UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
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(Mark One)
ü | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE |
| ACT OF 1934 |
For the fiscal year ended: April 30, 2010 | |
OR | |
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| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE |
| ACT OF 1934 |
For the transition period from: _____________ to _____________ | |
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MILLER PETROLEUM, INC.
(Exact name of registrant as specified in its charter)
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Tennessee | 001-34732 | 62-1028629 |
(State or Other Jurisdiction | (Commission | (I.R.S. Employer |
of Incorporation or Organization) | File Number) | Identification No.) |
3651 Baker Highway, Huntsville, TN 37756
(Address of Principal Executive Office) (Zip Code)
(423) 663-9457
(Registrant’s telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act: | ||
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Title of each class |
| Name of each exchange on which registered |
Common Stock, par value $0.0001 per share |
| NASDAQ Global Market |
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Securities registered pursuant to Section 12(g) of the Act: | ||
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None | ||
| (Title of Class) |
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. | ||||
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| Yes | ü | No |
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Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. | ||||
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| Yes | ü | No |
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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the | ||||
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. | ü | Yes |
| No |
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Indicate by check mark 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 (§229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). | ||||
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| Yes |
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this | ||||||||
information statements incorporated by reference in Part III of this Form 10-K or any amendment to this | ||||||||
Form 10-K. | ü |
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. | ||||||||
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Large accelerated filer |
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| Accelerated filer |
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Non-accelerated filer |
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| Smaller reporting company | ü |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). |
| Yes | ü | No | ||||
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The aggregate market value of the outstanding common stock, other than shares held by persons who may be deemed affiliates of the registrant, computed by reference to the closing sales price for the registrant’s common stock on October 30, 2009 (the last business day of the registrant’s most recently completed second quarter), as reported on the OTC Bulletin Board, was approximately $6,200,000. As of July 22, 2010, there were 33,389,383 shares of common stock of the registrant outstanding. | ||||||||
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DOCUMENTS INCORPORATED BY REFERENCE | ||||||||
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List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly described for identification purposes (e.g., annual report to security holders for fiscal year ended December 24, 1980). None. | ||||||||
MILLER PETROLEUM, INC.
TABLE OF CONTENTS
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
Various statements in this annual report contain or may contain forward-looking statements that are subject to known and unknown risks, uncertainties, and other factors which may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These forward-looking statements were based on various factors and were derived from utilizing numerous assumptions and other factors that could cause our actual results to differ materially from those in the forward-looking statements. These factors include, but are not limited to the following:
·
the capital intensive nature of oil and gas development and exploration operations and our ability to raise adequate capital to fully develop our operations and assets,
·
our ability to perform under the terms of the Assignment Oversight Agreement with the Alaska DNR, including meeting the funding commitments of that agreement,
·
fluctuating oil and gas prices and the impact on our results of operations,
·
our ability to secure an extension of the Susitna Basin Exploration License,
·
the impact of the global economic crisis on our business,
·
the impact of natural disasters on our Cook Inlet Basin operations,
·
the imprecise nature of our reserve estimates,
·
our ability to recover proved undeveloped reserves and convert probable and possible reserves to proved reserves,
·
the possibility that present value of future net cash flows will not be the same as the market value,
·
the costs and impact associated federal and state regulations,
·
changes in existing federal and state regulations,
·
our dependence on third party transportation facilities,
·
insufficient insurance coverage,
·
conflicts of interest related to our dealings with MEI,
·
cashless exercise provisions of outstanding warrants,
·
market overhang related to restricted securities and outstanding options, warrants and convertible notes,
·
adverse impacts on the market price of our common stock from sales by the selling security holders.
Most of these factors are difficult to predict accurately and are generally beyond our control. You should consider the areas of risk described in connection with any forward-looking statements that may be made herein. Readers are cautioned not to place undue reliance on these forward-looking statements, and readers should carefully review this annual report in its entirety, including the risks described in Item 1A. Risk Factors. Except for our ongoing obligations to disclose material information under the Federal securities laws, we undertake no obligation to release publicly any revisions to any forward-looking statements, to report events or to report the occurrence of unanticipated events. These forward-looking statements speak only as of the date of this annual report, and you should not rely on these statements without also considering the risks and uncertainties associated with these statements and our business.
OTHER PERTINENT INFORMATION
We maintain our web site at www. millerenergyresources.com. Information on this web site is not a part of this prospectus.
Unless specifically set forth to the contrary, when used in this prospectus the terms “Miller," "we", "us", "our", and similar terms refer to Miller Petroleum, Inc., a Tennessee corporation doing business as Miller Energy Resources, and its subsidiaries.
PART I
ITEM 1.
BUSINESS.
Overview
We are an independent exploration and production company that utilizes seismic data and other technologies for geophysical exploration and development of oil and gas wells in the Appalachian region of eastern Tennessee and the Cook Inlet Basin in south central Alaska. In addition to our engineering and geological capabilities, we provide land drilling services on a contract basis to customers primarily engaged in natural gas exploration and production.
During 2010, we have significantly expanded our operations through the December 2009 acquisition of oil and gas assets from Pacific Energy Resources through a bankruptcy proceeding in which we acquired onshore and offshore production and processing facilities, the Osprey offshore energy platform, over 600,000 net lease acres of land with hundreds of miles of 2-D and 3-D geologic seismic data, miscellaneous roads, pads and facilities. Our current strategy focuses the majority of our efforts on growing our company, including the following:
·
increasing our overall oil and gas production through maintenance and repairs of nonperforming or underperforming wells located in Alaska,
·
organically growing production through drilling for our own benefit on existing leases and acreage in the exploration license with a view towards retaining the majority of working interest in the new wells, and
·
expanding our contract drilling and service capabilities and revenues, including drilling contracts with third parties.
Our exploration and production activities
Historically, we focused our exploration, development, and production efforts in the Appalachian region of eastern Tennessee. During 2010 we significantly increased our operations through the acquisitions of KTO and ETC in our Appalachian region and the assets in Alaska, which comprise our Cook Inlet operations. As of April 30, 2010, we had approximately 662,992 acres of gross oil and gas leases and exploration license rights (616,550 net acres), which includes 471,474 acres under the Susitna Basin Exploration License.
Cook Inlet Basin
We own approximately 131,190 gross acres of leasehold interests, the exploration license rights to an additional 471,474 acres and 10 crude oil and five natural gas wells in which we own an interest. Cook Inlet stretches 180 miles from the Gulf of Alaska to Anchorage in south-central Alaska. The Cook Inlet Basin contains large oil and gas deposits including several offshore fields. There are also numerous oil and gas pipelines running around and under the Cook Inlet.
At the time the Alaskan assets were acquired by us, all of the operated wells were shut-in, a term used in the oil and gas industry which means the wells were closed off so that they could not produce oil, with the exception of the WF-2 natural gas well. As of June 30, 2010, four of the oil wells had been returned to production. In addition, Cook Inlet Energy owns a 30% working interest in two gas wells operated by Aurora Gas, Three Mile Creek 1 and Three Mile Creek 2, which have been operated continuously.
Oil wells drilled in this area range from 9,000 vertical feet to 10,000 vertical feet in depth while gas wells have a vertical depth of 8,000 feet to 9,000 feet. Wells that are deviated (continue on from the vertical depth either diagonally or horizontally) will have a longer measured depth of approximately 5,000 feet giving total measured depth of 14,000 feet to 15,000 feet. Well spacing is quite variable, as there are large parts of Cook Inlet which are completely undeveloped, and others, that are more mature. Our fields have approximately 60 to 80 acre spacing. The Cook Inlet basin contains a thick section of terrestrial Tertiary rocks which includes shales, sandstones, and coals. The primary targets in the area are crude oil reserves.
In January 2010 we entered into a Master Services Agreement with Fairweather E&P Services, Inc., a company based in Anchorage, Alaska which provides a wide range of support services for the oil and gas industries, whereby it acts as an independent contractor for us in the development and/or refurbishment of the wells in Cook Inlet Basin. The agreement it provides us with engineering, logistics, field and project management support for the
1
well and facility work in Cook Inlet Basin which are anticipated to be completed on or before December 31, 2012. We pay the contractor for all costs associated with these services, including any services that Fairweather E&P may subcontract to third party providers, at its cost plus 15%. Fairweather E&P is required to maintain certain minimum levels of insurance coverage and the agreement contains customary cross-indemnification provisions. We may terminate the agreement at any time without reason.
Susitna Basin Exploration License
Included in the Alaskan assets we acquired is a 100% interest in an Exploration License granted by the State of Alaska in October 2005 covering approximately 471,474 acres in the Susitna basin area north of Anchorage, Alaska. Under the terms of the Exploration License, the licensee was granted a five year exclusive license to explore for oil and gas on the specified lands, and upon fulfillment of the work commitment, the license for all or any part of the land could be converted into oil and gas leases. The original work commitment of approximately $3.5 million was fulfilled, and we have the right at any time to covert the license for all or any portion of the acreage into oil and gas leases at any time. Once the exploration license is converted into oil and gas leases, we are required to pay a per acre fee to the state and commence drilling operations within specified timeframes. In an effort to control the timing of the development of this acreage, in April 2010 we requested a three year extension of the exploration license for a work commitment of $750,000. While we reasonably believe the state will grant our request for extension, there are no assurances we are correct, or that if granted, that the terms and conditions of the extension will be satisfactory to us. If we are unable to negotiate an extension, it is likely we will convert the license for only a portion of the land into oil and gas leases.
Osprey Platform
Included in the assets acquired from Pacific Energy was the Osprey platform which is located in the Redoubt Unit approximately 1.8 miles southeast of the West Foreland in central Cook Inlet at a water depth of approximately 45 feet. The Osprey platform, which produces from the Redoubt Unit is connected to our Kustatan Production Facility by two eight-inch and one six-inch pipeline and one power cable. It relies on our Kustatan Production Facility, which is currently inactive, and our West McArthur River Unit Production Facility to provide all of its electricity and gas, and the Kustatan Production Facility to process all of Osprey's produced fluids. The platform has 21 slots, eight of which are currently used, and an attached 40 man camp. The platform is currently inactive.
The Osprey platform was placed on site during June 2000 and it initially conducted exploration drilling operations between January 2001 and July 2002. Eight wells were drilled, which in their present configuration consist of one water flood well, one Class I injection well, and six oil wells. The oil wells were equipped with electrical submersible pumps which were necessary to bring the oil to surface. In 2005, the third-party drilling rig was removed from the platform after a contract dispute. The removal of the rig crippled the ability to maintain and repair the platform’s wells or to expand production. Shortly afterwards, a series of mechanical problems took much of the platform’s production offline and these problems could not be corrected without a rig present. Reduced production was temporarily restored by deploying jet pumps, which can provide artificial lift, but do not require a rig; however, production continued to fall, and the Osprey platform was shut-in in the spring of 2009.
In order to restore production from the Redoubt Unit, it will be necessary to mobilize a drilling rig to the Osprey platform and repair six wells. We believe that past experience suggests that a rig should be permanently located on the platform. Two of these wells require only the replacement of the electrical submersible pumps, and the other four wells require re-drilling in sections. We estimated that the total cost of restoring production, including the purchase of a drill rig, is approximately $35 million.
Assignment Oversight Agreement
On November 5, 2009, Cook Inlet Energy, LLC entered into an Assignment Oversight Agreement with the Alaska DNR which set out certain terms under which the Alaska DNR would approve the assignment of certain specified state oil and gas leases from Pacific Energy Resources to Cook Inlet Energy. This agreement remains in place following our acquisition of Cook Inlet Energy in December 2009. Generally, the agreement requires Cook Inlet Energy to provide the Alaska DNR with additional information and oversight authority to ensure that Cook Inlet Energy is acting diligently to develop the oil and gas from Redoubt Shoal, West McArthur River Field and West Foreland Field. Under the terms of the agreement, until the Alaska DNR determines, in its sole discretion, that Cook Inlet Energy has completed its development and operation obligations under the assigned leases, Cook Inlet Energy agreed to the following:
·
file a monthly summary of expenditures by oil and gas filed, tied to objectives in Cook Inlet Energy’s business plan and plan of development previously presented to the Alaska DNR,
2
·
meet monthly with the Alaska DNR to provide an update on operations and progress towards meeting these objectives,
·
notify the Alaska DNR 10 days prior to commitment when Cook Inlet Energy is preparing to spend funds on a purchase, project or item of more than $100,000 during the first 12 months, more than $1 million during the second 12 months and more than $5 million thereafter, and
·
submit a new plan of development and plan of operations for the Alaska DNR’s approval on or before December 15, 2009 and submit a plan of development annually thereafter on or before February 1, 2010. Cook Inlet Energy timely met both of these deadlines.
The agreement required Cook Inlet Energy to obtain financing in the minimum amount of $5,150,000 to provide funds to be used for expenditures approved by the Alaska DNR as part of Cook Inlet Energy’s plan of development. The funds are to be used for workover and repair of the wells, repair of the physical infrastructure, construction of a grind and inject plant at the West McArthur River facility, normal operating expenses associated with the leases and infrastructure and other capital project which are to be pre-approved by the Alaska DNR. The agreement also required Cook Inlet Energy to demonstrate funding commitments to support restoration of the base production at the Redoubt Unit, including bringing a number of the shut-in wells back on line, which was estimated at $31 million in the agreement but which we have internally increased to $35 million to accommodate the purchase of a drilling right. These funding commitments necessary under the agreement were provided to us under the terms of the Vulcan Capital Corporation, LLC letter agreement described earlier in this annual report. We have subsequently provided these funds through for the West McArthur River facility using a portion of the proceeds of our capital raising efforts described elsewhere herein, and intend to seek alternative sources of funding for the balance of the necessary capital.
Cook Inlet Energy is prohibited from using any of the approximate $36.15 million or any proceeds from the operations under the assigned leases of the funding commitments for non-core oil and gas activities under the assigned leases, or any activities outside the assigned leases, without the prior written approval of the Alaska DNR until the parties mutually agree that the full dismantlement obligation under the assigned leases is funded. The assigned leases will be subject to default and termination should Cook Inlet Energy fail to submit the information required under the agreement and expenditure of funds for items or activities do not support core oil and gas activities, as reasonably determined by the Alaska DNR.
Recent Developments
Cook Inlet Energy, LLC was one of nine successful bidders in State of Alaska’s Division of Oil & Gas Cook Inlet Areawide 2010 Competitive Oil and Gas Lease Sale. There were 38 bids for 36 tracts covering an estimated 144,640 acres of State of Alaska oil and gas acreage. Cook Inlet Energy bid on seven tracts and was the successful high bidder on each of those tracts which cover an estimated 27,520 acres. Cook Inlet Energy’s winning bid for these seven tracts was $908,800. Cook Inlet Energy paid a deposit of $181,767 at the time of the auction and the balance will be due once the title work is complete which we presently anticipate to be in January 2012. All of Cook Inlet Energy’s bids completed acreage positions covering prospects acquired in its purchase of a portfolio of Pacific Energy Alaska assets late last year.
Membership in Cook Inlet Spill Prevention and Response, Inc.
Cook Inlet Energy is a Class G member of the Cook Inlet Spill Prevention and Response, Inc., which we refer to as CISPRI. CISPRI is a non-profit corporation formed in 1990 to provide oil spill prevention and response capabilities in Cook Inlet. CISPRI has been designated as a Class "E" Oil Spill Removal Organization by the U.S. Coast Guard, which is the highest level of designation based on spill containment and removal equipment requirements for offshore/ocean response. CISPRI's response zone includes the entire Cook Inlet Region, stretching from Palmer to the Barren Islands and out into the Gulf of Alaska. At each annual meeting of CISPRI members adopt a budget for the coming year which includes funds for day to day operational activities of CISPRI, investments in capital equipment and materials to be used in connection with the cleanup activities and research and development and training. The budget is funded though payment of dues by the members and the amount of dues is calculated in accordance with a participation formula. Class G members pay an annual fee of $10,000 together with additional fees based upon the amount of oil we transport.
3
If a spill is identified as originating from facilities owned or operations conducted by one or more of the members, CISPRI will act to control and clean up the spill of crude oil/synthetic crude oil or refined petroleum products arising from those operations without any future action by the members. Any member that utilizes or receives the benefit of these activities must reimburse CISPRI for all expenses of control and clean up, including costs of equipment, materials and personnel. Each member is required to execute a response action contract providing terms and conditions under which response and cleanup activities will be undertaken. Cook Inlet Energy is a party to such an agreement which, in part, requires Cook Inlet Energy to maintain worker’s compensation insurance, employers’ liability insurance, comprehensive general and automotive liability insurance covering injury or death or persons and property damage of at least $10 million. Cook Inlet Energy is in compliance with this insurance requirement. All members accept responsibility for spills which result from their operations or facilities and have indemnified CISPRI and all other members for all liabilities arising for a spill. This indemnification is not limited by the amount of insurance coverage.
Cook Inlet Energy may resign its membership in CISPRI upon 30 days written notice. At the effective date of the resignation, Cook Inlet Energy is obligated to pay all unpaid dues and assessments levied prior to the notice of resignation. Cook Inlet Energy’s membership may be terminated by the Board of Directors of CISPRI upon 60 days notice if its determined Cook Inlet Energy is no longer eligible for membership. Cook Inlet Energy would not be entitled to a refund of any monies paid to CISPRI.
Appalachian Region
We own approximately 54,506 gross acres of leasehold interests with 185 producing oil wells and 334 producing gas wells in which we own an interest. Wells drilled in this area range from 1,800 to 4,200 feet in depth and the well spacing is generally from 20 to 40 acres per well and are predominately in Fort Payne formation.
The following table provides information on our reserves at April 30, 2010.
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| Net Reserves at April 30, |
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| 2010 |
| 2009 |
| 2008 |
| ||||||
Reserves category |
| Oil |
| Natural Gas |
| Oil |
| Natural Gas |
| Oil |
| Natural Gas |
|
PROVED |
|
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Developed – producing |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
| 1,695 |
| 1,085 |
| — |
| — |
| — |
| — |
|
Appalachian region |
| 108 |
| 619 |
| 43 |
| 563 |
| 63 |
| 511 |
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Developed - non producing |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
| 856 |
| — |
| — |
| — |
| — |
| — |
|
Appalachian region |
| 6 |
| 33 |
| 10 |
| 30 |
| 11 |
| 1,341 |
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Undeveloped |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
| 7,679 |
| 3,722 |
| — |
| — |
| — |
| — |
|
Appalachian region |
| — |
| — |
| — |
| 1,271 |
| — |
| — |
|
Total Proved |
| 10,344 |
| 5,459 |
| 53 |
| 1,864 |
| 74 |
| 1,852 |
|
|
|
|
|
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|
|
|
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|
PROBABLE |
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|
|
|
|
|
|
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Non-producing |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
| — |
| 5,567 |
| — |
| — |
| — |
| — |
|
Appalachian region |
| — |
| — |
| — |
| — |
| — |
| — |
|
Undeveloped |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
| 6,173 |
| — |
| — |
| — |
| — |
| — |
|
Appalachian region |
| — |
| 3,695 |
| — |
| — |
| — |
| — |
|
Total Probable |
| 6,173 |
| 9,262 |
| — |
| — |
| — |
| — |
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|
|
|
|
|
POSSIBLE |
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|
|
|
|
|
|
Undeveloped |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
| 1,078 |
| 5,203 |
| — |
| — |
| — |
| — |
|
Appalachian region |
| 39 |
| — |
| — |
| — |
| — |
| — |
|
Total Possible |
| 1,117 |
| 5,203 |
| — |
| — |
| — |
| — |
|
4
When used in this table, MBbls means million barrels of oil and MMcf means million metric cubic feet. We also use a number of terms when describing our reserves. “Proved reserves” are the quantities of oil and gas that, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible. We provide information on two types of proved reserves - developed and undeveloped. “Proved developed reserves” are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and “proved undeveloped reserves” are reasonably certain reserves in drilling units immediately adjacent to the drilling unit containing a producing well as well as areas beyond one offsetting drilling unit from a producing well.
Under recent SEC rules we are now also permitted to provide information about probable and possible reserves. As set forth above, prior to 2010 our reserve reports did not contain any estimates on probable or possible reserves. “Probable reserves” are additional reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. “Possible reserves” are additional reserves that are less certain to be recovered than probable reserves. The various reserve categories have different risks associated with them. Proved reserves are more likely to be produced than probable reserves and probable reserves are more likely to be produced than possible reserves. Because of these risks, the different reserve categories should not be considered to be directly additive.
