UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended September 30, 2011
[ ] 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 000-53311
JAYHAWK ENERGY, INC.
(Exact name of small business issuer as specified in its charter)
COLORADO | 20-0990109 |
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) |
811 E. Sherman Avenue Coeur d'Alene, Idaho (Address of principal executive office) | 83814 (Postal Code) |
(208) 667-1328 (Issuer's telephone number) | |
SECURITIES REGISTERED UNDER SECTION 12(b) OF THE ACT:
None
SECURITIES REGISTERED UNDER SECTION 12(g) OF THE ACT:
Common Stock, $0.001 par value
Indicate by check mark if the registrant is a well-known seasoned issued, as defined in Rule 405 of the Securities Act: Yes[ ]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 Act:Yes[ X] No []
Indicate by check mark whether the issuer (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 [ ]
Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate Website, 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 filed). Yes [X ] No [ ] (Not required)
Indicate by checkmark 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 the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of III of this Form 10-K or any amendment to the Form 10-K. [x]
Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “Accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one):
Large Accelerated Filer [ ]
Accelerated Filer [ ]
Non-Accelerated Filer [ ]
Smaller Reporting Company[x]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [x]
The aggregate market value of the Common Stock held by non-affiliates (as affiliates are defined in Rule 12b-2 of the Exchange Act) of the registrant, computed by reference to the average of the high and low sale price onOctober 31, 2010 was$8,871,001.
As ofFebruary 6, 2012 there were 59,381,895 shares of issuer’s common stock outstanding.
Oil and Gas Properties
S.E. Kansas - Girard Properties - Adjacent to the Uniontown Project is the Girard Project in Crawford County Kansas which the Company acquired on March 31, 2008. With this transaction JayHawk acquired 34 wells, of which 7 were tied into a pipeline also acquired at this time (more fully described immediately following). This acquisition provided JayHawk infrastructure necessary for future development of existing and acquired leased acreage, and during July and August of 2008, the Company completed drilling and casing an additional 20 gas wells. JayHawk Energy's acreage position in both Bourbon and Crawford counties Kansas was enhanced again with the acquisition from Missouri Gas Partners of certain oil, gas and mineral rights to 11,462 leased acres in June of 2008. As of September 30, 2011, the Company has 20 producing gas wells tied into the pipeline. Since June of 2008 through September of 2011, the Company's gas production and sales has contributed $302,542 in net revenues. This is more fully discussed in Note 5 to the Consolidated Financial Statements of this Form 10-K.
JayHawk Gas Transportation Company -Associated with the acquisition of the Girard properties in March of 2008, the Company acquired a 16 mile pipeline. In May of 2008, the Company established a 100% owned and controlled subsidiary, "JayHawk Gas Transportation Corporation" to hold and manage the assets associated with the pipeline. This pipeline is tied into a 2 million cubic foot sales pipeline and allows for substantial growth.
S.E. Kansas - Uniontown Properties– Located in S.E. Kansas, these properties consisted of the leased acreage and wells within the leased area drilled by previous operators. Further evaluation by management during the year ended September 30, 2011 indicated the capital required to develop the Uniontown Project exceeded the Company's ability to fund the project and any capital raised would be better served being deployed on other opportunities. Thus, the remainder of the leases expired without renewal and the Company recognized an additional abandonment loss of $1,020,479 on the Uniontown project for the year ended September 30, 2011.
North Dakota - Crosby (formerly Candak) Project – On January 16, 2008, the Company acquired a 65% working interest in five producing oil wells, historically referred to as the Candak properties but currently referred to as the Crosby properties more properly reflecting the pool designation of the properties, located in the Williston Basin area of North Dakota. In addition to the five producing wells, the Company acquired certain oil, gas, and mineral rights in a 15,500-acre land position. The Crosby properties provide production of approximately 50 barrels ("Bbls") of light to medium crude oil daily from the five existing wells. Since their acquisition and through September 30, 2011 these five wells have produced and sold in excess of 69,000 Bbls. and generated net revenues to JayHawk of$2,533,535.
