer

 

 

Assistant Secretary-Treasurer

 

and Director (Principal Executive Officer and

 

 

 

 

Principal Financial Officer)

 

 

 

 

 

DATE: June 1, 2010

 

DATE: June 1, 2010

 

 

By:

/s/  Randy Camp

 

 

 

 

Randy Camp, Director

 

 

 

 

DATE: June 1, 2010

 

44



Table of Contents

 

EXHIBITS.

 

Exhibit No.

 

Document Description

3(i)(a)

 

Articles of Incorporation of the Company dated May 9, 1969 filed as Exhibit A (1) to the Company’s Form 10 and incorporated herein by reference.

 

 

 

3(i)(b)

 

Amendment to Articles of Incorporation of the Company dated October 22, 1982 filed as Exhibit 3. (I)(B) to the Company’s Form 10-KSB for the period ending February 28, 2005 and incorporated herein by reference.

 

 

 

3(ii)

 

By-Laws of the Company dated May 23, 1975 filed as Exhibit A (4) to Form 10 and incorporated herein by reference.

 

 

 

14

 

Code of Ethical Conduct of Senior Officers filed as Exhibit 14 to the Company’s Form 10-KSB for the period ending February 28, 2005 and incorporated herein by reference.

 

 

 

23

 

Consent of Independent Petroleum Engineers and Geologists (filed herewith).

 

 

 

31(i)

 

Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

 

 

 

31(ii)

 

Certifications of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

 

 

 

32

 

Certifications of Chief Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

 

 

 

99

 

Stephens Engineering engineering report with respect to the Company’s proved oil and gas reserves (filed herewith).

 

45