Our reserve estimates for oil and natural gas at April 30, 2010 for our Cook Inlet assets were prepared by Ralph E. Davis Associates, Inc., an independent engineering firm, and our reserve estimates for oil and gas at April 30, 2010 for our Appalachian region assets were prepared by Lee Keeling and Associates, Inc., an independent engineering firm. Both of these reserve reports which are filed as exhibits to this annual report, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles and most recent definitions and guidelines established by the SEC. All reserve definitions comply with the applicable definitions of the rules of the SEC. The reserves were estimated using engineering and geological methods widely accepted in our industry. The accuracy of the reserve estimates is dependent upon the quality of available data and upon independent geological and engineering interpretation of that data. For proved developed producing, the estimates considered to be definitive, using performance methods that utilize extrapolations of various historical data including oil, gas and water production and pressure history. For other than proved producing, proved undeveloped reserves and probable and possible reserve estimates were made using volumetric methods.
Our policies regarding internal controls over reserve estimates require reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent engineering firm under the supervision of our Chief Financial Officer. We provide the engineering firm with estimate preparation material such as property interests, production, current operation costs, current production prices and other information. This information is reviewed by our Chief Executive Officer and our Chief Financial Officer to ensure accuracy and completeness of the data prior to submission to our third party engineering firm. A letter which identifies the professional qualifications of each of the independent engineering firms who prepared the reserve reports are included in those reserve reports which are filed as exhibits to this annual report. There was no conversion of undeveloped reserves to proved reserves during the fiscal year ended April 30, 2010.
5
Each of the engineering reports also projected future net income (FNI) from our net reserves and the present value, discounted at 10% per annum, of that future net income FNI @ 10% as summarized in the following table. Future net income is based upon gross income from future production, less direct operating expenses and taxes. Estimated future capital for development costs was also deducted from gross income at the time it will be expended. No allowance was made for depletion, depreciation, income taxes or administrative expense. In the following table, the price per barrel of oil was $73.01 and the price per MMcf of natural gas was $4.84 for the Cook Inlet reserves and $71.85 per barrel of oil and $5.15 per MMcf of natural gas for the Appalachian region reserves. In each instance these prices are computed in accordance with the SEC’s rule and represent the average fiscal year prices.
|
| Producing |
| Non-Producing |
| Undeveloped |
| Expenses |
| Total |
| |||||
Proved - Cook Inlet |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FNI |
| $ | 108,169,312 |
| $ | 45,505,746 |
| $ | 422,335,438 |
| $ | (94,233,000 | ) | $ | 481,777,496 |
|
FNI @ 10% |
| $ | 75,596,359 |
| $ | 26,222,301 |
| $ | 267,256,594 |
| $ | (57,103,397 | ) | $ | 311,971,859 |
|
Probable - Cook Inlet |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FNI |
|
| — |
| $ | 24,160,285 |
| $ | 313,927,312 |
|
| — |
| $ | 338,087,597 |
|
FNI @ 10% |
|
| — |
| $ | 17,047,756 |
| $ | 174,810,344 |
|
| — |
| $ | 191,858,100 |
|
Possible - Cook Inlet |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FNI |
|
| — |
|
| — |
| $ | 71,892,688 |
|
| — |
| $ | 71,892,688 |
|
FNI @ 10% |
|
| — |
|
| — |
| $ | 39,039,215 |
|
| — |
| $ | 39,039,215 |
|
Proved - Appalachian region |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FNI |
| $ | 6,700,649 |
| $ | 507,591 |
|
| — |
|
| — |
| $ | 7,208,240 |
|
FNI @ 10% |
| $ | 3,483,407 |
| $ | 223,913 |
|
| — |
|
| — |
| $ | 3,707,320 |
|
Probable - Appalachian region |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FNI |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
FNI @ 10% |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Possible - Appalachian region |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FNI |
|
| — |
|
| — |
| $ | 1,513,434 |
|
| — |
| $ | 1,513,434 |
|
FNI @ 10% |
|
| — |
|
| — |
| $ | 1,059,364 |
|
| — |
| $ | 1,059,364 |
|
At April 30, 2010 our standardized measure of discounted future net cash flows for proved reserves was $315,679,195. The present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum, (“PV-10”) is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at April 30, 2010. PV-10 may be considered a non-GAAP financial measure under the SEC’s regulations. We believe PV-10 to be an important measure for evaluating the relative significance of our natural gas and oil properties. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. We further believe investors may utilize our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. However, PV-10 is not a substitute for the standardized measure. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our natural gas and oil reserves.
|
| April 30, |
| |
|
|
|
|
|
Net present value of future cash flows, before income taxes for proved reserves |
| $ | 315,679,195 |
|
Future income taxes, discounted at 10% |
|
| 137,320,450 |
|
Standardized measure of discounted future net cash flows |
| $ | 178,358,745 |
|
6
The following table presents our producing wells by operating area at April 30, 2010.
|
| Producing Wells |
| ||||||||||
|
| Gross (a) |
| Net (b) |
| ||||||||
Location |
| Oil |
| Gas |
| Total |
| Oil |
| Gas |
| Total |
|
Cook Inlet |
| 3 |
| 3 |
| 6 |
| 3 |
| 3 |
| 6 |
|
Appalachian region |
| 185 |
| 334 |
| 519 |
| 170 |
| 142 |
| 312 |
|
Total |
| 188 |
| 337 |
| 525 |
| 173 |
| 145 |
| 318 |
|
———————
(a)
The number of gross wells is the total number of wells in which a working interest is owned.
(b)
The number of net wells is the sum of fractional working interests we own in gross wells expressed as whole numbers and fractions thereof.
Our staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. They utilize results from logs, seismic data and other tools to evaluate existing wells and to predict the location of economically attractive new natural gas and oil reserves. To further this process, we have collected and continue to collect logs, core data, production information and other raw data available from state and private agencies and other companies and individuals actively drilling in the regions being evaluated. From this information, the geologists develop models of the subsurface structures and formations that are used to predict areas for prospective economic development.
On the basis of these models, we obtain available natural gas and oil leaseholds, farm-outs and other development rights in these prospective areas. In most cases, to secure a lease, we pay a lease bonus and an annual rental payment, converting to a royalty upon initial production. In addition, overriding royalty payments may be granted to third parties in conjunction with the acquisition of drilling rights initially leased by others.
We believe that we hold good and defensible title to our developed properties, in accordance with standards generally accepted in the industry. As is customary in the industry, a preliminary title examination is conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties.
Certain of the properties we own are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The properties may also be subject to additional burdens, liens or encumbrances customary to the industry, including items such as operating agreements, current taxes, development obligations under natural gas and oil leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with the use of the properties.
The following table presents, by operating area, leased acres or acreage subject to the Susitna Basin Exploration License as of April 30, 2010.
|
| Developed Acres |
| Undeveloped Acres |
| Total Acres |
| ||||||
Project |
| Gross |
| Net |
| Gross |
| Net |
| Gross |
| Net |
|
Cook Inlet |
| 34,996 |
| 32,800 |
| 529,825 |
| 523,422 |
| 564,821 |
| 556,222 |
|
Appalachian region |
| 13,680 |
| 9,408 |
| 51,594 |
| 37,916 |
| 65,274 |
| 47,324 |
|
Total acreage |
| 48,676 |
| 42,208 |
| 581,419 |
| 561,338 |
| 630,095 |
| 603,546 |
|
7
The following table presents the net undeveloped acres that we control under fee leases and the Susitna Basin Exploration License and the period the leases and exploration license are scheduled to expire, absent pre-expiration drilling and production which extends the term of the lease(s) or the fulfillment of the exploration license terms which permits us to convert all or any portion of the exploration license into oil and gas leases. The expiration dates of the leases are subject to one year automatic renewals so long as we are producing oil and/or gas on the lease. The term of the Susitna Basin Exploration License expires in October 2010, subject to extension as described earlier in this annual report.
|
| Net Undeveloped Acres |
| ||
Lease/Exploration License |
| Year of Expiration |
| Total Acres |
|
Cook Inlet |
|
|
|
|
|
MHT 9300062 - Olsen Creek |
| 2010 |
| 4,857 |
|
MHT 9300063 - Olsen Creek |
| 2010 |
| 3,906 |
|
ADL 390551 - Stingray |
| 2012 |
| 520 |
|
ADL 390735 - Stingray |
| 2013 |
| 2,047 |
|
ADL 390578 - N Ivan |
| 2012 |
| 5,705 |
|
ADL 390585 - N Alexander |
| 2012 |
| 5,689 |
|
ADL 390571 - Pretty Creek |
| 2012 |
| 1,160 |
|
ADL 390749 - Otter |
| 2013 |
| 2,522 |
|
ADL 390579 - Otter |
| 2012 |
| 5,760 |
|
ADL 390370 - Raptor |
| 2010 |
| 1,280 |
|
ADL 390379 - Raptor |
| 2010 |
| 2,536 |
|
ADL 391108 - Raptor |
| 2014 |
| 1,271 |
|
ADL 17595 - Raptor |
| 1967, Held by Unit |
| 1,235 |
|
ADL 17602 - Sabre |
| 1967, Held by Unit |
| 896 |
|
ADL 18758 - Sabre |
| 1967, Held by Unit |
| 280 |
|
ADL 390078 - Susitna Basin Exploration License |
| 2010 |
| 471,474 |
|
ADL 390555 - Tutna |
| 2012 |
| 1,280 |
|
ADL 390556 - Tutna |
| 2012 |
| 2,522 |
|
ADL 390557 - Tazlina |
| 2012 |
| 2,529 |
|
ADL 390549 - Cherryville |
| 2012 |
| 2,560 |
|
ADL 17594 |
| 1967, Held by Unit |
| 80 |
|
ADL 17597 |
| 1967, Held by Unit |
| 2,280 |
|
ADL 18730 |
| 1967, Held by Unit |
| 480 |
|
ADL 18777 |
| 1967, Held by Unit |
| 553 |
|
Total |
|
|
| 523,422 |
|
Appalachian region |
|
|
|
|
|
Lindsay |
|
|
| 1,535 |
|
Edwards-Fowler, Gann |
|
|
| 81 |
|
Butler et al |
|
|
| 24 |
|
Gunsight |
|
|
| 1,335 |
|
Phillips et al from Gunsight acreage |
|
|
| 901 |
|
KTO acreage and wells |
|
|
| 19,128 |
|
ETC acreage and wells |
|
|
| 3,507 |
|
Baker-Senior lease farm out |
|
|
| 3,220 |
|
Other Undeveloped, net |
|
|
| 8,185 |
|
Total |
|
|
| 37,916 |
|
|
|
|
|
|
|
Total acreage |
|
|
| 561,338 |
|
8
The following table presents our development and exploratory drilling activities during the past three years. There is no correlation between the number of productive wells completed during any period and the aggregate reserves to those wells. Productive wells consist of producing wells capable of commercial production.
|
| Drilling Activities |
| ||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 |
| ||||||||||||
|
| Gross |
| Net |
| Gross |
| Net |
| Gross |
| Net |
| ||||||
Development: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Appalachian region |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 2 |
|
| 1 |
|
Total producing |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 2 |
|
| 1 |
|
Non-Producing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Appalachian region |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total non-producing |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Injection |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Appalachian region |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total injection |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Dry |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Appalachian region |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 1 |
|
| 5 |
|
Total dry |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total development |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 3 |
|
| 6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Appalachian region |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total productive |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Dry |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Appalachian region |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total dry |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Pending determination |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total exploratory |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total drilling activity |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 3 |
|
| 6 |
|
Our current efforts are focused on reworking certain of the wells in Cook Inlet and we do not currently have any ongoing drilling operations in either the Appalachian region or Cook Inlet, other than the workover of the wells in Alaska as described elsewhere herein. Much of the work associated with drilling, completing and connecting wells, including fracturing, logging and pipeline construction is performed by subcontractors, under our direction, specializing in those operations, as is common in the industry. When judged advantageous, we acquire materials and services used in the development process through competitive bidding by approved vendors. We also directly negotiate rates and costs for services and supplies when conditions indicate that such an approach is warranted.
Principal markets and principal customers
The existing markets for natural gas production in south central Alaska are the Tesoro Nikiski Refinery, utility companies, petrochemical manufacturing, the production of liquefied natural gas (LNG) for export to Alaskan or Asian markets, and the production of synthetic crude oil (“syncrude”). Presently, the sole market for our crude oil produced at our Alaskan operations is the Tesoro Nikiski Refinery. Crude oil is shipped by pipeline and tanker vessel to the Tesoro Nikiski refinery, operated by Tesoro Alaska Petroleum Company. The main export pipeline is operated by the Cook Inlet Pipeline Company, which is operated by Chevron Pipelines and tanker vessels operate under contract to Tesoro.
9
As a result of the acquisition of the assets in December 2009, Cook Inlet is a successor to the September 2003 contract with Tesoro Refining and Marketing Company. Under the terms of this agreement, Tesoro has agreed to purchase all of the Alaskan Cook Inlet crude oil available at the Drift River Terminal which is produced from leases on the west side of Cook Inlet for a maximum annual capacity of the lesser of the average proportionate share of the Alaskan Cook Inlet crude oil produced of 40,000 barrels per day. The per barrel pricing is based upon the simple arithmetic average of the published daily New York Mercantile Exchange (NYMEX) settlement prices for light sweet crude oil less certain adjustments and deductions. This pricing may be modified upon the mutual agreement of the parties if the volume falls below 9,000 barrels per day or exceeds 24,000 per day. The initial term of the agreement was to December 31, 2008 and thereafter it has automatically renewed in additional one year terms. The agreement may be terminated by either party upon notice 60 days prior to the automatic renewal. All of our present and planned future oil production is from the west side of Cook Inlet, and would be covered by this contract. Sales to Tesoro Refining and Marking Company under this agreement represented approximately 82% of our total revenue in 2010.
As of July 25, 2010 all natural gas produced by Cook Inlet Energy was used by it to generate heat and power at its production facilities. At such time as gas production exceeds Cook Inlet Energy’s internal needs, it can sell the excess production as all of Cook Inlet Energy’s gas wells are connected to the south central Alaska Railbelt pipeline network through the Cook Inlet Gas Gathering System and/or the Beluga Pipeline, both of which are operated by Marathon Pipelines.
The principal markets for our crude oil and natural gas produced in the Appalachian region are refining companies, utility companies and private industry end users. Crude oil is stored in tanks at the well site until the purchaser retrieves it by tank truck. Direct purchases of our crude oil are made statewide at our well sites by Barrett Oil Purchasing Company. Our natural gas has multiple markets throughout the eastern United States through gas transmission lines. Access to these markets is presently provided by three companies in northeastern Tennessee, including Cumberland Valley Resources, NAMI Resources Company, and Tengasco. Local markets in Tennessee are served by Citizens Gas Utility District and the Powell Clinch Utility District. Natural gas is delivered to the purchaser via gathering lines into the main gas transmission line. Surplus gas is placed in storage facilities or transported to East Tennessee Natural Gas which serves Tennessee and Virginia. In 2010 and 2009, sales to Barrett Oil Purchasing and Sunoco, collectively, represented approximately 9% and approximately 24%, respectively, of our total revenues and sales to Cumberland Valley Resources, which purchases natural gas produced from a joint venture with Delta Producers, Inc., accounted for approximately 21% of our total revenue for 2009 and approximately4% of our total revenue in 2010.
The following table presents information regarding production volumes and revenues, average sales prices and costs, after deducting royalties and interests of others, with respect to oil and gas production attributable to our interest for the last three years. In the following table, average production cost are costs incurred to operate and maintain the wells and equipment and to pay the production costs, which does not include ad valoreum and severance taxes per unit of production, and is exclusive of work-over costs.
|
| Year Ended April 30, |
| |||||||
|
| 2010 |
| 2009 |
| 2008 |
| |||
Oil production (Bbls) |
|
|
|
|
|
|
|
|
|
|
Cook Inlet |
|
|
|
|
|
|
|
|
|
|
Production |
|
| 46,445 |
|
| — |
|
| — |
|
Average sales price |
| $ | 78.76 |
|
| — |
|
| — |
|
Average production cost |
| $ | 43.54 |
|
| — |
|
| — |
|
Appalachian region |
|
|
|
|
|
|
|
|
|
|
Production |
|
| 2,945 |
|
| 4,580 |
|
| 4,984 |
|
Average sales price |
| $ | 71.33 |
| $ | 68.77 |
| $ | 77.25 |
|
Average production cost |
| $ | 54.64 |
| $ | 52.49 |
| $ | 21.73 |
|
We must currently pay a $14.57 per barrel Cook Inlet Pipe Line tariff to the Drift River Terminal and a minimum of 5% in royalties to the State of Alaska from any oil or gas sold from the West McArthur River Unit and the Redoubt Unit, although with increased production at the West McArthur River Unit these escalate to a maximum of 12.5%. The Redoubt Unit is scheduled to have an increased royalty rate of 12.5% in 2012, unless we can negotiate a reduced rate. We are currently in royalty discussions with the State of Alaska, Division of Natural Resources and hope there will be a reduction. We have also protested the increase in the Cook Inlet Pipe Line tariff, that was increased from $4.06 per barrel to the current rate following the 2009 eruption of Mount Redoubt that
10
disrupted shipments though the Drift River Terminal. There are no assurances we will be successful in either appeal. We are also obligated to pay Cook Inlet Region, Inc. a 12.5% royalty on any gas sold from the portion of the West Foreland Gas Field located outside of the West McArthur River Unit. Finally, there are overriding royalty interests totaling approximately 12.4% for West McArthur River Unit, 4% for Redoubt Unit, and 5% for the portion of the West Foreland Gas Field located outside the West McArthur River Unit.
Our contract drilling operations
We provide land drilling services on a contract basis in the domestic market to customers that are primarily engaged in oil and natural gas exploration and production. The market that we serve is primarily the Appalachian Basin, which has unconventional natural gas bearing formations. Natural gas production from unconventional formations, including tight sands, shales and coalbed methane, is both the largest and fastest growing component of U.S. natural gas production. In addition to vertical drilling, we anticipate the need for horizontal drilling, which increases exposure of the wellbore to gas-bearing formations and provides better drainage. The horizontal drilling rigs contemplated for this are specially equipped for this type of work, as they typically require air circulation systems for penetrating through hard rock and enhanced fluid circulation systems for drilling horizontally into natural gas bearing formations. We plan to contract out the horizontal drilling operations in order to be able to provide this service.
Our services range from contract drilling by the foot or day rate to offering turnkey services to our customers. Our services are typically limited to the drilling portion of oil and gas extraction. Thus, when offering turnkey solutions, we will contract out the non-drilling functions such as possibly horizontal drilling and fracturing to non-affiliated third parties. We are responsible for the costs of rig refurbishment.
During calendar year 2010, in addition to providing drilling services for our other subsidiaries, we expect our wholly owned subsidiary Miller Drilling TN, LLC to drill, as needed, under contract in connection with our agreement to satisfy the two year drilling contract that it has with Atlas Energy. In addition, through our relationship with Atlas Energy, Miller Drilling has the opportunity to bid on other drilling or service work that Atlas Energy bids on in the State of Tennessee.
We are dependent on local customers for drilling revenues. Five customers, Atlas Energy Resources, LLC, Tri-Global Holdings, LLC, Montello Resources, LLC, Delta Producers Inc. and Herman Gettelfinger, a member of our Board of Directors, accounted for approximately 35% and approximately 94%, respectively, of our service and drilling revenue for 2010 and 2009.
Competition
Our oil and gas exploration activities in Alaska and Tennessee are undertaken in a highly competitive and speculative business environment. In seeking any other suitable oil and gas properties for acquisition, we compete with a number of other companies doing business in Alaska, Tennessee and elsewhere, including large oil and gas companies and other independent operators, many with greater financial resources than we have.
At the local level, as we seek to expand our lease holdings, we compete with several companies who are also seeking to acquire leases in the areas of the acreage which we have under lease. In Alaska, we have eight significant competitors including Aurora Gas, Bucaneer Alaska, Chevron, ConocoPhillips, Escopeta Oil, XTO, Linc Energy, and Marathon. However, we believe we have a competitive edge because we already have existing oil and gas production, facilities, infrastructure, and pipelines that connect us to the oil and gas markets as well as some of the lowest operating cost in the area. We believe that our existing Alaska oil and gas reserves and current leases with large acreage positions, enhance our competitive position within the area and will enable us to effectively compete for additional lease acreage with our competitors. In the Appalachian region, we have six significant competitors including Atlas Energy Resources, LLC, Consol Energy, Inc., Can Argo Energy Corporation, Champ Oil, John Henry Oil and Tengasco. These companies are in competition with us for oil and gas leases in known producing areas in which we currently operate, as well as other potential areas of interest. We believe we can effectively complete for leases, however, as in the Appalachian region we have name recognition over 40 years, we are the largest operator of oil and gas wells in Tennessee and we have a staff of experienced, proven petroleum geologists and engineers that allows us to exploit the potential the Appalachian region provides.
11
Substantially most of our competitors have more capital, longer operating histories and significantly greater financial and operating resources than we do. Given the relative size of our operations and our limited capital there is no assurance we will ever effectively compete in the area of obtaining the most leases in our target areas.
Government Regulation
While the prices of oil and natural gas are set by the market, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for oil production and natural gas depends on several factors beyond our control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of oil and natural gas, to prevent waste of oil and natural gas, to protect rights among owners in a common reservoir and to control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies.