During the year ending September 30, 2010, JayHawk drilled two vertical wells on the Crosby property in order to develop the Mississippian reservoir further within the pool. The wells exhibited marginal production potential after attempts to stimulate flow and are currently shut-in. One of these wells will be converted to water disposal in order to reduce operating expense. The second well is being considered for horizontal drilling to test the potential for Bakken reservoir production on the land in which the Company has acquired drilling rights in the Bakken formation. JayHawk, in its acquisition of leases during 2010, acquired Bakken rights along with the Mississippian rights in section 28-164N-97W at the Crosby property. Activity in the Bakken has been moving northward from the well developed Bakken fields in Mountrail and McKenzie Counties to the south. Recent drilling by other companies into the Bakken shale formation and the underlying Three Forks shale have yielded promising production results within 10 miles of the Crosby pool. The Company is also looking at strategies to redeploy redundant production equipment on the property in order to streamline the production system and to increase overall efficiency.
Reserves -For the North Dakota properties, the independent petroleum engineering firm of McDaniel & Associates Consultants, Ltd. of Calgary, Alberta Canada, prepared the estimates of the Company's proved developed and proved undeveloped reserves as of September 30, 2010 and 2011. The future net cash flows (and related present value) attributable proved and probable reserves were calculated for each well and the properties in total as of these respective dates. Proved developed reserves are defined as estimated quantities of oil, natural gas and natural gas liquids which upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions. Proved undeveloped reserves are those reserves which can be expected to be recovered from new wells with existing equipment and operating methods.
Summary Estimated quantities of oil proved reserves for the North Dakota, Crosby properties for the years end September 30, 2011 and 2010 are presented below:
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| 2011 |
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| 2010 | ||||||||||
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| Oil (Bbls) |
| In Barrels |
| Oil (Bbls) | |||||
PROVED |
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| ||||||||
Developed – North Dakota |
|
|
| 55,400 |
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| 53,400 | ||||||||
Undeveloped – North Dakota |
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|
| 26.000 |
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| ||||||||
| TOTAL PROVED RESERVES |
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|
| 81,400 |
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|
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| 79,400 |
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(1) Before tax cash flow NPV after royalty deductions (10% discount)
The Kansas properties identified above as the Girard and Uniontown projects have not been evaluated and no independent estimates of proved reserves have yet been made. Additional information about the Company’s proved oil and gas reserves are presented under Note 22 - Supplemental Oil and Gas Information in the accompanying Consolidated Financial Statements.
NOTE 22 - SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)
In January 2010, the FASB issued an ASU to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules discussed in Note 1. The significant revisions involved revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves the period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves at December 31, 2009. The new guidelines have expanded the definition of proved undeveloped reserves that can be recorded from an economic producer did not impact or prove undeveloped reserves.
The Company follows the guidelines prescribed in ASC 932 for computing a standardized measure of future cash net cash flows and changes therein relating to estimated proved reserves. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality and basis differentials to the year-end estimated quantities of oil and gas to be produced in the future. The resulting net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and gas reserves in place at the end of the period using year-end costs and assuming continuation of existing conditions, plus Company overhead incurred. Future development costs are determined based on estimates of capital expenditures to be incurred in developing proved oil and gas reserves.
The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. The assumptions do not necessarily reflect the Company's expectations of actual revenues to be derived from these reserves, no their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimate of new discoveries and undeveloped locations are more imprecise than estimates of establishing proved producing oil and gas properties. Users of this information should be aware that the process of estimating quantities of “proved” and “proved-developed” oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various resevoirs make these estimates generally less precise than other estimates included in the financial statements disclosures.
Proved oil reserve quantities at September 30, 2011 and 2010, and the related future net cash flows are based on the estimates prepared by independent petroleum engineers. The following reserve quantity and future net cash flow information for 2011 and 2010 was prepared by McDaniel & Associates Consultants, Ltd and are consistent with internal estimates. The Company provided McDaniel & Associates with engineering, geological and geophysical data, actual production histories and other information necessary for the reserve determination. The reserve estimates were prepared based on economic and operating conditions existing at September 30, 2011 and 2010.
All of the Company's oil and gas reserves are within the continental United States in the states of North Dakota and Kansas. Based on the evaluation described in the preceding paragraph, presented below (in barrels) is a summary of changes to the Company's net interest in proved developed and proved undeveloped reserves for the years ending September 30, 2011 and 2010:
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| Crude Oil (Net Bbls) |
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| September 30, 2009 |
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| 148,900 |
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| |
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| Revisions of previous estimates |
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| (50,200) |
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| Purchase of minerals in place |
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| - |
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| Production |
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| (19,300) |
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| September 30, 2010 |
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| 79,400 |
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| Revisions of previous estimates |
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| 2,700 |
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| Purchase of minerals in place |
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| 8,400 |
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| Production |
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| (9,100) |
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| September 30, 2011 |
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| 81,400 |
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Oil reserves
Based on the evaluation described in the preceding paragraph, presented below (in barrels) is a summary of changes to the Company’s net interest in proved undeveloped and proved developed producing and non-producing reserves for the years ending September 30, 2011 and 2010:
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| 2011 |
| 2010 | ||||
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| Oil (Bbls) |
| Oil (Bbls) | |||
| Proved developed producing |
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| Proved developed non-producing |
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| - | ||||
| Proved undeveloped reserves |
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| 26,000 |
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| Total proved reserves |
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| 81 |
| 89,400 | |||
The reserves in this report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.