Our exploration and production business is subject to various federal, state and local laws and regulations on the taxation of natural gas and oil, the development, production and marketing of natural gas and oil and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. The permits and approvals include those for the drilling of wells. Additionally, other regulated matters include the following:
·
bond requirements in order to drill or operate wells;
·
the location of wells;
·
the method of drilling and casing wells;
·
the surface use and restoration of well properties;
·
the plugging and abandoning of wells; and
·
the disposal of fluids.
The Regulatory Commission of Alaska regulates the intrastate pipeline tariffs and encompasses all pipelines Cook Inlet Energy ships through including the CIPL, CIGGS, and Beluga lines. The Regulatory Commission of Alaska must also review and approve most major gas sales contracts, and through this mechanism plays the dominant role in determining gas pricing, since Alaska has no spot market for gas.
Alaska law requires that we obtain state permits for the drilling of wells and to post a $200,000 bond with the Alaska Oil and Gas Conservation Commission. Injection wells are regulated by the Alaska Oil and Gas Conservation Commission and the United States Environmental Protection Agency (“EPA”). A $490,000 abandonment escrow is established for two Class 1 non-hazardous injection wells for benefit of EPA. These funds are held by the First National Bank of Alaska in escrow accounts currently on deposit. There are also many additional obligations to landholders, which are the Alaska DNR, Cook Inlet Region, Inc. (“CIRI”), Salamatof Native Association and the United States Bureau of Land Management (“BLM”). The Alaska DNR requires $600,000 in bonding to operate of Alaskan oil and gas leases, and as a condition of the bankruptcy sale has bound Cook Inlet Energy to funding an abandonment escrow over time based on production, not to exceed $50 million, which includes abandonment expenses associated with onshore assets, principally the wells associated with the West McArthur River Unit, is not to exceed $10 million, and the escrow for the offshore assets, principally for the closure of wells on the Osprey platform and the physical removal of the platform, is not to exceed $40 million. We are presently negotiating the term and amount of these escrow accounts in an effort to significantly reduce the amounts to levels we believe are more reasonable with the actual costs. Cook Inlet Energy is also obligated to establish an abandonment escrow of $1.5 million to cover future abandonment expenses related to the three West Foreland gas wells for benefit of the BLM and CIRI, $500,000 of which has already been funded, and $750,000 to establish an abandonment escrow for future abandonment expenses related to surface facilities and pipelines for benefit of CIRI and Salamatof Native Association. The BLM requires a bond of $25,000. $500,000 is due to Cook Inlet Region, Inc. in each of December 2010 and 2011 and $250,000 is payable to Salamatof Native in May each of 2010, 2011 and 2012.
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Under the Oil Pollution Act of 1990 Cook Inlet Energy is required to fund a citizens advisory group, the Cook Inlet Regional Citizen’s Advisory Council, under which its commitment is approximately $55,000 per year.
Tennessee law requires that we obtain state permits for the drilling of oil and gas wells and to post a bond with the Tennessee Gas and Oil Board to ensure that each well is reclaimed and properly plugged when it is abandoned. The reclamation bonds cost $1,500 per well. The cost for the plugging bonds are $2,000 per well or $10,000 for ten wells. Currently, we have several of the $10,000 plugging bonds. For most of the reclamation bonds, we have deposited a $1,500 Certificate of Deposit with the Tennessee Gas and Oil Board.
Sales of natural gas in Tennessee are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the Federal Energy Regulatory Commission ("FERC"), which sets the rates and charges for transportation and sale of natural gas, adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. The stated purpose of FERC's changes is to promote competition among the various sectors of the natural gas industry. In 1995, FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas by pipeline. Every five years, FERC will examine the relationship between the change in the applicable index and the actual cost changes experienced by the industry. We are not able to predict with certainty what effect, if any, these regulations will have on us.
The state and regulatory burden on the oil and natural gas industry generally increases our cost of doing business and affects our profitability. While we believe we are presently in compliance with all applicable federal, state and local laws, rules and regulations, continued compliance (or failure to comply) and future legislation may have an adverse impact on our present and contemplated business operations. Because such federal and state regulation are amended or reinterpreted frequently, we are unable to predict with certainty the future cost or impact of complying with these laws.
We are subject to various federal, state and local laws and regulations governing the protection of the environment, such as the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act and the Federal Water Pollution Control Act of 1972 (the "Clean Water Act"), which affect our operations and costs. In particular, our exploration, development and production operations, our activities in connection with storage and transportation of oil and other hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes may be subject to regulation under these and similar state legislation. These laws and regulations:
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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
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impose substantial liabilities for pollution resulting from our operations.
CERCLA, also known as "Superfund," imposes liability for response costs and damages to natural resources, without regard to fault or the legality of the original act, on some classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the "owner" or "operator" of a disposal site and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, we may generate waste that may fall within CERCLA's definition of a "hazardous substance." We may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed.
We currently lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we and our predecessors have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed or released on, under or from the properties owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose actions with respect to the
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treatment and disposal or release of hydrocarbons or other wastes were not under our control. These properties and wastes disposed on these properties may be subject to CERCLA and analogous state laws. Under these laws, we could be required to do the following:
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remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators,
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clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination, and/or
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clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination.
At this time, we do not believe that we are associated with any Superfund site and we have not been notified of any claim, liability or damages under CERCLA.
The RCRA is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements and liability for failure to meet such requirements on a person who is either a "generator" or "transporter" of hazardous waste or an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA's requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.
The Clean Water Act imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. The Clean Water Act requires us to construct a fresh water containment barrier between the surface of each drilling site and the underlying water table. This involves the insertion of a seven-inch diameter steel casing into each well, with cement on the outside of the casing. The cost of compliance with this environmental regulation is approximately $10,000 per well. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.
The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.
Our operations are also subject to laws and regulations requiring removal and cleanup of environmental damages under certain circumstances. Laws and regulations protecting the environment have generally become more stringent in recent years, and may in certain circumstances impose "strict liability," rendering a corporation liable for environmental damages without regard to negligence or fault on the part of such corporation. Such laws and regulations may expose us to liability for the conduct of operations or conditions caused by others, or for acts which may have been in compliance with all applicable laws at the time such acts were performed. The modification of existing laws or regulations or the adoption of new laws or regulations relating to environmental matters could have a material adverse effect on our operations.
In addition, our existing and proposed operations could result in liability for fires, blowouts, oil spills, discharge of hazardous materials into surface and subsurface aquifers and other environmental damage, any one of which could result in personal injury, loss of life, property damage or destruction or suspension of operations. We
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have an Emergency Action and Environmental Response Policy Program in place. This program details the appropriate response to any emergency that management believes to be possible in our area of operations. We believe we are presently in compliance with all applicable federal and state environmental laws, rules and regulations; however, continued compliance (or failure to comply) and future legislation may have an adverse impact on our present and contemplated business operations.
Consultants
In February 2010, we entered into a one year consulting agreement with Tyler Energy Consulting Group to provide certain investor relation services to us. Under the terms of this agreement issued 250,000 shares of our common stock valued at $487,500 as compensation. The agreement also provided that at our discretion we could issue up to an additional 250,000 shares of our common stock to the firm as additional compensation. On March 29, 2010 we issued the consultant an additional 70,000 shares of our common stock valued at $462,000 and on April 5, 2010 we issued the consultant an additional 110,000 shares of our common stock valued at $660,000 under the terms of this agreement. We granted Tyler Energy Consulting Group piggy back registration rights covering these shares and agreed to reimburse the firm for business related expenses. The agreement contains customary indemnification provisions.
We have entered into two agreements with Bristol Capital, LLC, an affiliate of Bristol Capital Advisors, LLC which is the investment advisor to Bristol Investment Fund, Ltd., an investor in the 2010 Offering, including the following:
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On March 12, 2010 we entered into a one year consulting agreement with Bristol Capital, LLC under which it agreed to assist us with strategic planning, management and business operations, introductions to further our business goals, advice and services regarding our growth initiative and other similar services we might request. As compensation for these services we granted Bristol Capital, LLC a five year warrant to purchase 300,000 shares of our common stock at an exercise price of $2.50 and five year options to purchase an additional 300,000 shares of our common stock at an exercise price of $2.50 per share. However, Bristol Capital, LLC will only be entitled to exercise the warrant or the option, not both, which will result in a total possible issuance of 300,000 shares of our common stock. These securities were valued at $1,169,293. In the event we issue securities at a price per share which is lower than $2.50 we are required to increase the number of shares underlying the warrant and option. Under the terms of this agreement, we agreed to include the shares underlying the warrant or option in the next registration statement we filed with the SEC, depending upon the form of registration statement is utilized. Upon the effectiveness of such registration statement, the option will automatically terminate. In the event we fail to file a registration statement covering the shares of common stock underlying the warrant by September 10, 2010, Bristol Capital, LLC may elect to terminate either security in its discretion. In any event, Bristol Capital, LLC shall only retain either the warrant or the option, but not both. Bristol Capital, LLC is contractually limited under the terms of this consulting agreement so that its beneficial ownership of our common stock cannot exceed 9.9% of our outstanding shares. It may waive this limitation upon 61 days notice to us.
We agreed to pay all out-of-pocket expenses incurred by Bristol Capital, LLC under this agreement, subject to our prior approval. The agreement also contains customary indemnification and confidentially provisions.
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On April 26, 2010 we entered into a finder’s agreement with Bristol Capital, LLC pursuant to which on our behalf it has commenced preliminary discussions with two parties regarding our possible acquisition of certain specified assets. We agreed that if within two years from the date of the agreement we should enter into a definitive agreement with either named party or any of their affiliates for the acquisition of these assets, we will pay Bristol Capital, LLC a finder’s fee of either an assignment of 5% of the interest in the assets or shares of our common stock valued at 5% of the aggregate purchase price at its election. We also agreed to pay a fee equal to 5% of the transaction value. If the efforts by Bristol Capital, LLC on our behalf should result in a joint venture or similar partnership related to these assets, we agreed to pay it a finder’s fee of 5% of the anticipated economic value of such an agreement.
Employees
At July 25, 2010 we had 45 full time and two part-time employees.
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Our history
We were incorporated in the State of Delaware in November 1985 originally under the name Longhorn Development Company, Inc. for the purpose of searching out and acquiring or participating in a business or business opportunity. In August 1988 we changed our name to Single Chip Systems International, Inc. In August 1988 we acquired all of the issued and outstanding securities of Single Chip Systems, Inc., a California corporation, in exchange for shares of our common stock. Our then current officers and directors resigned and the officers and directors of Single Chip Systems, Inc. were appointed officers and directors of our company. Prior thereto, on July 1, 1988, Single Chip Systems, Inc. had entered into a technology utilization license agreement with Ramtron International Corporation which granted Single Chip Systems, Inc. the royalty-bearing, non-exclusive licenses to use the ferroelectric technologies and the certain trademarks in production, manufacture and sales of Single Chip Systems, Inc. products. We failed to receive any economic benefit related to the license agreement and we recorded a $100,000 loss on the license agreement in the period ended December 31, 1988.
Thereafter, we had no business or operations until the transaction in January 1997 as hereinafter described. In May 1996 we changed our name to Triple Chip Systems, Inc.
Mr. Deloy Miller formed Miller Petroleum, Inc. (“pre-merger Miller”), a company which is the basis of our current operations, in January 1978. In January 1997, we closed an Agreement and Plan of Reorganization with pre-merger Miller whereby we issued 5,582,535 shares of our common stock in exchange for all of the outstanding common stock of per-merger Miller. The acquisition was accounted for as a recapitalization of our company because the shareholders of pre-merger Miller controlled the company after the acquisition. Following the transaction, in January 1997, pre-merger Miller was merged into our company and we changed our name to Miller Petroleum, Inc. in conjunction with the redomestication of our company into the State of Tennessee.
Effective as of June 13, 2008 we entered into an agreement with Atlas Energy Resources, LLC under which we assigned it:
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an unencumbered, undivided 100% working interest and an 80% net revenue interest in and to the oil and gas lease comprising 27,620 acres known as Koppers North and Koppers South and located in Campbell County, Tennessee; and an unencumbered, undivided 100% interest and an 82.5% net revenue interest (net of a 5% overriding royalty interest to us) in and to the oil and gas lease comprising 1,952 acres adjacent to Koppers North and Koppers South and located in Campbell County, Tennessee; and
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an unencumbered, undivided 100% working interest and an 80% net revenue interest in eight gas wells on Koppers South. We have the option to repurchase the wells within one year form the closing date or within 30 days after the pipeline to be built by Atlas Energy has been completed and is ready to accept gas for transport.
The transaction was subject to unwinding pursuant to a pending litigation between our company and CNX Gas Company LLC as disclosed in Item 3. Legal Proceedings. Transferring any of the leases or any interest thereon was also subject to a 60-day standstill period which has since expired. The aggregate consideration for the assignment of the leases and wells to Atlas Energy was $19,625,000, $9,025,000 of which was paid us and the remaining $10,600,000 of which was paid directly to Wind City Oil & Gas, LLC in consideration of a settlement of claims between Wind City and our company described below.
As part of the transaction, we also agreed to contract with Atlas Energy for two rigs for two years to drill wells, commencing a significant commitment to contract drilling. To give Atlas Energy the level of service required, during the first quarter of fiscal 2009 we acquired a 2007 COPCO Model RD III drilling rig and related equipment drilling rig from Atlas to assist in drilling the wells. For two years after the closing date, Atlas Energy granted us the opportunity to bid on any other drilling or service work that Atlas Energy bids on in the State of Tennessee. In addition, we entered into:
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a natural gas transportation agreement with Atlas Energy which provides us access to the Atlas Volunteer Pipeline, to the extent that capacity is available, on substantially the same terms as those offered to the producers delivering into the system; and
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a natural gas processing agreement pursuant to which Atlas Energy will provide gas processing services to us on substantially the same terms as those services are provided to other producers delivering gas into the Atlas Volunteer Pipeline and deliver back to us gas with a heating value of 1,100 BTUs per cubic foot.
Effective as of June 13, 2008, we also settled all issues and controversies with Wind City Oil & Gas, LLC, Wind Mill Oil & Gas, LLC and Wind City Oil & Gas Management, LLC. Under the terms of the settlement, we paid Wind City $10,600,000 for the re-purchase of 2,900,000 shares of our common stock and reacquisition of all leases previously assigned by us to Wind City or the related parties, all wells and equipment associated with these leases, all pipeline rights and rights of way, all contract rights, and all other equipment, property and real property rights. As set forth above, we used a portion of the proceeds from the Atlas Energy transaction to pay the settlement amounts.
On June 8, 2009 we acquired certain assets from Ky-Tenn Oil, Inc., a Kentucky corporation ("KTO"), an unrelated third party, including KTO's:
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undivided interest in approximately 170 oil and gas wells in Morgan, Scott and Fentress counties in Tennessee, together with all property, fixtures and improvements, leasehold interest and contract rights related to these wells;
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undivided interest in approximately 35,325 acres of oil and gas leases in Scott and Morgan counties, Tennessee;
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interest in an operating agreement with the Tennessee State Energy Development Partnership;
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interest in a gas gathering pipeline system; and
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other rights related to these assets, including royalty and working interests, licenses, permits, and similar incidental rights.
As consideration for these assets we issued KTO 1,000,000 shares of our common stock valued at $320,000 and we granted the seller piggy-back registration rights covering these shares. Pursuant to this FASB guidance, we originally valued these assets at $252,455 and recorded a loss on the transaction of $67,545. Subsequently, we completed the determination of the value of all undeveloped reserves for this acreage during the quarter ended October 31, 2009 and accordingly we recorded an additional gain of $1,057,564 on this transaction.
On June 18, 2009 we acquired 100% of the stock of East Tennessee Consultants, Inc., a Tennessee corporation ("ETC") and 100% of the membership interests in East Tennessee Consultants II, LLC, a Tennessee limited liability company ("LLC") from the owners of these entities. Pursuant to FASB ASC 805-10, we have valued these companies at $1,862,369 and have recorded a gain on the transaction of $828,745. As consideration for these companies we issued the sellers, who were unrelated third parties, 1,000,000 shares of our common stock valued at $250,000. We granted the sellers registration rights covering these shares.
Under the terms of the stock purchase agreement, the sellers agreed not to engage in oil and gas operations for a period of three years following the closing date. We also agreed that each of the sellers, Messrs. Eugene D. Lockyear, Douglas G. Melton and Jerry G. Southwood, would continue their employment with the acquired companies for at least three years from the closing date of the transaction at their same compensation and benefit levels to which they were entitled in May 2009. In addition, Mr. Lockyear was appointed Vice President of Operations of our company. We also agreed that if any or all of the sellers incur any income tax liability as a result of the receipt of the above shares as consideration for the stock purchase, we agreed to pay a bonus to such seller equal to the amount of his tax liability within 30 days from the request of the sellers.
On December 10, 2009, Cook Inlet Energy acquired former Alaskan assets of Pacific Energy Resources valued at more than $479 million through a Delaware Chapter 11 bankruptcy proceeding, including oil and gas assets which include onshore and offshore production facilities, $215 million in proven energy reserves, $122 million in probable energy reserves and $31 million in possible energy reserves, providing total reserves of $368 million. The purchased assets included the West McArthur River oil field, the West Foreland natural gas field, and the Redoubt unit with the Osprey offshore platform, all located along the west side of the Cook Inlet. Also included in the asset purchased were 602,000 acres of oil and gas leases which includes 471,474 acres under the Susitna Basin Exploration License as well as completed 3D seismic geology and other production facilities, together with:
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all easements, wells and tangible assets,
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all oil and gas or proceeds from the sale of oil and gas produced in connection with the acquired assets from the closing date,
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all contracts, unitization, communization and pooling declarations, orders and agreements,
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all permits, records, royalty interests, partnership and joint venture interests,
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to the extent assignable, all rights to indemnities,
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all leases for real property used by the seller in connection with the operation of the acquired assets,
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escrow accounts and bonds deposited with government entities with respect to the acquired assets,
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all surety bonds, plugging bonds, abandonment bonds, standby trust agreements, escrow accounts for plugging, abandonment, decommissioning, removal and restoration obligations, together with security deposits,
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all imbalances owed to the sellers by a third party at the closing, as well as all oil and gas in pipelines and tanks or held by or for the account of the sellers related to the assets acquired, and
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the portion of the seller’s Royalty Distributors Inc.’s account relating to post-petition suspended royalties.
In this transaction, Cook Inlet Energy assumed certain liabilities related to the acquired assets, including:
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all liabilities associated with or arising out of the ownership of, or operation of, the assets after the closing date,
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all environmental liabilities with respect to the acquired assets,
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all accounts payable from the closing date,
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all royalty obligations associated with or related to the acquired assets after the closing date,
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all claims arising out of the ownership or operation of the acquired assets after the closing date,
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all plugging, abandonment, decommissioning, removal and/or restoration liabilities associated with or arising from the acquired assets with respect to all periods prior to, on or after the closing date,
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permitted encumbrances and imbalances owed by the sellers to third parties, and
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post-petition suspended royalties maintained by Royalty Distributors Inc.
At closing we paid Pacific Energy Resources $2.25 million and provided $2.22 million for bonds, contract cure payments and other federal and State of Alaska requirements to operate the facilities. Under the terms of the purchase agreement, Donkel Oil & Gas, LLC was granted a one-half of 1% overriding royalty interest in the oil and gas leases acquired by Cook Inlet Energy, a 1% overriding royalty interest on Pacific Energy’s working interest in all exploration oil and gas leases acquired by Cook Inlet Energy in the transaction, and a 5/10th of 1% overriding royalty interest owned by Pacific Energy on the leases that comprise the Cosmopolitan Unit and Falls Creek. In addition, Donkel Oil & Gas, LLC received a 1% overriding royalty interest on Cook Inlet Energy’s working interest in any oil and gas lease which arises from certain properties included in an exploration license, which includes one lease, together with a 1% overriding royalty on our working interest in two additional oil and gas leases.
On December 10, 2009, we acquired 100% of the membership interests in Cook Inlet Energy, an Alaska limited liability company from the owners of this entity. As consideration for these companies we issued the sellers, who were unrelated third parties, four year stock warrants to purchase 3,500,000 shares of our common stock at exercise prices ranging from $0.01 to $2.00 per share. In addition, we are required to deliver $250,000 in cash to satisfy certain expenses as well as reimbursement for reasonable out of pocket expenses; such payment has not yet been made. Under the terms of the stock purchase agreement, the sellers agreed not to engage in non-company related oil and gas operations for a period of three years following the closing date. We also agreed that each of the sellers, Messrs. David M. Hall, Walter J. Wilcox II and Troy Stafford, would continue their employment with the acquired company for at least three years from the closing date of the transaction at their specifically defined compensation and benefit levels. In addition, Mr. Hall was appointed as a member of our Board of Directors and as Chief Executive Officer of Cook Inlet Energy. Subsequent to April 30, 2010, Mr. Stafford has left the employ of Cook Inlet Energy.
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Miller Energy Income 2009-A, L.P. Offering
In 2009 we formed both Miller Energy GP and MEI. MEI was organized to provide the capital required to invest in various types of oil and gas ventures including the acquisition of oil and gas leases, royalty interests, overriding royalty interests, working interests, mineral interests, real estate, producing and non-producing wells, reserves, oil and gas related equipment including transportation lines and potential investments in entities that invest in such assets except for other investment partnerships sponsored by affiliates of MEI.
Between August 2009 and April 2010 MEI sold 61.35 units of securities to 23 accredited investors in transactions exempt from registration under the Securities Act of 1933 in reliance on exemptions provided by Section 4(2) and Regulation D of that act. Each unit consisted of a $50,000 limited partnership interest in MEI, together with 25,000 shares of our common stock and a five year warrant to purchase an additional 25,000 shares of our common stock with an exercise price of $1.00 per share. In order to receive our securities as part of the offering, investors in the MEI were required to purchase at least one unit. We issued a total of 1,329,250 shares of our common stock and common stock purchase warrants to purchase an additional 1,329,250 shares of our common stock.
MEI received $3,067,500 in proceeds from this offering. It paid selling commissions of 7% on the sale of certain units (an aggregate of $115,780) and a non-accountable marketing and due diligence allowance of 1% of the proceeds received from certain units sold in the offering (an aggregate of $16,540), to Dimirak Securities Corporation, a related party, and Newbridge Securities Corporation, both broker-dealers and members of FINRA. Mr. Scott M. Boruff, our CEO, is a director and 49% owner of Dimirak Securities Corporation. MEI also paid a wholesaling commission based on 2% of the gross proceeds (an aggregate of $33,080) to several firms including Newbridge Securities Corporation, Empire Securities Corporation and Arque Capital Ltd. MEI paid a dealer management fee of 1% of the gross offering proceeds (an aggregate of $30,540) to several parties including Dimirak Securities Corporation, its affiliate Dimirak Financial Corporation and Empire Securities Corporation. Finally, Dimirak Securities Corporation received an additional $30,675 in other fees which was based on 1% of investor capital and two individuals received a total of $81,000 for referral fees. Purchasers of these securities have been granted piggy back registration rights covering the shares of our common stock.
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ITEM 1A.
RISK FACTORS.
An investment in our common stock involves a significant degree of risk. You should not invest in our common stock unless you can afford to lose your entire investment. You should consider carefully the following risk factors and other information in this annual report before deciding to invest in our common stock.
Risks Related to Our Business
We have a history of operating losses and our net income in 2010 and 2009 are both the result of one-time acquisition gains. Our revenues are not currently sufficient to fund our operating expense and there are no assurances we will develop profitable operations.
We reported an operating loss of approximately $11.1 million in 2010 and approximately $3.2 million in 2009. Our net income of approximately $249.5 million in 2010 is attributable to the approximate $461.1 million gains on the acquisitions of the Alaska and Tennessee assets. Our net income of approximately $8.4 million in 2009 is attributable to the approximate $11.7 million one-time gain on the sale of assets in Tennessee. While our revenues increased approximately $4.3 million in 2010 from 2009, our operating expenses increased by approximately $12.2 million from year to year. Approximately 31% of this increase in 2010 is associated with one-time non cash expenses and 19% is associated with ongoing non cash expenses. In addition, we did not begin reporting revenues from our Alaskan assets until January 2010. However, as a result of the significant expansion of our business during 2010 our operating expenses presently far exceed our revenues. We anticipate that our operating expenses will continue to increase as we fully develop our operations following the acquisition of the Alaskan assets and expect an increase in our revenues as well. However, until such time as we are able to significantly increase our revenues, we will continue depleting our cash resources to fund our operating expenses. We believe our present working capital is sufficient to fund our operations for the foreseeable future, but we may have to reduce or cease our expansion efforts if we have not seen an increase in revenues in the next few months. While we believe that we will successful in increasing our revenues to a level which will pay our operating expenses, if we are not successful we will need to raise additional capital until such time as our revenues are sufficiently increased. As described below, our ability to raise additional capital could be adversely impacted by the terms of our March 2010 unit offering. If we are unable to raise additional capital as necessary to fund our operating expenses, our ability to continue to grow our company would be hampered and we could be forced to curtail development of some or all of our assets until such time, if ever, that we are able to raise the needed capital.
Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which would prevent us from fully developing our business and substantially increasing our revenues.
The oil and gas industry is capital intensive and we anticipate in addition to funds necessary to fund our operating expenses while we continue to develop the Alaskan assets, that we will need to raise between $75 million and $100 million to meet our funding commitments under the Assignment Oversight Agreement with the State of Alaska DNR and to fully develop our Tennessee and Alaskan reserves. We intend to seek this additional capital through the sale of equity or debt instruments; however, the terms of the March 2010 unit offering contain restrictive covenants that prevent us from raising any additional equity capital for six months following the effective date of a registration statement we are obligated to file with the SEC registering the securities sold in this offering and which contain additional covenants which may impede our capital raising activities in future periods. We may not be able to obtain this necessary equity or debt financing on terms favorable to us, if at all. If we are unable to raise the capital as needed, the State of Alaska could terminate all of the Cook Inlet leases which would be a material adverse event to our company and we would be unable to fully develop our Alaskan reserves which would materially impact our ability to increase our revenues in future periods. To the extent such funds are not available from any of those sources, our operations and activities will be limited to those operations and activities we can afford with the funds then available to us. The failure to obtain additional financing could also result in a curtailment of our operations relating to exploration and development of our prospects.
We have failed to timely file a registration statement related to our March 2010 unit offering and are subject to registration rights penalties which are payable in cash.
Under the terms of our March 2010 unit offering we were required to file a registration statement with the SEC registering for resale the shares of common stock sold in the offering, including those underlying the warrants included in the units, by April 15, 2010. We also agreed to use our best efforts to cause the registration statement to
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be declared effective by the SEC within 90 days from the filing date or 120 days if the registration statement should be selected for a full review by the staff of the SEC. The registration rights agreement provides that if we failed to timely file the registration statement, or if it should not be declared effective within the prescribed time, we are subject to liquidated damages payable in cash equal to 2% of the aggregate purchase price of the securities up to a maximum of 12% of the total proceeds of the offering. We have yet to file the registration statement. Because we did not timely file the registration statement, during the fourth quarter of 2010 we accrued registration rights penalties of $602,040 which is payable in cash to the investors in that offering.
Cook Inlet Energy’s operations are subject to oversight by the Alaska DNR and the Cook Inlet Energy oil and gas leases could be terminated if it fails to uphold the terms of the Assignment Oversight Agreement. If these leases were terminated, we would be unable to continue our operations as they are presently conducted and could be liable for significant additional costs associated with decommissioning the Osprey platform.
Cook Inlet Energy is a party to an Assignment Oversight Agreement with the Alaska DNR that was entered into in November 2009 as a condition of the sale of the oil and gas leases from Pacific Energy Resources to Cook Inlet Energy. The agreement states that its intent is to ensure that there were sufficient funds, and that those funds are only spent, to fulfill Cook Inlet Energy’s initial development, operation, and dismantlement obligations under the assigned leases, applicable statutes and regulations. Those commitments include approximately $5.15 million to be used by Cook Inlet Energy to restore base production at the West McArthur River Unit Facility and approximately $31 million to support restoration of base production at the Redoubt Unit. Internally we have increased that requirement to $35 million to accommodate the purchase of a drilling rig for the Osprey platform. During the interim period, Cook Inlet Energy has fulfilled its commitment to restore base production from the West McArthur River Unit. However, we remain obligated to restore base production from the Redoubt Unit. We will need to either close the funding commitment from Vulcan Capital Corporation or raise the necessary capital from third parties. As a result of the restrictive covenants of the March 2010 unit offering, our ability to raise additional capital is limited. If we are unable to raise the capital as necessary to fully fund the commitment made in connection with the Assignment Oversight Agreement, the State of Alaska could terminate all of the Cook Inlet leases which would be a material adverse event to our company. Our operations would be limited to the Appalachian region and it is unlikely we would be able to continue our operations as they are presently conducted. In addition, we would then be obligated to fund the decommissioning and abandonment of the Osprey platform, which could cost as much as $40 million, of which only approximately $6.6 million has been escrowed with Alaska.
Oil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Declines in prices adversely affect our financial results and rate of growth in proved reserves and production.
Oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, changes in global supply and demand for oil and gas, the actions of the Organization of Petroleum Exporting Countries, the level of global oil and gas exploration and production activity, weather conditions, technological advances affecting energy consumption, domestic and foreign governmental regulations and tax policies, proximity and capacity of oil and gas pipelines and other transportation facilities and transportation costs and the price and technological advancement of alternative fuels.
The downward pressure in oil and natural gas prices that began in the last half of 2008 continued in 2010. The average realized gas price per thousand standard cubic feet (Mscf) for 2010 decreased 40% from 2009 and the average realized oil price per barrel for 2010 decreased 9% from 2009. The decrease in prices significantly decreased the amount available to invest in exploration and development drilling and the present value of our proved reserves. Our proved oil and gas reserves and production volumes decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce, to increase our daily production and to increase our total proved reserves. It will be necessary for us to raise additional capital to fund these expenditures. Low prices also reduce the amount of oil and gas that we can economically produce and may cause us to curtail, delay or defer certain exploration and development projects.
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The global economic crisis may have impacts on our business and financial condition that we currently cannot predict.
The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could have an impact on potential lenders, purchasers of our oil and gas production and working interest owners in properties we operate, causing them to fail to meet their obligations to us.
Estimates of oil and natural gas reserves are inherently imprecise. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the quantities and present value of our reserves.
Estimates of proved oil and natural gas reserves and the future net cash flows attributable to those reserves are prepared by independent petroleum engineers and geologists. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and cash flows attributable to such reserves, including factors beyond our control and that of our engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Different reserve engineers may make different estimates of reserves and cash flows based on the same available data. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and natural gas prices and expenditures for future development drilling and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development drilling and exploration activities and prices of oil and natural gas. Actual future production, revenue, taxes, development drilling expenditures, operating expenses, underlying information, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information set forth herein.
Approximately 74% of our total estimated proved reserves at April 30, 2010 were proved undeveloped reserves. In addition, there are no assurances that probable and possible reserves will be converted to proved reserves.
Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. Although cost and reserve estimates attributable to our natural gas and crude oil reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate, that development will occur as scheduled or that the results of such development will be as estimated. We also have a significant amount of probable and possible reserves at April 30, 2010. There is significant uncertainty attached to probable and possible reserve estimates. Proved reserves are more likely to be produced than probable reserves and probable reserves are more likely to be produced than possible reserves. There are no assurances that we can develop probable or possible reserves into probable reserves, or that if developed, probable reserves will become producing reserves to the level of the estimates.
There are no assurances that we will be able to extend the Susitna Basin Exploration License.
Included in the Alaskan assets we acquired is the Susitna Basin Exploration License granted by the State of Alaska covering approximately 471,474 acres which expires in October 2010. The acreage which is the subject of this exploration license represents approximately 84% of our net undeveloped acreage at April 30, 2010. Under the terms of the exploration license, providing that the work commitment of approximately $3.5 million was fulfilled, during the exploration license term the licensee has the right to convert the license for all or a portion of the acreage into oil and gas leases. This original work commitment was met by the prior licensee and we presently have the right to convert the license into leases. Once the exploration license is converted into oil and gas leases, we are required to pay a per acre fee to the state and commence drilling operations within specified timeframes. In an effort to control the timing of the development of this acreage, in April 2010 we requested a three year extension of the exploration license for a work commitment of $750,000. While we reasonably believe the state will grant our request for extension, there are no assurances we are correct, or that if granted, that the terms and conditions of the extension will be satisfactory to us. If we are unable to negotiate an extension, it is likely we will convert the license for only a
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portion of the land into oil and gas leases. The loss of the remaining rights would reduce the acreage which we could develop into proved, producing reserves.
The present value of future net cash flows from our proved reserves will not necessarily be the same as the current market value of our estimated natural gas, crude oil and natural gas liquids reserves.
You should not assume that the present value of future net revenues from our proved reserves referred to in this annual report is the current market value of our estimated natural gas, crude oil and natural gas liquids reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from our proved reserves are based on prices and costs on the date of the estimate, held flat for the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate. Actual future net cash flows will also be affected by increases or decreases in consumption by oil and gas purchasers and changes in governmental regulations or taxation. The timing of both the production and the incurrence of expenses in connection with the development and production of oil and gas properties affects the timing of actual future net cash flows from proved reserves. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor.
Our industry is subject to extensive environmental regulation that may limit our operations and negatively impact our production. As a result of increased enforcement of existing regulations and potential new regulations following the Gulf oil spill, the costs for complying with government regulation could increase.
Extensive Federal, state, and local environmental laws and regulations in the United States affect all of our operations. Environmental laws to which we are subject in the U.S. include, but are not limited to, the Clean Air Act and comparable state laws that impose obligations related to air emissions, the Resource Conservation and Recovery Act of 1976 (RCRA), and comparable state laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from our facilities, the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which our hazardous substances have been transported for disposal, and the Clean Water Act, and comparable state laws that regulate discharges of wastewater from our facilities to state and federal waters. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental laws, including CERCLA and analogous state laws, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Environmental legislation may require that we do the following:
·
acquire permits before commencing drilling;
·
restrict spills, releases or emissions of various substances produced in association with our operations;
·
limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas;
·
take reclamation measures to prevent pollution from former operations;
·
take remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and remedying contaminated soil and groundwater; and
·
take remedial measures with respect to property designated as a contaminated site.
There is inherent risk of incurring environmental costs and liabilities in connection with our operations due to our handling of natural gas and other petroleum products, air emissions and water discharges related to our operations, and historical industry operations and waste disposal practices. The costs of any of these liabilities are presently unknown but could be significant. We may not be able to recover all or any of these costs from insurance. In addition, we are unable to predict what impact the Gulf oil spill will have on independent oil and gas companies
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such as our company. For instance, companies such as ours currently pay an $0.08 per barrel tax on all oil produced in the U.S. which is contributed to the Oil Spill Liability Trust Fund. There are pending proposals to raise this tax to $0.18 to $0.25 per barrel. It is also probable that there will be increased enforcement of existing regulations and adoption of new regulations which will also increase our cost of doing business which would reduce our operating profits in future periods.
The effects of future environmental legislation on our business are unknown but could be substantial.
Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. Changes in, or enforcement of, environmental laws may result in a curtailment of our production activities, or a material increase in the costs of production, development drilling or exploration, any of which could have a material adverse effect on our financial condition and results of operations or prospects. In addition, many countries, as well as several states in the United States have agreed to regulate emissions of “greenhouse gases.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning natural gas, are greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations and demand for products in the future.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the Energy Policy Act of 2005, the Federal Energy Regulatory Commission, or FERC, has authority to impose penalties for violations of the Natural Gas Act, up to $1 million per day for each violation and disgorgement of profits associated with any violation. FERC has recently proposed and adopted regulations that may subject our facilities to reporting and posting requirements. Additional rules and legislation pertaining to these and other matters may be considered or adopted by FERC from time to time. Failure to comply with FERC regulations could subject us to civil penalties.
Our business depends on oil and natural gas transportation facilities, most of which are owned by others.
The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. The lack of availability of these facilities for an extended period of time could negatively affect our revenues. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.
Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate.
Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation costs. In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease. We maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operation.
Our Cook Inlet Basin leases and our Osprey Platform are located in a region of active volcanoes and we could be subject to the adverse impacts of natural disasters.
The Cook Inlet region contains active volcanoes, including Augustine Volcano, Mount Spurr and Mount Redoubt, and volcanic eruptions in this region have been associated with earthquakes and tsunamis and debris avalanches have also resulted in tsunamis. In 2009 the Cook Inlet Pipeline Co. suspended operations on several
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occasions as a result of the spring 2009 major eruption of Mount Redoubt which also resulted in a shutdown of the Drift River Oil Terminal. Our operations in this area are subject to all of the inherent risks associated with operations in a geographical region which is subject to natural disasters and we are susceptible to the risk of damage to our operations and assets located in the Cook Inlet Basin. While our facilities are engineered to withstand seismic activity, and the current tight line configuration should allow us to continue shipments through an active volcanic period without much interruption, we do not maintain business interruption insurance which could adversely impact our results of operations as the result of lost revenues in future periods.
We may be subject to certain conflicts of interest related to Miller Energy Income 2009 -A, LP which may not be resolved in a manner favorable to our company.
A wholly owned subsidiary of our company is the general partner of Miller Energy Income 2009-A, LP ("MEI") and Messrs. Miller, Boruff and Boyd are officers of MEI. In November and December 2009 we borrowed an aggregate of approximately $2.7 million from MEI under the terms of four year secured notes. In the event there should be a dispute under this loan, there are no assurances that it will be resolved in our favor. We asked a third party to hold in escrow titles to substantial company drilling equipment to serve as collateral for these loans. In the event of a dispute under this loan, we could lose ownership of this equipment which we need to perform drilling and drilling services. In that event, we would be unable to continue our operations as they are presently conducted which would have a material adverse impact on our results of operations in future periods. There are no assurances that decisions Messrs. Miller, Boruff and/or Boyd make in matters related to MEI will be beneficial to us.
Certain of our outstanding warrants contain cashless exercise provisions which means we will not receive any cash proceeds upon their exercise.
At July 22, 2010 we have common stock warrants outstanding to purchase an aggregate of 2,910,000 shares of our common stock with an average exercise price of $1.21 per share which are exercisable on a cashless basis. This means that the holders, rather than paying the exercise price in cash, may surrender a number of warrants equal to the exercise price of the warrants being exercised. It is possible that the warrant holders will utilize the cashless exercise feature which will deprive us of additional capital which might otherwise be obtained if the warrants did not contain a cashless feature.
A large portion of our outstanding common shares are “restricted securities” and we have outstanding options, warrants and purchase rights to purchase approximately 47% of our currently outstanding common stock.
At July 22, 2010 we had 33,389,383 shares of common stock outstanding together with outstanding options and warrants to purchase an aggregate of 11,976,955 shares of common stock at exercise prices of between $0.01 and $6.53 per share and $1,285,000 principal amount of convertible notes which are convertible into 2,336,364 shares of common stock at a conversion price of $0.55 per share. Of our outstanding shares of common stock at July 22, 2010, approximately 16,426,863 shares are "restricted securities." Future sales of restricted common stock under Rule 144 or otherwise could negatively impact the market price of our common stock. In addition, in the event of the exercise of the warrants and options and the conversion of the notes, the number of our outstanding common stock will increase by approximately 32%, which will have a dilutive effect on our existing shareholders.
The impacts of non-cash gains and losses from derivative liability accounting in future periods could materially impact our financial results.
As a result of the terms of the March 2010 unit offering, as well as the terms of other recent financing transactions we have entered into in 2010, our financial statements for the year ended April 30, 2010 were impacted by the accounting effect of the application of derivative accounting. We anticipate that our financial statements in future periods will also be impacted. The application of EITF 07-05 “Determining Whether an Instrument (or Embedded Feature) is Indexed to a Company's Own Stock,” which was effective on January 1, 2009 will significantly affect the application of ASC Topic 815 and ASC Topic 815-40 for both freestanding and embedded derivative financial instruments in our financial statements. Generally, warrants, conversion features in debt, and similar terms that include “full-ratchet” or reset provisions, which mean that the exercise or conversion price adjusts to pricing in subsequent sales or issuances, no longer meet the definition of indexed to a company's own stock and are not exemption for equity classification provided in ASC Topic 815-15. This means that instruments that were previously classified in equity will require reclassification to liabilities and ongoing measurement under ASC Topic 815. As a result of the application of this accounting principle, we recorded a current derivative liability of $720,840
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and a long-term derivative liability of $16,708,947 at April 30, 2010. Beginning in the first quarter of 2011, we expect to record either a gain or loss based upon the market price of our common stock. The amount of quarterly non-cash gains or losses we will record in future periods is unknown at this time as the measurement is based upon the fair market value of our common stock on the measurement date. It is likely, however, that these non-cash gains or losses could have a material impact on our financial results in future periods.
ITEM 1B.
UNRESOLVED STAFF COMMENTS.
ITEM 2.
PROPERTIES.
Our executive offices presently comprise approximately 4,968 square feet for the main office building and 6,600 square feet for the shop building on 14.05 acres of land in Huntsville, Tennessee that we own. We also own or rent facilities in the following locations:
·
Tennessee: Knoxville, Huntsville and Sunbright.
·
Anchorage, Alaska
Production facilities
Cook Inlet Energy operates two onshore production facilities and one offshore platform located on or near the West Foreland, which is a small peninsula located in a remote area on the west side of Cook Inlet. The West Foreland is accessible by barge and fixed wing aircraft, and is not tied in with the Alaskan road system or electrical grid. Cook Inlet Energy maintains its own 10-mile road system and local electrical system.