Capitalized Costs Relating to Oil and Gas Producing Activities
Evaluated and unevaluated capitalized costs related to the Company's oil and natural gas producing activities are summarized as follow in $ thousands:
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| Year Ended September 30, | |||
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| 2011 |
| 2010 | |
| Unproved properties | $ | 3,976 | $ | 4,294 | ||
| Proved properties |
| 2,358 |
| 2,358 | ||
| Wells and equipment |
| 5,501 |
| 7,128 | ||
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| Total capitalized costs | $ | 11,835 | $ | 13,780 | |
| Less: Allowance for depreciation, depletion, amortization and lease impairment |
| (6,954) |
| (4,749) | ||
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| TOTAL | $ | 4,881 | $ | 9,031 | |
The Company will continue to evaluate its unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined.
Costs Incurred in Oil and Gas Producing Activities (in $ thousands)
Costs incurred in oil and natural gas property acquisitions, exploration and development are summarized as follows, in $ thousands:
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| Year Ended September 30, | ||
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| 2011 |
| 2010 |
| Property acquisitions |
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| Unproved properties | $ | 47 | $ | 148 |
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| Proved properties (includes wells, equipment and related facilities acquired with proved reserves) |
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| 1,954 |
| Exploration |
| - |
| - | |
| Production and development capital expenditures |
| - |
| - | |
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| TOTAL | $ | 47 | $ | 2,102 |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves
The following Standardized Measure of Discounted Future Net Cash Flow information has been developed utilizing ASC 932, Extractive Activities – Oil and Gas (ASC 932) procedures and based on estimated oil reserve and production volumes. It can be used for some comparisons, but should not be the only method used to evaluate the Company or the Company performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the Company’s current value.
The Company believes that the following factors should be taken into account when reviewing the following information:
·
future costs and selling prices will probably differ from those required to be used in these calculations;
·
due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;
·
a 10% discount rate may not be reasonable as a measure of the relative risk in realizing future net oil reserves; and
·
future net revenues may be subject to different rates of income taxation.
The Standardized Measure of discounted future net cash flows relating to the Company's ownership interests in proved developed oil reserves for the years ended December 31, 2011 and 2010 are as follows:
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| 2011 |
| 2010 |
| Future cash flows | $ | 3,079,000 | $ | 5,125,800 | |
| Future oil and natural gas operation expenses |
| (830,000) |
| (1,276,000) | |
| Future abandonment costs |
| (128,000) |
| (203,800) | |
| Future severance tax |
| (154,000) |
| (366,600) | |
| Future income tax expense |
| - |
| - | |
| Future net cash flows |
| 1,967,000 |
| 2,251,600 | |
| Less: 10% annual discount for estimating timing of cash flow |
| (512,000) |
| (711,400) | |
|
| Standardized measure of discounted future net cash flow | $ | 1,455,000 | $ | 1,540,200 |
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves
The following is a summary of the changes in Standardized Measure of discounted future net cash flows for the Company’s proved oil reserves during each of the years in the two year period ended September 30, 2011:
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| 2011 |
| 2010 | ||
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| Standardized measure of discounted future net cash flows at beginning of year | $ | 1,540,200 | $ | 3,004,200 | ||
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| Net changes in prices and production costs |
| 259,496 |
| 2,602,109 | ||
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| Sales of oil produced, net of production costs |
| (184,525) |
| (326,143) | ||
| Revisions of previous quantity estimates |
| 85,509 |
| (2,690,700) |
| ||
| Development costs incurred |
| (20,100) |
| (326,650) | |||
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| Change in income taxes |
| - |
| - | ||
| Accretion of discount |
| 15,493 |
| 14,084 | |||
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| Standardized measure of discounted future net cash flows at year end | $ | 1,455,000 | $ | 1,540,200 | ||