The West McArthur River Unit Production Facility is one of our two onshore production facilities. It is located 3.5 miles south of Chevron's Trading Bay Production Facility, which is near the site of the local airstrip and barge landing. The West McArthur River Unit Production Facility can process 5,000 barrels of oil and seven MMscf of natural gas per day, generate three megawatts of electricity and contains 10,000 barrels of on-site tankage. The West McArthur River Unit Production Facility also includes our onshore camp, which provides housing and life support facilities sufficient for 65 people.
The Kustatan Production Facility is our other onshore production facility. This facility can process 30,000 barrels of oil a day, generate 16 megawatts of electricity, treat up to 20 MMscf of natural gas and contains 50,000 barrels of on-site tankage. The facility, which is located five miles south of The West McArthur River Unit Facility, is currently inactive.
Oil and gas properties
Information on our oil and gas properties appears earlier in this annual report.
ITEM 3.
LEGAL PROCEEDINGS.
CNX Gas Company, LLC commenced litigation on June 11, 2008 in the Chancery Court of Campbell County, State of Tennessee in a case style CNX Gas Company, LLC vs. Miller Petroleum Inc., Civil Action No. 08-071, to enjoin us from assigning or conveying certain leases described in the Letter of Intent signed by CNX and our company on May 30, 2008, to compel us to specifically perform the assignments as described in the Letter of Intent; and for damages. A Notice of Lien Lis Pendens was issued June 11, 2008. We moved for entry of summary judgment dismissing the claims asserted against us by CNX and on January 30, 2009 the court found that CNX’s claims had no merit. The court granted our motion and dismissed all claims asserted by CNX in that action. CNX has appealed the ruling, and briefs have been submitted to the Court of Appeals of Tennessee. Oral arguments were held on May 18, 2010, and an opinion from the Court of Appeals is expected sometime in the fall of 2010.
On May 20, 2009 Gunsight Holdings, LLC, a Florida limited liability company, filed a complaint in the United States District Court for the Eastern District of Tennessee, Northern Division, against us styled Gunsight Holdings, LLC, Plaintiff, v Miller Petroleum, Inc. and Ky-Tenn Oil, Inc., Defendants, Case No. 3-09-CV-221. The litigation surrounds certain rights related to approximately 6,800 acres in Scott County, Tennessee which KTO purportedly acquired under a lease assignment from an unrelated party in August 2004. In September 2008, KTO
26
assigned us 75% of its interest in the subject lease and the working interest in all the wells on the leased land, retaining a 25% interest in the wells consisting of landowner's royalty and overriding royalty. On June 8, 2009 we acquired certain assets from KTO including KTO's undivided interest in approximately 170 oil and gas wells in Morgan, Scott and Fentress counties in Tennessee, together with all property, fixtures and improvements, leasehold interest and contract rights related to these wells and undivided interest in approximately 35,325 acres of oil and gas leases in Scott and Morgan counties, Tennessee. The lease which is the subject of the litigation was included in the assets purchased by us from KTO. The plaintiff is alleging that our company and KTO have failed or refused to pay royalties due to the plaintiff’s predecessors and have breached the implied duty of further exploration by failing to drill required wells, failing to reasonably develop or explore the property, failing to maintain an active interest in further development of the property and otherwise failing to act as a prudent operator of the property thereby causing damages to the plaintiff exceeding $75,000. The plaintiff is seeking a declaratory judgment of its allegations, removal of our company and KTO from the property, a full accounting of activities related to the property and all monies received from those activities, damages and costs of action. We have filed an answer denying the various claims and asserting affirmative defenses including that there has been continuous production from the subject lease. We are currently in discovery.
On October 8, 2009 we filed an action styled Miller Petroleum, Inc. v. Maynard, Civil Action No. 9992 in the Chancery Court for Scott County, Tennessee, seeking a declaratory judgment that there has been continuing commercial production of oil, and oil and gas lease owned by us is still in full force and effect. The defendant filed an Answer and Counterclaim, seeking in the Counterclaim a declaration that the oil and gas lease has expired. Although no compensatory monetary damages have been sought against us, the Counterclaim does seek attorney fees, expenses and costs. There has been no discovery to date and a trial date has not been assigned. Plaintiff’s attorney left his firm, and the case has been delayed as Plaintiff’s new counsel (with the same firm) becomes familiar with the case.
On March 26, 2010, Petro Capital III, LP filed an action styled Petro Capital III, LP v. Miller Petroleum, Inc., Civil Action No. 3:10-cv-00606P in the United States District Court for the Northern District of Texas, Dallas Division, seeking damages for breach of contract; damages for alleged negligent misrepresentation; a declaratory judgment regarding the proper number of and exercise price of the original warrants to which Petro Capital is entitled under a warrant and registration rights agreement, the number of penalty warrants to which Petro Capital may be entitled under a warrant and registration rights agreement, as well as the proper exercise price thereof, and damages resulting from the alleged breach of contract; and attorney’s fees. On April 6, 2010, Petro Capital filed an Amended Complaint that did not include additional causes of action. We filed an Answer and Counterclaim on April 28, 2010. The Counterclaim seeks a declaratory judgment to declare void the issuance of any penalty warrants after May 4, 2007 (the latest date upon which the shares underlying the warrants would become freely tradable under Rule 144). The Counterclaim further seeks a declaratory judgment as to the number of shares and proper exercise price for the original warrant.
We are also party to various routine legal proceedings arising in the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.
ITEM 4.
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ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Since May 6, 2010 our common stock has been listed on the NASDAQ Global Market under the symbol “MILL.” Previously, our common stock was quoted on the OTC Bulletin Board and in the over the counter market on the Pink Sheets. The reported high and low sales prices for the common stock as reported on the various markets on which our stock was quoted during the periods indicated are shown below. The quotations reflect inter-dealer prices, without retail mark-up, markdown or commission, and may not represent actual transactions.
|
| High |
| Low |
| ||
2008 |
|
|
|
|
|
|
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First quarter ended July 31, 2007 |
| $ | 0.49 |
| $ | 0.25 |
|
Second quarter ended October 31, 2007 |
| $ | 0.34 |
| $ | 0.02 |
|
Third quarter ended January 31, 2008 |
| $ | 0.10 |
| $ | 0.04 |
|
Fourth quarter ended April 30, 2008 |
| $ | 0.22 |
| $ | 0.09 |
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|
|
|
|
|
|
|
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2009 |
|
|
|
|
|
|
|
First quarter ended July 31, 2008 |
| $ | 0.54 |
| $ | 0.10 |
|
Second quarter ended October 31, 2008 |
| $ | 0.51 |
| $ | 0.15 |
|
Third quarter ended January 31, 2009 |
| $ | 0.40 |
| $ | 0.15 |
|
Fourth quarter ended April 30, 2009 |
| $ | 0.40 |
| $ | 0.15 |
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|
|
|
|
|
|
|
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2010 |
|
|
|
|
|
|
|
First quarter ended July 31, 2009 |
| $ | 0.38 |
| $ | 0.22 |
|
Second quarter ended October 31, 2009 |
| $ | 0.70 |
| $ | 0.28 |
|
Third quarter ended January 31, 2010 |
| $ | 2.95 |
| $ | 0.60 |
|
Fourth quarter ended April 30, 2010 |
| $ | 6.60 |
| $ | 1.95 |
|
On July 22, 2010, the last sale price of our common stock as reported on the NASDAQ Global Market was $5.66. As of July 22, 2010, there were approximately 400 record owners of our common stock.
Dividend Policy
We have never paid cash dividends on our common stock and we do not anticipate that we will declare or pay dividends in the foreseeable future. Payment of dividends, if any, is within the sole discretion of our Board of Directors and will depend, among other factors, upon our earnings, capital requirements and our operating and financial condition. In addition under Tennessee law, we may not pay a dividend if, after giving effect, we would be unable to pay our debts as they become due in the usual course of business or if our total assets would be less than the sum of our total liabilities plus the amount that would be needed if we were to be dissolved at the time of the payment of the dividend to satisfy the preferential rights upon dissolution of shareholders whose preferential rights
ITEM 6.
SELECTED FINANCIAL DATA.
Not applicable to a smaller reporting company.
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ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We are an independent exploration and production company that utilizes seismic data, and other technologies for geophysical exploration and development of oil and gas wells in the Appalachian region of eastern Tennessee and the Cook Inlet Basin in south central Alaska. In addition to our engineering and geological capabilities, we provide land drilling services on a contract basis to customers primarily engaged in natural gas exploration and production.
During fiscal 2009 and 2010, we completed several transactions which we believe had both a positive impact on our balance sheet and will assist us in our continued growth. These transactions, which are described in detail earlier in this annual report under Item 1. Business - Our history included the following:
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sale of leases and wells to Atlas Energy Recourses, LLC,
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settlement of Wind City litigation,
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acquisition of assets from Ky-Tenn Oil, Inc.,
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acquisition of East Tennessee Consultants,
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acquisition of Cook Inlet Energy LLC in Alaska, and
·
acquisition of Alaskan assets of Pacific Energy Resources.
As a result of the aforedescribed acquisitions, we presently have approximately 662,992 acres of gross oil and gas leases and exploration license rights (616,550 net acres), which includes 471,474 acres under the Susitna Basin Exploration License. The terms of these new leases have a net revenue interest ranging from 0.1% to 100.0% and run from three to five years. We are presently reviewing these leases, as well as our other existing leases, to determine the capital requirements and timing for drilling additional wells. We plan to drill five new wells in the next 12 months. As a part of our fiscal 2008 sale to Atlas Energy, we retained a 5% royalty interest on a 1,930 acre tract that we expect to be the subject of Atlas Energy drilling.
With the closing of these transactions, our management is now able to focus the majority of its efforts on growing our company. In addition to raising capital we are also continuing to focus our short-term efforts on three distinct areas, including the following:
·
Increase our overall oil and gas production through maintenance and repairs of nonperforming or underperforming wells,
·
Organically growing production through drilling for our own benefit on existing leases and under license rights, leveraging our 100,000 plus well log database and over 660,000 acres which are either under lease or part of the Susitna Basin Exploration License, with a view towards retaining the majority of working interest in the new wells, and
·
Expanding our contract drilling and service capabilities and revenues, including drilling and service contracts with third parties.
Our ability, however, to implement one or more of these goals is dependent upon the availability of additional capital. To fully expand our operations as set forth above, we will need up to $75 million to $100 million to fund the balance of our expansion plans, including up to approximately $67.4 million associated with obligations arising from our purchase of the Alaskan assets to provide the required capital, we are seeking to leverage our existing assets as well as raise additional capital through the sale of equity and/or debt securities. We do not have any firm commitments for the additional capital we need to fully fund our operations and there are no assurances the capital will be available to us upon terms acceptable to us, if at all. While we are actively seeking to secure the additional capital, terms of the Securities Purchase Agreement for our March 2010 unit offering contain restrictive covenants which may adversely impact our ability to raise additional capital during the 12 months following the effective date of a registration statement we are obligated to file with the SEC. If we are not able to raise the capital as required, we will be unable to fully implement our expanded business model, and the State of Alaska could terminate the leases which comprise substantially all of our Cook Inlet Basis assets.
29
Results of Operations
Our fiscal year end is April 30. The year ended April 30, 2010 is referred to as “fiscal 2010”, the year ended April 30, 2009 is referred to as “fiscal 2009” and the year ending April 30, 20011 is referred to as “fiscal 2011.” When used in the following tables, “NM” means not meaningful.
Fiscal 2010 as compared to fiscal 2009.
The following table shows the components of our revenues for fiscal 2010 and 2009, together with their percentages of total revenue in each year and percentage change on a year-over-year basis.
|
|
| For the Year Ended April 30, |
|
|
|
| |||||||||
|
| 2010 ($) |
| % of Revenue |
| 2009 ($) |
| % of Revenue |
| Change |
| |||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue |
|
| 4,437,215 |
|
| 76 | % |
| 640,094 |
|
| 41 | % |
| +593 | % |
Service and drilling revenue |
|
| 1,429,789 |
|
| 24 | % |
| 927,210 |
|
| 59 | % |
| +54 | % |
Total revenues |
|
| 5,867,004 |
|
| 100 | % |
| 1,567,304 |
|
| 100 | % |
| +274 | % |
Oil and gas revenue represents revenues generated from the sale of oil and natural gas produced from the wells in which we have a partial ownership interest. Oil and gas revenue is recognized as income as production is extracted and sold. We reported a 593% increase in oil and gas revenues for fiscal 2010 over 2009. The increase was primarily due to the addition of the Alaskan oil well production during fiscal 2010 which accounted for revenues of approximately $3,621,881 for year then ended. In addition, we produced 122,015 Mcf of gas in fiscal 2010 in Alaska but we did not sell this as substantially all was used in our Alaska oil production.
Our increase in oil and gas revenue from fiscal 2009 to 2010 was primarily due to production and sales from the Alaska acquistion as well as increased oil and gas prices. For example, at April 30, 2010 oil was priced at $86.07 per barrel versus $50.35 at April 30, 2009 and at April 30, 2010 natural gas was $3.92 Mcf as compared to $3.37 per Mcf at April 30, 2009. In addition, we had 188 producing oil wells and 337 producing gas wells on April 30, 2010 compared to 20 producing oil wells and 32 producing gas wells on April 30, 2009. For fiscal 2010 we produced 63,002 barrels of oil and 154,291Mcf of natural gas as compared to 4,580 barrels of oil and 50,073 Mcf of natural gas during fiscal 2009.
Service and drilling revenue represents revenues generated from drilling, maintenance and repair of third party wells. Service and drilling income is recognized at the time it is both earned and we have a contractual right to receive the revenue. Our service and drilling revenue increased 54% for fiscal 2010 as compared to fiscal 2009. During fiscal 2010 we drilled 10 wells for Atlas Energy Resources, LLC, which compares to six wells drilled for them for fiscal 2009.
Direct Expenses
The following table shows the components of our direct expenses for fiscal 2010 and 2009. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.
|
| For the Year Ended April 30, |
| ||||||||||
|
| 2010 ($) |
| Margin |
|
| 2009 ($) |
| Margin |
| |||
Direct Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas |
|
| 2,583,384 |
|
| 42 | % |
| 240,389 |
|
| 62 | % |
Service and drilling |
|
| 1,342,509 |
|
| 6 | % |
| 1,184,901 |
|
| (28 | )% |
Depletion expense |
|
| 1,741,150 |
|
| NM |
|
| 221,465 |
|
| NM |
|
Total direct expenses |
|
| 5,667,043 |
|
| 3 | % |
| 1,646,755 |
|
| (5 | )% |
The cost of oil and gas revenues were $2,583,384 for fiscal 2010 which reflected a gross profit of $1,853,831 and a gross profit margin of 42% as compared to a gross profit of $399,705 and a gross profit margin of 62% for fiscal 2009. We follow the successful efforts method of accounting for our oil and gas activities. Accordingly, costs associated with the acquisition, drilling and equipping of successful exploratory wells are capitalized. During fiscal 2010 we capitalized approximately $376,216,621 of costs primarily associated with the recent Alaska acquisition as previously discussed, but also with drilling and equipping of wells as compared to $975,992 during fiscal 2009. During fiscal 2009 we acquired leases for 5,007 acres for approximately $666,000 and
30
spent $270,644 on drilling and equipping three existing wells. However, geological and geophysical costs, delay and surface rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred and are included in the cost of service and drilling revenue. Finally, costs of drilling development wells are capitalized. Upon the sale or retirement of oil and gas properties, the cost thereof and the accumulated depreciation or depletion are removed from the accounts and any gain or loss is credited or charged to operations.
The cost of service and drilling revenue represents direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs. Fiscal 2010 showed $1,342,509 for this component, up 13% from $1,184,901 in fiscal 2009. This represented a profit of $87,280 or 6% for fiscal 2010 compared to a loss of $257,691 or 28% loss for fiscal 2009. As previously discussed, while drilled 10 wells for Atlas Energy during fiscal 2010 and only six wells during fiscal 2009, in preparation for the Atlas Energy drilling contract we spent significant time and expense maintaining and repairing our drilling equipment in fiscal 2009 which contributed to the loss for that year.
Depletion of capitalized costs of proved oil and gas properties is provided on a pooled basis using the units-of-production method based upon proved reserves. Acquisition costs of proved properties are amortized by using total estimated units of proved reserves as the denominator. All other costs are amortized using total estimated units of proved developed reserves. During fiscal 2010 depletion expense was $1,741,150 or 30% of total revenue, as compared to $221,465 or 14% of total revenue for fiscal 2009. The primary reason for the increase in depletion expense for fiscal 2010 was the addition of wells as a result of the acquisitions. As a result of these components, total direct expenses were $5,667,043, which reflected a profit of $199,961 and a profit margin of 3% for fiscal 2010. This compares to a loss of $79,451 which was a negative profit margin of 5% experienced for fiscal 2009.
Total Costs and Expenses and Total Other Income (Expense)
The following table shows the components of certain of our costs and expenses and certain of our total other income (expenses) for fiscal 2010 and 2009. Percentages listed in the table reflect percentages of total revenue for each component of other expenses.
|
| For the Year Ended April 30, |
| ||||||||||
|
| 2010 ($) |
| % of Revenue |
| 2009($) |
| % of Revenue |
| ||||
Selling, general and administrative |
|
| 10,345,217 |
|
| 176 | % |
| 2,712,943 |
|
| 173 | % |
Depreciation and amortization |
|
| 968,158 |
|
| 17 | % |
| 427,605 |
|
| 27 | % |
Interest expense, net of interest income |
|
| 501,739 |
|
| 9 | % |
| 24,785 |
|
| 2 | % |
Loss on derivative securities |
|
| 15,861,007 |
|
| NM |
|
| — |
|
| — |
|
Loan fees and costs |
|
| 741,309 |
|
| 13 | % |
| 124,085 |
|
| 8 | % |
Loss (gain) on sale of equipment |
|
| 9,755 |
|
| NM |
|
| (10,450 | ) |
| NM |
|
Gain on sale of oil and gas properties |
|
| — |
|
| — |
|
| (11,715,570 | ) |
| 747 | % |
Gain on acquisitions |
|
| (461,111,924 | ) |
| >1,000 | % |
| — |
|
| — |
|
Total other expense (revenues) |
|
| (432,684,739 | ) |
| >1,000 | % |
| (8,436,602 | ) |
| 538 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling, general and administrative expense includes salaries, general overhead expenses, insurance costs, professional fees and consulting fees. The increase of $7.6 million for fiscal 2010 as compared to fiscal 2009 primarily reflects costs associated with the addition of our acquisitions during fiscal 2010 in Alaska and Tennessee, which included an increases in fund raising expenses of $2.7 million, employee related expenses of $0.8 million, office related expenses of $0.7 million, taxes other than income of $0.3 million and travel related expenses of $0.2 million. In addition, an additional $1.7 million was recorded as compensation expense during fiscal 2010, which reflected the cost of options and warrants issued to various employees and directors. Also, during fiscal 2010, we wrote off $666,476 of prepaid offering costs associated with Miller Rig & Equipment, LLC and Miller Energy Drilling 2009-A, LP. Both offerings associated with these companies ended in December, 2009 and no funds were raised.
Depreciation and amortization expenses reflect the usage of our fixed assets over time. The increase in depreciation and amortization for fiscal 2010 as compared to fiscal 2009 reflects an increase in the amount of depreciation due to the Alaskan assets purchased. These non-cash expenses will continue at this higher level as the Alaska assets are being depreciated over a range of 30 to 40 years.
31
We recorded a non-cash loss on derivative securities for fiscal 2010 of $15,861,007 relating to the change in fair value of derivative instruments during fiscal 2010. This was comprised of three transactions, 3,000,000 warrants issued in the current and past years, which are subject to an ongoing litigation matter, 716,715 warrants issued in an equity financing in March 2010 and 300,000 warrants issued pursuant to a consulting arrangement in March 2010. We utilized the Black-Scholes pricing model to calculate the expense. The fair value of the warrants issued and outstanding at May 1, 2009, attributed to this derivative liability has been determined to be immaterial due to the low stock price in comparison to the exercise price, hence there was no adjustment to make for fiscal 2009.
Loan fees and costs of $741,309 for fiscal 2010, primarily represent non-cash expenses related to the fair value of warrants issued to new investors as an incentive to invest in the MEI partnership as well as expenses related to the fair value of warrants owned in connection with a prior financing transaction.
During fiscal 2009 we recorded a one-time gain of $11,715,570 on the sale of the oil and gas leases to Atlas Energy and the concurrent settlement of the Wind City litigation as described elsewhere herein. As a result of the one-time settlement transaction, we reported net income of $8,356,373 for fiscal 2009.
During fiscal 2010, we recorded a gain on acquisitions of $461,111,924. This was primarily due from the Alaskan acquisition as previously discussed. As a result of this non-cash gain, for fiscal 2010 we recorded net income of $249,453,180, an increase of $241,096,807 over fiscal 2009.
We do not anticipate recording similar gains on acquisitions in future periods.
Liquidity and capital resources
Liquidity is the ability of a company to generate adequate amounts of cash to meet the enterprise's needs for cash. At April 30, 2010 we had a working capital surplus of $338,110 as compared to a working capital deficit of $313,565 at April 30, 2009. This increase in capital surplus is primarily due to increased cash provided from financing activities, while partially offset by cash used by operating activities.
From April 30, 2009 to April 30, 2010, cash increased from $46,566 to $2,750,841. This increase was primarily due from the cash raised through net equity sales of $9,646,478 and proceeds of borrowings of $5,926,444 which were raised during fiscal 2010, partially offset by the funds required for the Alaska oil and gas assets. Other asset categories increased significantly due to the Alaska transaction. Fixed assets increased $111.1 million from April 30, 2009 to April 30, 2010 as new assets booked for Alaska were $110.5 million. Oil and gas properties increased $374.4 million during this time as well, as $368.0 million of the increase was due to the addition of Alaska reserves. Deferred income taxes payable rose to $184.5 million on April 30, 2010 from $778 on April 30, 2009, primarily due to the recording of the Alaska transaction. The Alaska transaction also contained a one-time gain of $277.2 million which is reflected in the $275.7 million stockholders’ equity recorded at April 30, 2010 as compared to $7.2 million recorded on April 30, 2009.
We do not presently have any commitment for capital expenditures other than related to the Osprey platform and onshore assets as described below. However, as set forth earlier in this section we require a substantial amount of capital to fund our other obligations associated with the acquisition of the Alaskan assets.
Under the terms of the purchase agreement for the Alaskan assets and the Assignment Oversight Agreement, Cook Inlet Energy assumed all liabilities related to the plugging, abandonment, decommissioning, removal and/or restoration liabilities associated with or arising from the acquired assets with respect to all periods prior to, on or after the closing date. Under the terms of the purchase agreement for the Alaskan assets, these assumed liabilities include approximately $10 million for the onshore assets and approximately $40 million associated with a retirement liability for the Osprey platform, of which approximately $6.6 million is presently on deposit in an escrow fund with the State of Alaska. We are presently in discussion with the State of Alaska to reduce these amounts to levels we believe are more realistic. During the fourth quarter of 2010 we accrued approximately $15.0 million for these liabilities, which includes approximately $3.5 million for the onshore assets and approximately $10.0 million for the Osprey platform. We are also seeking to obtain confirmation from the State of Alaska that the $6.6 million, currently in the escrow account is specifically allocated to the Osprey platform.
32
Cash flows
Net cash used by operating activities for fiscal 2010 was $2,160,152. This primarily reflects the cash paid for the costs of revenues and selling, general and administrative expense in excess of revenues received for the period, which included the gain from the Alaska transaction, but partially offset by the issuance of equity for services, compensation and financing costs of $3,892,886.
Net cash used by operating activities in fiscal 2009 was $1,721,122. This primarily reflects the cash paid for the costs of revenues and selling, general and administrative expense in excess of revenues received for the period, which included the gain from the sale of oil and gas properties, but partially offset by the issuance of equity for services, compensation and financing costs of $1,605,994.
Net cash used by investing activities for fiscal 2010 of $10,476,830 is primarily due to the cash we paid for the Alaska assets of $4,541,252 and the purchase of oil and gas properties of $5,600,843, which were primarily costs associated with well start ups.
Net cash provided by investing activities of $6,760,273 in fiscal 2009 reflects the net cash we received from the Atlas Energy transaction of $12,519,713, partially offset by the purchase of additional drilling equipment and vehicles of $4,408,998 and funds used for the purchase of a lease and capitalized costs associated with the purchase of oil and gas properties of $1,268,942.
Net cash provided by financing activities of $15,341,257 for the fiscal 2010 primarily reflects the net cash received from the sale of stock of $9,646,478, proceeds received from borrowings of $5,926,444, a $1,856,488 decrease in restricted cash due to payoff of a bank financing, and cash acquired through acquisitions of $203,993, which was partially offset by payments on notes payable of $2,309,205.
Net cash used in financing activities of $5,035,021 for fiscal 2009 primarily reflects the repurchase of 2,900,000 shares of our common stock from Wind Mill for $4,350,000 due to the settlement of Wind Mill litigation as discussed elsewhere here. In addition, we used cash to pay off certain notes payable of $726,630 during fiscal 2009.
Loan Commitment from Vulcan Capital Corporation, LLC
On November 5, 2009 we entered into a letter agreement with Vulcan Capital Corporation, LLC which memorialized the terms of our agreement with Vulcan Capital Corporation to provide us with a financial debt package for the specific requirements of our acquisition of Cook Inlet Energy and the Alaskan assets of Pacific Energy Resources. Mr. Ford Graham, the President of Vulcan Capital Corporation, LLC, is a former executive officer and director of our company. This November 2009 agreement superseded an earlier October 2009 letter agreement and provided for an increased debt commitment from $5.5 million to $36.5 million. Under the terms of this letter agreement, Vulcan Capital Corporation has agreed to lend us not less than $36.5 million at the closing of these transactions. Both of these transactions, which closed in December 2009, are described earlier in this annual report under Item 1. Business - Our history. The terms of the proposed debt included the following:
·
a senior secured status on all Cook Inlet Energy assets acquired by us,
·
the use of proceeds from the loan is limited to the Assignment Oversight Agreement between Cook Inlet Energy and the State of Alaska
·
a three year term, with a prepayment penalty, and 10% per annum interest
·
interest only for 24 months, principal due as a bullet,
·
there will be no sinking fund established, we will be unable to pay dividends before the debt is repaid and there will be certain unspecified negative covenants,
·
we will grant Vulcan Capital Corporation warrants exercisable at $0.01 per share equal to 10% of the total debt package,
·
Vulcan Capital Corporation will have a right of first refusal for all other of our debt and/or equity requirements with regard to these acquired assets and any other of our Alaskan business activities,
·
Vulcan Capital Corporation or its assignee will be provided with one Board seat during the term of the loan,
33
·
the documents will contain customary representations and warranties and we will indemnify Vulcan Capital Corporation; and
·
we will pay all fees and expenses at closing.
The assets identified in the letter agreement include all properties and operations regarding specific State of Alaska oil and gas leases, wells, all associated infrastructures, including the Osprey platform and its subsea pipelines, and all associates agreements held by Pacific Energy Resources including the $6.7 million Redoubt escrow fund. The letter agreement provides that Vulcan Capital Corporation will provide us this debt through it newly created special purpose vehicle, Vulcan Miller Alaska Energy, LLC. In preparation of the transaction, Vulcan Capital Corporation placed cash or cash equivalents of over $5 million into Vulcan Miller Alaska Energy’s separate account and agreed to leave the account and its assets unencumbered until closing of the transaction, at which time it is to deliver the funds to us for our sole and exclusive use for the assigned leases. The balance of the funds are to be provided to us upon demand. Under the terms of the letter agreement, upon acceptance by us Vulcan Capital Corporation was to deliver to us senior loan documents for execution to close this transaction. We accepted the letter agreement on November 5, 2009, however we have not proceeded towards a closing of the financing arrangement. We have subsequently been advised by Vulcan Capital Corporation that the amount previously deposited in the Vulcan Miller Alaska Energy, LLC account has been transferred from the account and is no longer available. We have utilized a portion of the funds we raised in private placements to fund approximately $5.15 million of the anticipated use of proceeds of the Vulcan Capital Corporation commitment as we believed the terms of those financings were more advantageous to us. As we have not yet begun working on the Redoubt Unit which represents the balance use of proceeds from the Vulcan Capital Corporation commitment, while the commitment remains available to us, we intend to seek to obtain alternative financing upon terms which are more advantageous to us than the Vulcan Capital Corporation commitment. Our ability however to obtain this financing is limited by the terms of the March 2010 unit offering as described elsewhere herein.
Recent Financing Transactions
In order to finance the expansion of our operations into Alaska and to provide capital to us for our other operations, we entered into the following financing transactions:
·
On November 1, 2009 we borrowed $2,365,174 from Miller Energy Income 2009-A, LP ("MEI”), a limited partnership of which our wholly-owned subsidiary, Miller Energy GP, LLC, is the general partner. Under the four year secured promissory note we issued MEI to evidence this loan, interest is payable at the rate of 12% per annum, with interest only payments due monthly. On December 15, 2009 we borrowed an additional $356,270 from MEI and issued it a second, four year secured promissory note which also pays interest at the rate of 12% per annum with interest only payments due monthly. In connection with these loans, we granted MEI a first priority security interest in oil and gas drilling equipment owned by us. Pursuant to the terms of an escrow agreement, a third-party escrow agent has been retained to hold the certificates of title for the collateral to which title is evidenced by a certificate. The remaining equipment is subject to a financing statement that has been filed with the Tennessee Secretary of State. We used the proceeds from these loans for general corporate purposes including reducing outstanding debt and to partially fund the Alaska transaction.
·
In December 2009 we issued $2,855,000 principal amount 6% convertible secured promissory notes to provide funds for the Alaskan asset transaction. Included in the sales of these notes was an aggregate of $500,000 purchased by Messrs. Scott Boruff, our Chief Executive Officer and a member of our Board of Directors, and Mr. Deloy Miller, members of our Board of Directors. We paid a finder’s fee of $20,000. Interest on the notes is paid quarterly and the principal is due December 4, 2016. Holders of $1,150,000 principal amount of these notes, including Messrs. Boruff and Miller, have subsequently converted those notes into an aggregate of 2,090,909 shares of our common stock. As of June 30, 2010, notes in the aggregate principal amount of $1,375,000 remain outstanding. The notes contain a convertible feature which the note holder has the right, but not the obligation, at the holder's option, at any time prior to payment in full of the principal balance of the note, to convert the unpaid principal amount of the note, in whole or in part, into fully paid and non-assessable shares of our common stock at the conversion price of $0.55 per share. We granted the note holders a lien on and security interest in property, assets and rights including, but not limited to, all of our mineral rights and oil and gas assets and all proceeds from those assets in the 35,325 leased acres located in
34
Morgan and Scott Counties on the Chattanooga Shale and the 173 natural gas and oil producing wells.
·
Between December 2009 and January 2010 we sold 6,015,000 shares of our common stock in private transactions to accredited investors for $1.00 per share. This was a discount of 16.67% from market value on the date of determination. We received $5,657,000 in net cash proceeds from this offering, after payment of offering costs, commissions and finder’s fees, which was used for general corporate purposes, including reducing debt and partially financing the Alaska asset acquisition. We paid Sutter Securities Incorporated, a FINRA member firm, cash compensation of $200,000 as well as the non- accountable sum of $10,000 for its legal fees and expenses and issued it five-year warrants to purchase an aggregate of 280,000 shares of our common stock at exercise prices ranging from $1.35 to $1.815 per share. We also paid finder’s fees of $123,000 and issued five-year warrants to purchase an aggregate of 52,500 shares of our common stock at exercise price of $1.35 per share. In addition, we paid Seaside 88 Advisors, LLC, the general partner of one of the purchasers of the shares, the non-accountable sum of $25,000. The warrants are exercisable on a cashless basis. If we make any subsequent sales of our securities within one year to any purchaser introduced to us by Sutter Securities Incorporated, we are obligated to pay that firm a finder’s fee on those sales. Under the terms of the Securities Purchase Agreements we agreed that until 12 months from the closing date, if in connection with a Subsequent Financing (as defined in the Securities Purchase Agreement), either our company or any of our subsidiaries should issue any common stock or common stock equivalents entitling any person or entity to acquire shares of common stock at an effective price per share less than the per share purchase price of $1.00 (subject to reverse and forward stock splits and the like), that we will issue to the purchaser of this current stock sale, a number of additional shares of common stock to the aforementioned purchasers to prevent the follow-on investment from being a dilutive issuance (see the attachment for more specific details). If shares are issued for a consideration other than cash, the per share selling price shall be the fair value of such consideration as determined in good faith by the Board of Directors. We also granted the purchasers of stock certain piggy back registration rights until such time as the purchasers are able to resell the shares of common stock purchased in the offering pursuant to Rule 144 of the Securities Act until the requirement for adequate public information on our company is no longer applicable.
·
On March 26, 2010, we executed a Securities Purchase Agreement pursuant to which at closing we agreed to sell units of our securities, including 1,433,432 shares of our common stock at a purchase price of $3.50 per share and five year warrants to purchase an additional 716,716 shares of common stock with an exercise price of $5.28 per share to 14 accredited and/or institutional purchasers. This offering closed on April 1, 2010. We received gross proceeds $5,017,002. Sutter Securities Incorporated, a broker-dealer and member of FINRA, acted as finder for us in this unit offering. Under the terms of a Finder’s Agreement with the firm, we paid Sutter Securities Incorporated a fee of $346,190 and issued the firm five-year common stock purchase warrants to purchase an aggregate of 100,339 shares of our common stock at an exercise price of $5.28 per share. In addition, we paid a finder’s fee of $5,000 to Viriathus Capital LLC and paid the attorney for Sutter Securities Incorporated legal expenses totaling $10,000 incurred in the preparation of the various transactional documents. We are using the net proceeds of this offering for general working capital.
The Securities Purchase Agreement for the March 2010 unit offering provides that until September 26, 2010 any securities sold in the offering are subject to a per share price protection. In the event we were to issue any shares of common stock, or securities convertible into or exercisable for shares of common stock, to any third party purchaser at a purchase price or exercise price per share which is less than $3.50 per share, or less than the exercise price of $5.28 per warrant share (collectively, the “Discounted Per Share Purchase Price”), we will automatically issue additional shares of our common stock to the purchasers in the March 2010 unit offering without the payment of any additional consideration by those purchasers. The number of shares we may be obligated to issue will be equal product of:
·
the fraction obtained by dividing (A) the sum of the number of initial shares and any additional shares we may have already issued the purchasers under the terms of the Securities Purchase Agreement then held by the purchasers on the date of the dilutive issuance by (B) the sum of the number of initial shares issued to the purchasers on the closing date and all additional shares issued to the purchasers after the closing date,
35
multiplied by
·
the difference between the aggregate number of shares of common stock that would have been issued to the purchasers at the closing if the subscription amount of $3.50 per share was divided by the Discounted Per Share Purchase Price minus the aggregate number of shares of common stock equal to the sum of the initial shares, plus, to the extent there has been a previous issuance of additional shares to the purchasers, the number of additional shares previously issued to the purchasers.
In implementing this per share price protection, to the extent that an issuance of additional shares would result in a purchaser or any of its affiliates beneficially owning in excess of 4.99% of our common stock, then we will initially issue only a number of additional shares that would result in a purchaser (together with the purchaser’s affiliates) beneficially owning 4.99% of our common stock. After this initial issuance, and until all additional shares which otherwise would have been issued under this per share price protection would have been issued, from time to time we will issue a number of the unissued additional shares so that the purchaser (together with the purchaser’s affiliates) will beneficially own only 4.99% of our common stock.
We agreed under the terms of the Securities Purchase Agreement that we would not offer or sell any shares of common stock until six months from the effective date of the registration statement we are obligated to file as described below. In addition, we agreed that so long as the purchasers own any of our securities purchased in the March 2010 unit offering, we would not enter into any agreement for the issuance or sale by us or any of our subsidiaries of any common stock or common stock equivalent for cash in a variable rate transaction nor would we enter into any form of equity line of credit. Generally, a variable rate transaction means a transaction in which we sell securities which are convertible or exercisable into shares of our common stock at a price that varies based upon the market price of our common stock or contains a price reset provision.
Finally, under the terms of the Securities Purchase Agreement we agreed that until one year after the effective date of the registration statement we are obligated to file:
·
that if we or any of our subsidiaries issue any common stock or common stock equivalents for cash, debt or a combination of cash and debt, purchasers in the offering would have a right to participate in this subsequent financing in an amount equal to 100% of any subsequent financing, and upon the same terms and conditions and at a price as may be contemplated by this subsequent financing; and
·
we would not undertake a forward or reverse stock split or a reclassification of our common stock without the prior written consent of the purchasers holding a majority in interest of the shares sold in the offering.
The terms of the warrants issued to the purchasers in the offering, as well as the compensatory warrants issued to Sutter Securities Incorporated, are identical and provide that the number of shares issuable upon the exercise of the warrants, as well as the exercise price of the warrants, is subject to proportional adjustment in the event of stock splits, stock dividends, recapitalizations and similar corporate events. The warrants are exercisable on a cashless basis. The warrants are not exercisable to the extent that (i) the number of shares of our common stock beneficially owned by the holder and (ii) the number of shares of our common stock issuable upon the exercise of the warrants would result in the beneficial ownership by holder of more than 4.99% of our then outstanding common stock. This provision may be waived upon 61 days notice to us; provided, however, that the beneficial ownership limitation can in no event exceed 9.99% of the number of shares of the common stock outstanding immediately after giving effect to the issuance of shares of common stock upon exercise of the warrant.
So long as the warrants are outstanding, if we should issue or sell any common stock or common stock equivalent, or grant any option to purchase any of our common stock or common stock equivalents, at a price less than the then exercise price, we will automatically reduce the exercise price of the warrants and the number of shares of common stock issuable upon the exercise of the warrants will be automatically increased so that the aggregate exercise price payable upon the exercise of the warrant, after taking into account the decrease in the exercise price, will be equal to the aggregate exercise price prior to the adjustment. In addition, while the warrant is outstanding, if we should issue or sell any common stock or common stock equivalent, or grant any option to purchase any of our common stock or common stock equivalents, at a price less than the daily volume weighted average of our common stock (the “VWAP”) on the record date of the proposed transaction, then we will automatically adjust the exercise price of the warrants by multiplying it by a fraction, with the denominator being the number of shares of the common stock outstanding on the date of issuance of such rights, options or warrants
36
plus the number of additional shares of common stock offered for subscription or purchase, and the numerator being be the number of shares of the common stock outstanding on the date of issuance of such rights, options or warrants plus the number of shares which the aggregate offering price of the total number of shares offered would purchase at the VWAP.
Under the terms of the Registration Rights Agreement entered into with the purchasers in the March 2010 unit offering, we were obligated to file a registration statement with the SEC covering the shares of common stock issued and sold in the offering, as well as the shares of common stock underlying the warrants, on or before April 15, 2010 so as to permit the public resale thereof. We have not yet filed the registration statement. We agreed to use our best efforts to cause the registration statement to be declared effective by the SEC within 90 days from the filing date or 120 days if the registration statement should be selected for a full review by the staff of the SEC. The registration rights agreement provides that if we failed to timely file the registration statement, or if it should not be declared effective within the prescribed time, we are subject to liquidated damages payable in cash equal to 2% of the aggregate purchase price of the securities up to a maximum of 12% of the total proceeds of the offering. Because we did not timely file the registration statement, we began accruing liquidated damages during the fourth quarter of 2010.
Modernization of Oil and Gas Reporting
In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as "Modernization of Oil and Gas Reporting" and include provisions that do the following:
·
introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.
·
report oil and gas reserves using an un-weighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.
·
permit companies to disclose their probable and possible reserves on a voluntary basis. Prior rules limited disclosure to only proved reserves.
·
update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include "by geographic area" and "reasonable certainty."
·
permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
·
require additional disclosures regarding the qualifications of the chief technical person who oversees its overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company's reserves preparer or auditor based on Society of Petroleum Engineers criteria.
We began complying with the disclosure requirements in this annual report on Form 10-K.
Off Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that we are required to disclose pursuant to these regulations. In the ordinary course of business, we enter into operating lease commitments, purchase commitments and other contractual obligations. These transactions are recognized in our financial statements in accordance with generally accepted accounting principles in the United States.
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Critical Accounting Policies
General
The preparation of financial statements requires management to utilize estimates and make judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. These estimates are based on historical experience and on various other assumptions that management believes to be reasonable under the circumstances. The estimates are evaluated by management on an ongoing basis, and the results of these evaluations form a basis for making decisions about the carrying value of assets and liabilities that are not readily apparent from other sources. Although actual results may differ from these estimates under different assumptions or conditions, management believes that the estimates used in the preparation of our financial statements are reasonable. The critical accounting policies affecting our financial reporting are summarized in Note 1 to the consolidated financial statements included in this annual report. Policies involving the most significant judgments and estimates are summarized below.
Impact of Derivative Accounting
As a result of recent financing transactions we have entered into, our financial statements for the year ended April 30, 2010 and future periods have and will be impacted by the accounting effect of the application of derivative accounting. The application of EITF 07-05 “Determining Whether an Instrument (or Embedded Feature) is Indexed to a Company's Own Stock,” which was effective on January 1, 2009 will significantly affect the application of ASC Topic 815 and ASC Topic 815-40 for both freestanding and embedded derivative financial instruments in our financial statements. Generally, warrants, conversion features in debt, and similar terms that include “full-ratchet” or reset provisions, which mean that the exercise or conversion price adjusts to pricing in subsequent sales or issuances, no longer meet the definition of indexed to a company's own stock and are not exemption for equity classification provided in ASC Topic 815-15. This means that instruments that were previously classified in equity are reclassified to liabilities and ongoing measurement under ASC Topic 815. The amount of quarterly non-cash gains or losses we will record in future periods will be based upon the fair market value of our common stock on the measurement date.
Estimates of Proved Reserves and Future Net Cash Flows
Estimates of our proved oil and gas reserves and related future net cash flows are used in impairment tests of goodwill and other long-lived assets. These estimates are prepared as of year-end by independent petroleum engineers and are updated internally at mid-year. There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of any reserve estimate is dependent on the quality of available data and is subject to engineering and geological interpretation and judgment. Results of our drilling, testing and production after the date of these estimates may require future revisions, and actual results could differ materially from the estimates.
Impairment of Long-Lived Assets
Our long-lived assets include property, equipment and goodwill. Long-lived assets with an indefinite life are reviewed at least annually for impairment, and all long-lived assets are reviewed whenever events or changes in circumstances indicate that their carrying values may not be recoverable.
Oil and Gas Activities
We follow the successful efforts method of accounting for our oil and gas activities. Accordingly, costs associated with the acquisition, drilling and equipping of successful exploratory wells are capitalized. Geological and geophysical costs, delay and surface rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. Costs of drilling development wells are capitalized. Upon the sale or retirement of oil and gas properties, the cost thereof and the accumulated depreciation or depletion are removed from the accounts and any gain or loss is credited or charged to operations.
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Depreciation, Depletion and Amortization
Depreciation, depletion and amortization of capitalized costs of proved oil and gas properties is provided on a pooled basis using the units-of-production method based upon proved reserves. Acquisition costs of proved properties are amortized by using total estimated units of proved reserves as the denominator. All other costs are amortized using total estimated units of proved developed reserves.
Fair Value of Financial Instruments
Effective May 1, 2008, we adopted guidance issued by the FASB on "Fair Value Measurements" for assets and liabilities measured at fair value on a recurring basis. This guidance establishes a common definition for fair value to be applied to existing generally accepted accounting principles that require the use of fair value measurements, establishes a framework for measuring fair value, and expands disclosure about such fair value measurements. The adoption of this guidance did not have an impact on our financial position or operating results, but did expand certain disclosures.
The FASB defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Additionally, the FASB requires the use of valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
These inputs are prioritized below:
Level 1: |
| Observable inputs such as quoted market prices in active markets for identical assets or liabilities. |
Level 2: |
| Observable market-based inputs or unobservable inputs that are corroborated by market data |
Level 3: |
| Unobservable inputs for which there is little or no market data, which require the use of the reporting entity's own assumptions. |
Cash and cash equivalents include money market securities and commercial paper and marketable securities representing certificates of deposits maturing in less than one year that are considered to be highly liquid and easily tradable. These securities are valued using inputs observable in active markets for identical securities and are therefore classified as Level 1 within the fair value hierarchy.
In addition, the FASB issued, "The Fair Value Option for Financial Assets and Financial Liabilities," effective for May 1, 2008. This guidance expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. We did not elect the fair value option for any of our qualifying financial instruments, other than those subject to recent acquisitions.
Equity-Based Compensation
The computation of the expense associated with stock-based compensation requires the use of a valuation model. The FASB issued accounting guidance requires significant judgment and the use of estimates, particularly surrounding Black-Scholes assumptions such as stock price volatility, expected option lives, and expected option forfeiture rates, to value equity-based compensation. We currently use a Black-Scholes option pricing model to calculate the fair value of our stock options. We primarily use historical data to determine the assumptions to be used in the Black-Scholes model and have no reason to believe that future data is likely to differ materially from historical data. However, changes in the assumptions to reflect future stock price volatility and future stock award exercise experience could result in a change in the assumptions used to value awards in the future and may result in a material change to the fair value calculation of stock-based awards. This accounting guidance requires the recognition of the fair value of stock compensation in net income. Although every effort is made to ensure the accuracy of our estimates and assumptions, significant unanticipated changes in those estimates, interpretations and assumptions may result in recording stock option expense that may materially impact our financial statements for each respective reporting period.
Recent Accounting Pronouncements
On January 1, 2009, we adopted the FASB guidance for Business Combinations, which replaces SFAS No. 141, Business Combinations ("SFAS 141R" FASB ASC 805-10), and requires an acquirer to recognize the assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions. This Statement also requires the acquirer in a
39
business combination achieved in stages to recognize the identifiable assets and liabilities, as well as the non-controlling interest in the acquiree, at the full amounts of their fair values. Additionally, this Statement requires acquisition-related costs to be expensed in the period in which the costs were incurred and the services are received instead of including such costs as part of the acquisition price. This guidance makes various other amendments to authoritative literature intended to provide additional guidance or to conform the guidance in that literature to that provided in this Statement. Our acquisition of the Ky-Tenn Oil, Inc and Cook Inlet assets and the stock and membership interests of East Tennessee Consultants, Inc. and East Tennessee Consultants II, LLC were recorded in accordance with this guidance.
In April 2009, the FASB issued FASB ASC 805-20 (formerly FSP SFAS No. 141R-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies). FASB ASC 805-20 amends the guidance in FASB ASC 805 (formerly SFAS 141R) relating to the initial recognition and measurement, subsequent measurement and accounting and disclosures of assets and liabilities arising from contingencies in a business combination. FASB ASC 805 (formerly FSP SFAS 141R) is effective for fiscal years beginning after December 15, 2008. We adopted FASB ASC 805 (formerly FSP SFAS 141R) as of the beginning of fiscal 2009. We will apply the requirements of FASB ASC 805-20 (formerly FSP FAS 141R-1) prospectively to any future acquisitions.
In December 2009, the FASB issued guidance for Consolidations - Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (Topic 810). The amendments in this update are a result of incorporating the provisions of SFAS No. 167, Amendments to FASB Interpretation No. 46(R). The provisions of such Statements are effective for fiscal years, and interim periods within those fiscal years, beginning on or after November 15, 2009. Earlier adoption is not permitted. The presentation and disclosure requirements shall be applied prospectively for all periods after the effective date. Management believes this Statement will not have a material impact on our financial statements once adopted.
We determined that all other issued, but not yet effective accounting pronouncements are inapplicable or insignificant to us and once adopted are not expected to have a material impact on our financial position.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable to a smaller reporting company.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Our financial statements are contained in pages F-1 through F-30, which appear at the end of this annual report.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A(T).
CONTROLS AND PROCEDURES.
Disclosure Controls and Procedures.
Our Chief Executive Officer and Chief Financial Officer are responsible for establishing and maintaining disclosure controls and procedures for us. Disclosure controls and procedures are controls and procedures designed to reasonably assure that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this report, is recorded, processed, summarized and reported within the time periods prescribed by SEC rules and regulations, and to reasonably assure that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
Our management does not expect that our disclosure controls or our internal controls will prevent all error and fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.
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Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people or by management override of the control. The design of any systems of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of these inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
As required by Rule 13a-15 under the Securities Exchange Act of 1934, as of April 30, 2010, the end of the period covered by this report, our management concluded its evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. As of the evaluation date, our Chief Executive Officer and Chief Financial Officer, concluded that we do not maintain disclosure controls and procedures that are effective in providing reasonable assurance that information required to be disclosed in our reports under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods prescribed by SEC rules and regulations, and that such information is accumulated and communicated to our management to allow timely decisions regarding required disclosure as a result of material weaknesses in our disclosure controls and procedures. During fiscal 2010 we failed to timely file with the SEC several Current Reports on Form 8-K. In an effort to remediate these weaknesses, during the fourth quarter of 2010 we hired a General Counsel. She has developed systems which should ensure that the information required to be disclosed in our reports under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods prescribed by SEC rules and regulations, and that such information is accumulated and communicated to our management to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of our internal control over financial reporting as of April 30, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in Internal Control-Integrated Framework. Based on the assessment using those criteria, our management concluded that the internal control over financial reporting was not effective at April 30, 2010.
While we have designed a system of internal controls to supplement our existing controls during our implementation of Section 404 of the Sarbanes-Oxley Act of 2002 ("SOX 404"), we have been unable to complete testing of these controls and accordingly lack the documented evidence that we believe is necessary to support an assessment that our internal control over financial reporting is effective. Without such testing, we cannot conclude that there are any significant deficiencies or material weaknesses, nor can we appropriately remediate any such deficiencies that might have been detected. In addition, during the analysis of our internal controls in connection with our implementation of SOX 404, we did identify a number of controls weaknesses, the remediation of these controls of which are material to our internal control environment and critical to providing reasonable assurance that any potential errors could be detected. Those identified controls weaknesses include:
·
We do not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience and training in the selection and application of U.S. GAAP and SEC reporting requirements commensurate with our financial reporting requirements at our newly acquired subsidiaries and / or the corporate office to accommodate the newly acquired subsidiaries financial reporting needs.
·
Our newly acquired subsidiaries have yet to integrate a uniform accounting reporting system.
Due to the nature of these material weaknesses in our internal control over financial reporting, there is more than a remote likelihood that misstatements which could be material to our annual or interim financial statements could occur that would not be prevented or detected. To remediate these weaknesses we, during fiscal year, will need to:
·
Hire additional accounting personnel, both in Tennessee and Alaska, who are sufficiently experienced in the application of GAAP and SEC reporting requirements; and
41
·
Implement a uniform accounting reporting system within our newly acquired subsidiaries.
We anticipate that we will be able to complete these remediation efforts by April 30, 2011
Changes in Internal Control over Financial Reporting. There have been no changes in our internal control over financial reporting during our fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
OTHER INFORMATION
None.
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PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Directors and Executive Officers
Name |
| Age |
| Position |
Deloy Miller |
| 63 |
| Chairman of the Board of Directors and Chief Operating Officer |
Scott M. Boruff |
| 47 |
| Chief Executive Officer, President and director |
David M. Hall |
| 40 |
| Chief Executive Officer of Cook Inlet Energy and director |
Paul W. Boyd |
| 51 |
| Chief Financial Officer |
Charles M. Stivers 1 |
| 47 |
| Director |
Herman E. Gettelfinger 2,3 |
| 77 |
| Director |
General Merrill A. McPeak 1, |
| 74 |
| Director |
Jonathan S. Gross3 |
| 51 |
| Director |
David J. Voyticky1,2,3 |
| 41 |
| Director |
———————
1
Member of the Audit Committee.
2
Member of the Compensation Committee.
3
Member of the Nominating and Corporate Governance Committee.
Deloy Miller. Mr. Miller has been Chairman of the Board of Directors since December 1996, and was Chief Executive Officer from December 1997 to August 2008. Since then, Mr. Miller has been our Chief Operating Officer. From 1967 to 1997, Mr. Miller was the founder and Chief Executive Officer of our company. He is a seasoned gas and oil professional with more than 40 years of experience in the drilling and production business in the Appalachian basin. During his years as a drilling contractor, he acquired extensive geological knowledge of Tennessee and Kentucky and received training in the reading of well logs. Mr. Miller served two terms as president of the Tennessee Oil & Gas Association and in 1978 the organization named him the Tennessee Oil Man of the Year. He continues to serve on the board of that organization. Mr. Miller was appointed in 1978 by the Governor of Tennessee to be the petroleum industry’s representative on the Tennessee Oil & Gas Board, the state agency that regulates gas and oil operations in the state. Mr. Miller is the father-in-law of Mr. Boruff.
Scott M. Boruff. Mr. Boruff has served as a director and our Chief Executive Officer since August 2008 and as our President since June 2010. Prior to joining our company, Mr. Boruff has been a licensed investment banker and was a director from 2006 to 2007 with Cresta Capital Strategies, LLC a New York investment banking firm that was responsible for closing transactions in the $150 to $200 million category. Mr. Boruff specialized in investment banking consulting services that included structuring of direct financings, recapitalizations, mergers and acquisitions and strategic planning with an emphasis in the gas and oil field. As a commercial real estate broker for over 20 years Mr. Boruff developed condominium projects, hotels, convention centers, golf courses, apartments and residential subdivisions. As a consultant to us, Mr. Boruff led the last three major financial transactions completed by the company. Since April 2009, Mr. Boruff has also been a director and 49% owner of Dimirak Securities Corporation, a broker-dealer and member of FINRA. See Item 13. Certain Relationships and Related Transactions and Director Independence appearing later in this annual report. Mr. Boruff holds a Bachelor of Science in Business Administration from East Tennessee State University. Mr. Boruff is the son-in-law of Mr. Miller.
David M. Hall. Mr. Hall has served as Chief Executive Officer of our Cook Inlet Energy subsidiary and member of our Board of Directors since December 2009. Mr. Hall was the former Vice President and General Manager of Alaska Operations, Pacific Energy Resources Ltd. from January 2008 to December 2009. Before that time, from 2000 to 2008, he served as the Production Foreman and Lead Operator in Alaska for Forest Oil Corp, rising to Production Manager for all of Alaska operation for Forest Oil.
Paul W. Boyd. Mr. Boyd has served as our Chief Financial Officer since September 2008. Prior to joining our company, from 2001 until August 2008 Mr. Boyd was Chief Financial Officer and Treasurer of IdleAire Technologies Corporation, a Knoxville, Tennessee company which provides a patented system that enables long haul truck drivers to park their trucks for extended periods of time while still using the heat, air conditioning and many other amenities. From 1999 to 2000 Mr. Boyd was Chief Financial Officer of United States Internet, Inc., a Knoxville, Tennessee company which was a subsidiary of Earthlink Company. From 1996 to 1999 he was Treasurer
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of Clayton Homes, Inc., a manufacturer of manufactured housing which is a subsidiary of Berkshire Hathaway, Inc. Mr. Boyd received a B.B.A. in Accounting from the University of Houston and is a certified public accountant.
Charles M. Stivers. Mr. Stivers has been a member of our Board of Directors since 2004. He also served as our Chief Financial Officer from 2004 until January 2006. Mr. Stivers has over 18 years accounting experience and over 12 years of experience within the energy industry. He owns and operates Charles M. Stivers, C.P.A., which specializes in the oil and gas industry and has clients located in eight different states. Mr. Stivers served as Treasurer and Chief Financial Officer for Clay Resource Company and Senior Tax and Audit Specialist for Gallaher and Company. He received a Bachelor of Science degree in accounting from Eastern Kentucky University.
Herman E. Gettelfinger. Mr. Gettelfinger has been a member of our Board of Directors since 1997. Mr. Gettelfinger, who has been active in the gas and oil drilling and exploration business for more than 35 years, is a co-owner and President of Kelso Oil Company, Knoxville Tennessee. Kelso is one of eastern Tennessee’s largest distributors of motor oils, fuels and lubricants to the industrial and commercial market.
General Merrill A. McPeak (USAF, retired). General McPeak has been a member of our Board of Directors since April 2010. General McPeak has served as President of McPeak and Associates, a 15-year old management consulting firm, since its founding in 1995. From October 1990 until October 1994, he was Chief of Staff of the U.S. Air Force and a member of the Joint Chiefs of Staff. During this period, he was the senior officer responsible for organization, training and equipage of a combined active duty, National Guard, Reserve and civilian work force of over 850,000 people serving at 1,300 locations in the United States and abroad. As a member of the Joint Chiefs of Staff, he and the other service chiefs were military advisors to the Secretary of Defense, the National Security Council and the President of the United States. Following retirement from active service, General McPeak began a second career in business. He is Chairman of Ethicspoint, a privately-held, Portland-based provider of risk management and compliance software-as-a-service, including secure, anonymous reporting of ethical violations in the workplace. General McPeak has also served as a member of the Board of Director for Del Global Technologies Corp. (since 2005), Point Blank Solutions, Inc. (since 2008), Tektronix, Inc. (1995 to 2006); Quintessence Photonics Corp. (2006 to 2009), Blacklight Power Inc. (2003 to present), Health Sciences Group, Inc. (2005 to 2007), MathStar, Inc. (2005 to February 2010), Gigabeam Corp. (2004 to 2009), TWA (1997 to 2002), ECC International (1997 to 2003), Praegitzer Industries (1997 to 1999) and Western Power and Equipment (1998 to 2000). In 1992, San Diego State University honored General McPeak with its first ever Lifetime Achievement Award. In 1995, George Washington University gave him its Distinguished Alumni Award, the “George.” He was among the initial seven inductees to the Oregon Aviation Hall of Honor. He is a member of the Council on Foreign Relations, New York City, and in 2008 and 2009 was a national co-chairman of Obama for President.
Jonathan S. Gross. Mr. Gross has been a member of our Board of Directors since April 2010. Mr. Gross has 29 years of experience in domestic and international oil and gas exploration and currently serves as Senior Vice President - Geosciences for Energy Partners, Ltd. (NYSE: EPL). From June 2009 to May 2010, he served as President of Jexco, LLC, a Houston, Texas geological and geophysical consulting company. During his career, Mr. Gross has served as the Chief Operating Officer of Houston Exploration Services, Inc., a Houston, Texas based subsidiary of Kuwait Energy Company from July 2008 to May 2009, Senior Vice President of Exploration and Technology Manager of Cheniere Energy, Inc. from June 1999 to July 2008, and has also worked for Zydeco Energy, Inc. from January 1998 to May 1999. He has domestic and international experience in both onshore and offshore basins in several parts of the world including the U.S., Trinidad, West Africa, North Africa, the Middle East and Eurasia. Mr. Gross received his B.A. in Geophysical Sciences from the University of Chicago in 1981 and is a member of the American Association of Petroleum Geologists, the Society of Exploration Geophysicists and the Houston Geological Society.
David J. Voyticky. Mr. Voyticky has been a member of our Board of Directors since April 2010. Mr. Voyticky is has over 15 years of domestic and international mergers and acquisitions, restructuring and financing experience. Since August 2005, Mr. Voyticky has been an independent consultant to companies in the middle market on value maximization strategies. As part of this focus, Mr. Voyticky provides strategic and capital markets advice to high growth businesses He served as a vice president with Goldman, Sachs & Co. from June 2000 to May 2002, a vice president of Houlihan Lokey Howard & Zukin Capital, Inc. in Los Angeles from July 2002 to January 2005, and an associate with J.P. Morgan in London and New York from June 1996 to May 2000. During that period, he advised public and private domestic and multinational corporations and financial sponsors on mergers, acquisitions, divestitures, joint ventures, cross-border transactions, anti-raid (defense) preparation and capital-raising activities. Mr. Voyticky designed and was a founding partner of Red Mountain Capital Partners.
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From December 2005 through June 2006, Mr. Voyticky was a partner in the $300 million re-launch of Chapman Capital L.L.C., an activist hedge fund focused on the publicly traded middle market companies. Since January 2010 he has been a member of the Board of Directors of Best Energy Services, Inc. Mr. Voyticky received a J.D. and a M.B.A degree from the University of Michigan and a Masters in International Policy and Economics from the Ford School at the University of Michigan. He also received a Bachelor of Arts in Philosophy from Pomona College.
There are no family relationships between any of the executive officers and directors, except as set forth above. Each director is elected at our annual meeting of shareholders and holds office until the next annual meeting of shareholders, or until his successor is elected and qualified. As a term of the acquisition of Cook Inlet, we agreed Cook Inlet’s owners prior to the acquisition would be represented by a seat on our Board of Directors for a period of three years from December 11, 2009. Mr. Hall has initially been designated as the director representing Cook Inlet’s prior owners. In the event Mr. Hall should die or otherwise become incapacitated or unavailable to act as director, Mr. Wilcox will be designated as the successor directors and thereafter Mr. Stafford. Under the terms of the November 2009 letter agreement with Vulcan Capital Corporation, LLC, upon closing of the loan agreement Vulcan Capital Corporation will have the right to designate a member of our Board of Directors during the term of the loan.
Director Qualification
The following is a discussion for each director of the specific experience, qualifications, attributes or skills that led to our conclusion that such person should be serving as a member of our Board of Directors as of the date of this annual report in light of our business and structure. In addition to their individual skills and backgrounds which are focused on our industry as well as financial and managerial experience, we believe that the collectively skills and experience of our Board members are well suited to guide us as we continue to grow our company.
Deloy Miller – Mr. Miller has extensive experience as a seasoned gas and oil professional. our company. Mr. Miller has more than 40 years of experience in the drilling and production business in the Appalachian basin, extensive geological knowledge of Tennessee and Kentucky, training in the reading of well logs, and particular familiarity with our operations as our founder, former Chief Executive Officer, and current Chief Operating Officer.
Scott M. Boruff – Mr. Boruff has experience in the financial industry, specializing in investment banking consulting services that included structuring of direct financings, recapitalizations, mergers and acquisitions and strategic planning with an emphasis in the gas and oil field.
David M. Hall – Mr. Hall has a comprehensive knowledge of our Alaskan operations, with nearly 20 years of experience with our Alaskan assets, together with engineering expertise in which he trained as both an electrical engineer and industrial engineer.
Herman E. Gettelfinger – Mr. Gettelfinger has over 35 years of experience in the gas and oil drilling and exploration business including as co-owner and President of Kelso Oil Company, one of East Tennessee’s largest distributors of motor oils, fuels and lubricants to the industrial and commercial market.
Jonathan S. Gross – Mr. Gross has 29 years of experience in domestic and international oil and gas exploration and education and is trained as a geologist. Mr. Gross has experience in both onshore and offshore basins in several parts of the world, has held various positions in several energy companies and is a geologist.
Merrill A. McPeak – General McPeak has extensive experience in management consulting and a successful military career, including his position as Chief of Staff of the U.S. Air Force and a member of the Joint Chiefs of Staff, during which time he was the senior officer responsible for organization, training and equipage of a combined active duty, National Guard, Reserve and civilian work force of over 850,000 people serving at 1,300 locations in the United States and abroad and advised the Secretary of Defense, the National Security Council and the President of the United States. General McPeak currently serves or has served in the past on the Board of Directors of a number of publicly traded companies.
Charles M. Stivers – Mr. Stivers, a certified public accountant, has over 18 years of experience in accounting and over 12 years of experience within the energy industry. Mr. Stivers owns and operates an accounting firm that specializes in the oil and gas industry with clients in eight different states.
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David J. Voyticky – Mr. Voyticky has over 15 years of domestic and international mergers and acquisitions, restructuring and financing experience and education and training, with experience as an independent consultant to companies in the middle market on value maximization strategies, providing strategic and capital markets advice to high growth businesses.
Director Compensation
We have not established standard compensation arrangements for our directors and the compensation payable to each individual for their service on our Board is determined from time to time by our Board of Directors based upon the amount of time expended by each of the directors on our behalf. Currently, executive officers of our company who are also members of the Board of Directors do not receive any compensation specifically for their services as directors. Mr. David M. Hall, an employee of our company, also serves on our Board of Directors and he receives no compensation for his services as a director. On April 27, 2010 our Board of Directors granted options under our stock option plan exercisable at fair market value on the date of grant as compensation to our non-employee directors for their services to us. Our Board of Directors intends to adopt a policy regarding compensation of non-employee directors prior to the end of our current fiscal year.
The following table provides information about compensation paid to our non-employee directors during the 2010 for their services as directors. The value of the securities issued reflects the aggregate grant date fair value computed in accordance with ASC Topic 718. While options were granted to these individuals as described below, because none of these options have vested and the grant is subject to continued Board service, under generally accepted accounting principles we will recognize compensation expense for these grants over the vesting period.
Name (a) |
| Fees Paid or ($) (b) |
| Stock |
| Option |
| Non-Equity |
| Change in Nonqualified (f) |
| All Other ($) (g) |
| Total ($) (h) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Charles M. Stivers 1 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
|
Herman E. Gettelfinger 2 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
|
Merrill A. McPeak3 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
|
Jonathan S. Gross4 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
|
David J. Voyticky 5 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
|
———————
1
Mr. Stivers was granted options to purchase an aggregate of 100,000 shares of our common stock at an exercise price of $5.94 per share, of which options to purchase 33,333 shares vest on April 27, 2011, options to purchase an additional 33,333 shares vest on April 27, 2012 and options to purchase the remaining 33,334 shares vest on April 27, 2013.
2
Mr. Gettelfinger was granted options to purchase an aggregate of 100,000 shares of our common stock at an exercise price of $5.94 per share, of which options to purchase 33,333 shares vest on April 27, 2011, options to purchase an additional 33,333 shares vest on April 27, 2012 and options to purchase the remaining 33,334 shares vest on April 27, 2013.
3
General McPeak was granted options to purchase an aggregate of 200,000 shares of our common stock at an exercise price of $5.94 per share, of which options to purchase 66,667 shares vest on April 27, 2011, options to purchase an additional 66,667 shares vest on April 27, 2012 and options to purchase the remaining 66,666 shares vest on April 27, 2013.
4
Mr. Gross was granted options to purchase an aggregate of 200,000 shares of our common stock at an exercise price of $5.94 per share, of which options to purchase 66,667 shares vest on April 27, 2011, options to purchase an additional 66,667 shares vest on April 27, 2012 and options to purchase the remaining 66,666 shares vest on April 27, 2013.
5
Mr. Voyticky was granted options to purchase an aggregate of 200,000 shares of our common stock at an exercise price of $5.94 per share, of which options to purchase 66,667 shares vest on April 27, 2011, options to purchase an additional 66,667 shares vest on April 27, 2012 and options to purchase the remaining 66,666 shares vest on April 27, 2013.
46
Code of Business Conduct and Ethics
We have adopted a Code of Business Conduct and Ethics that applies to our President, Chief Executive Officer, Chief Financial Officer Chief Accounting Officer or Controller and any other persons performing similar functions. This Code provides written standards that we believe are reasonably designed to deter wrongdoing and promote honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships, and full, fair, accurate, timely and understandable disclosure in reports we file with the Securities Exchange Commission. A copy of our Code of Business Conduct and Ethics is available on our website site. It has also been filed with the Securities and Exchange Commission as an exhibit to this annual report.
Committees of the Board of Directors
Our Board of Directors has established an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee. While our Board of Directors established the Audit Committee in 2004, the Compensation Committee and Nominating and Corporate Governance Committee were only recently established in conjunction with the listing of our common stock on the NASDAQ Stock Market.
Audit Committee. The Audit Committee assists the Board in fulfilling its oversight responsibility relating to the integrity of our financial statements, our compliance with legal and regulatory requirements and the qualifications and independence of our independent registered public accountants. The Audit Committee is composed of three directors, Messrs. Stivers (Chairman) and Voyticky and General McPeak, all of whom have been determined by the Board of Directors to be “independent,” as defined by the Marketplace Rules of the NASDAQ Stock Market. The Board has determined that Mr. Stivers, the Chairman of the Audit Committee, qualifies as an “audit committee financial expert” as defined by the SEC.
Compensation Committee. The Compensation Committee is responsible for overseeing our compensation programs and practices, including our executive compensation plans and incentive compensation plans. The Chief Executive Officer will provide input to the Compensation Committee with respect to the individual performance and compensation recommendations for the other executive officers. The Compensation Committee is composed of three directors, Messrs. Voyticky (Chairman), Stivers and Gettelfinger, all of whom have been determined by the Board of Directors to be “independent,” as defined by the Marketplace Rules of the NASDAQ Stock Market.
Nominating and Corporate Governance Committee. The Nominating and Corporate Governance Committee will recommend the slate of director nominees for election to our Board of Directors, identify and recommend candidates to fill vacancies occurring between annual stockholder meetings, review the composition of Board committees and monitor compliance with, review, and recommend changes to our various corporate governance policies and guidelines. The committee will also prepare and supervise the Board’s annual review of director independence and the Board’s annual self-evaluation. The Nominating and Corporate Governance Committee is composed of three directors, Messrs. Gettelfinger (Chairman), Voyticky and Gross, all of which have been determined by the Board of Directors to be “independent,” as defined by the Marketplace Rules of the NASDAQ Stock Market.
The Nominating and Corporate Governance Committee will consider all qualified candidates for our Board of Directors identified by members of the committee, by other members of the Board of Directors, by senior management and by our stockholders. The committee will review each candidate, including each candidate’s independence, skills and expertise based on a variety of factors, including the person’s experience or background in management, finance, regulatory matters and corporate governance. Further, when identifying nominees to serve as director, the Nominating and Corporate Governance Committee will seek to create a Board that is strong in its collective knowledge and has a diversity of skills and experience with respect to accounting and finance, management and leadership, vision and strategy, business operations, business judgment, industry knowledge and corporate governance. In addition, prior to nominating an existing director for re-election to the Board of Directors, the Nominating and Corporate Governance Committee will consider and review an existing director’s Board and committee attendance and performance, length of Board service, experience, skills and contributions that the existing director brings to the Board, equity ownership in our company and independence.
The Nominating and Corporate Governance Committee will follow the same process and use the same criteria for evaluating candidates proposed by stockholders, members of the Board of Directors and members of senior management. Based on its assessment of each candidate, the committee will recommend candidates to the
47
Board. However, there is no assurance that there will be any vacancy on the Board at the time of any submission or that the committee will recommend any candidate for the Board.
ITEM 11.
EXECUTIVE COMPENSATION.
The following table summarizes all compensation recorded by us in fiscal 2010 for the following:
·
our principal executive officer or other individual serving in a similar capacity,
·
our two most highly compensated executive officers other than our principal executive officer who were serving as executive officers at April 30, 2010 as that term is defined under Rule 3b-7 of the Securities Exchange Act of 1934, and
·
up to two additional individuals for whom disclosure would have been required but for the fact that the individual was not serving as an executive officer at April 30, 2010.
For definitional purposes, these individuals are sometimes referred to as the “named executive officers.” The value attributable to any option awards in the following table is computed in accordance with ASC Topic 718. The value of the securities issued reflects the aggregate grant date fair value computed in accordance with ASC Topic 718 assuming the following weighted averages:
Expected life (in years) |
|
| 3.0 |
|
Volatility |
|
| 221.97 | % |
Discount rate - bond equivalent rate |
|
| 1.55 | % |
Annual rate of quarterly dividends |
|
| 0.00 |
|
Summary Compensation Table
———————
1
Mr. Boruff has served as our Chief Executive Officer since August 2008 and the terms of his compensation are set forth in his employment agreement which is described later in this section. Mr. Boruff is entitled to a bonus each year equal to 100% of his base salary and 100,000 shares of our common stock if we meet certain revenue and EBITDA milestones. These milestones were met in each of 2010 and 2009. Mr. Boruff’s bonus in 2010 and 2009 included $319,500 and $33,000, respectively, attributable to the value of 100,000 shares of our common stock issued to him. The value of stock awards and option awards in each of 2010 and 2009 represents the value of restricted stock awards and option grants made to him in each of those years under the terms of his employment agreement. All other compensation for both 2010 and 2009 included an auto allowance of $1,000 per month plus $640 and $59, respectively, of compensation derived from personal use of a company vehicle. The amount of Mr. Boruff’s compensation excludes fees paid to Dimirak Securities Corporation, a broker-dealer and member of FINRA, and its related parties under the terms of a Marketing Agreement. Mr. Boruff is a director and owns 49% of Dimirak Securities Corporation. See Item 14. Certain Relationships and Related Transactions and Director Independence appearing later in this annual report. Mr. Boruff’s compensation for 2010 excludes the value of options granted to him in April 2010 which have not yet vested.
2
Mr. Miller served as our Chief Executive Officer from December 1997 to August 2008 and is currently our Chief Operating Officer. All other compensation included $1,161 and $2,244 of compensation derived from personal use of a company vehicle in 2010 and 2009, respectively. Mr. Miller’s compensation for 2010 excludes the value of options granted to him in April 2010 which have not yet vested.
48
3
Mr. Graham served as our President and Vice-Chairman of our Board of Directors from December 2009 until June 2010. Option awards in 2010 represent the value of 10 year warrants which were immediately exercisable to purchase an aggregate of 1,000,000 shares of our common stock, with warrants to purchase 400,000 shares exercisable at $0.01 per share, warrants to purchase 200,000 shares exercisable at $0.69 per share, warrants to purchase 200,000 shares exercisable at $1.00 per share and warrants to purchase 200,000 shares exercisable at $2.00 per share. Mr. Graham has transferred the $0.01, $1.00 and $2.00 warrants to Vulcan Capital Corporation, a company of which he is a control person. Mr. Graham’s compensation for 2010 excludes the value of options granted to him in April 2010 which have not yet vested. Because Mr. Graham resigned prior to the vesting of any of these options, these options have lapsed and the shares underlying them have been returned to the pool available for future grants under the terms of our Stock Plan.
Employment Agreement with Mr. Boruff
Effective August 1, 2008, we entered into an employment agreement, as amended in September 2008, with Mr. Scott M. Boruff pursuant to which Mr. Boruff will serve as our Chief Executive Officer for an initial term of five years, subject to additional one-year renewal periods. Under the terms of the agreement, as amended, Mr. Boruff’s compensation consists of the following:
·
a base salary of $250,000 per annum, with provision for cost-of-living increases,
·
10 year options to purchase 250,000 shares of our common stock at an exercise price per share of $0.33, with vesting in equal annual installments over a period of four years from the grant date, or immediately upon a change of control of our company as described in the agreement, and
·
a restricted stock grant of 250,000 shares of common stock, with vesting in equal annual installments over a period of four years from the issuance date, or on an accelerated basis in the event of a change of control of our company also as described in the agreement.
Mr. Boruff is also entitled to receive certain incentive compensation in the form of cash and shares of our common stock based upon, and subject to, two performance benchmarks, gross revenue and earnings before income taxes, depreciation and amortization (EBITDA), as follows:
·
100% of his base salary and 100,000 shares of our common stock in the event that our gross revenues for fiscal 2009 (annualized beginning on the date of the agreement) were not less than $2,000,000 and EBITDA for such period was not less than $200,000,
·
100% of his base salary and 100,000 shares of our common stock in the event that our gross revenues for fiscal 2010 are not less than $4,000,000 and EBITDA for such period was not less than $400,000,
·
100% of his base salary and 100,000 shares of our common stock in the event that our gross revenues for fiscal 2011 are not less than $8,000,000 and EBITDA for such period was not less than $800,000,
·
100% of his base salary and 100,000 shares of our common stock in the event that our gross revenues for fiscal 2012 are not less than $16,000,000 and EBITDA for such period was not less than $1,600,000, and
·
100% of his base salary and 100,000 shares of our common stock in the event that our gross revenues for fiscal 2013 are not less than $30,000,000 and EBITDA for such period was not less than $3,000,000.
One half of each element of incentive compensation is earned if the gross revenue benchmark is achieved, and the other half of each element is earned if the EBITDA benchmark is achieved.
Mr. Boruff is also entitled to a $1,000 per month automobile allowance. The employment agreement also provides that Mr. Boruff is entitled to participate in the employee benefit plans, programs and arrangements we have in effect during the employment term which are generally available to our senior executives. The agreement also contains indemnification, confidentiality and non-solicitation clauses.
49
The agreement may be terminated by us for cause, as defined in the agreement, or upon his death or disability, or for no cause. In the event the agreement is terminated for either reason, if Mr. Boruff should terminate the agreement for any reason or if the agreement is not renewed, he is only entitled to receive his base salary through the date of termination. We may also terminate the agreement without cause, in which event Mr. Boruff will be entitled to his base salary through the date of termination and, should we terminate the agreement during the initial term, as severance, his base salary for one year. If we should terminate the agreement as a result of a change of control as defined in the agreement, he is entitled to a lump sum payment equal to 2.99 times Mr. Boruff’s then base salary.
In addition to the compensation payable to him under the terms of his employment agreement, in April 2010 the Compensation Committee of the Board of Directors granted Mr. Boruff options under our stock option plan to purchase 500,000 shares of our common stock with an exercise price of $5.94 per share as additional compensation. These options vest over three years in arrears commencing on April 27, 2011, and are subject to continued employment. The Compensation Committee determined to make this award of additional compensation to Mr. Boruff in recognition of his past performance and a desire to retain him throughout the three year vesting period.
How Mr. Miller's Compensation was Determined
Mr. Miller, who served as our principal executive officer until December 1997 to August 1, 2008, is not a party to an employment agreement with our company. His compensation is determined by the Chief Executive Officer. The Board considered a number of factors in determining Mr. Miller's compensation including the scope of his duties and responsibilities to our company and the time he devotes to our business. The Board of Directors did not consult with any experts or other third parties in fixing the amount of Mr. Miller's compensation. During each of 2010 and 2009, Mr. Miller's compensation package included a base salary of $200,000. We also provide him with a company vehicle. In addition, in April 2010 the Compensation Committee of the Board of Directors granted Mr. Miller options under our stock option plan to purchase 350,000 shares of our common stock with an exercise price of $5.94 per share as additional compensation. These options vest over three years in arrears commencing April 27, 2011, and are subject to continued employment. The Compensation Committee determined to make this award of additional compensation to Mr. Miller in recognition of his past performance and a desire to retain him throughout the three year vesting period.
How Mr. Graham’s Compensation was Determined
Mr. Graham served as our President from December 2009 to June 2010. We were not a party to an employment agreement with him, but at the time of his hiring our Board approved annual base compensation of $200,000, a one-time signing bonus of $200,000, a seat on our Board of Directors as Vice-Chairman and other compensation which is customarily paid to our other senior officers. In addition, on December 10, 2009 we granted him 10 year warrants which were immediately exercisable to purchase an aggregate of 1,000,000 shares of our common stock valued at $314,936 as additional compensation. Mr. Graham has transferred certain of the warrants to Vulcan Capital Corporation, a company of which he is a control person. The Board considered a number of factors in determining Mr. Graham’s compensation including the scope of his duties and responsibilities to our company. The Board of Directors did not consult with any experts or other third parties in fixing the amount of Mr. Graham's compensation. In addition, in April 2010 the Compensation Committee of the Board of Directors granted Mr. Graham options under our stock option plan to purchase 100,000 shares of our common stock with an exercise price of $5.94 per share as additional compensation. These options vest over three years in arrears commencing April 27, 2011, and are subject to continued employment. The Compensation Committee determined to make this award of additional compensation to Mr. Graham in recognition of his past performance and a desire to retain him throughout the three year vesting period. Because Mr. Graham resigned prior to the vesting of any of these options, these options have lapsed and the shares underlying them have been returned to the pool available for future grants under the terms of our Stock Plan.
Severance Agreement with Mr. Graham
In June 2010 Mr. Graham resigned as an executive officer and director of our company. Following his resignation we entered into a Separation Agreement and General Release with Mr. Graham pursuant to which he will receive six month’s salary as severance and he will be entitled to retain the warrants to purchase 1,000,000 shares of our common stock with exercise prices ranging from $0.01 per share to $2.00 per share granted to him when he joined our company in December 2009. The options to purchase an additional 100,000 shares of our common stock at an exercise price of $5.94 per share granted in April 2010 were contingent upon continued service
50
and will, accordingly, terminate. The Separation Agreement and General Release contains continuing indemnification and confidentially provisions and a general release to us from Mr. Graham.
How Mr. Boyd’s Compensation was Determined
Mr. Boyd, who has served as our Chief Financial Officer since September 2008, is not a party to an employment agreement with our company. His compensation is determined by our Chief Executive Officer who considered a number of factors in determining Mr. Boyd's compensation including the scope of his duties and responsibilities to our company and the time he devotes to our business. We did not consult with any experts or other third parties in fixing the amount of Mr. Boyd's compensation. During each of 2010 and 2009, Mr. Boyd’s compensation package included a base salary and an automobile allowance of $500 per month. At the time he joined our company we granted Mr. Boyd two year options to purchase 250,000 shares of our common stock at an exercise price of $0.40 per share, of which options to purchase 125,000 shares vested on the date of grant and the remaining options vested on March 31, 2010. In addition, in February 2010 our Board granted Mr. Boyd five year options to purchase 25,000 shares of our common stock at an exercise price of $2.52 per share which vested on May 19, 2010. In addition, in April 2010 the Compensation Committee of the Board of Directors granted Mr. Boyd options under our stock option plan to purchase 350,000 shares of our common stock with an exercise price of $5.94 per share as additional compensation. These options vest over three years in arrears commencing April 27, 2011, and are subject to continued employment. The Compensation Committee determined to make this award of additional compensation to Mr. Boyd in recognition of his past performance and a desire to retain him throughout the three year vesting period. Mr. Boyd’s total compensation for 2010 was $165,368.
Outstanding Equity Awards at Fiscal Year-End
The following table provides information concerning unexercised options, stock that has not vested and equity incentive plan awards for each named executive officer outstanding as of April 30, 2010:
OPTION AWARDS |
| STOCK AWARDS | ||||||||||||||||
Name (a) |
| Number of Options (b) |
| Number of Securities Underlying Unexercised options (#) unexercisable (c) |
| Equity Incentive plan awards: Number of Securities Underlying Unexercised Unearned options (#) (d) |
| Option Exercise price ($) (e) |
| Option Expiration date (f) |
| Number of shares or units of stock that have not vested (#) (g) |
| Market value of units of stock that have not vested ($)1 (h) |
| Equity incentive plan awards: (i) |
| Equity unearned (j) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Scott M. Boruff |
| 62,500 |
| 187,500 |
| — |
| 0.33 |
| 8/1/2018 |
| 187,500 |
| 1,083,750 |
| — |
| — |
|
|
|
|
|
|
|
|
|
|
|
| 300,000 |
| 1,734,000 |
| 50,000 |
| 289,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deloy Miller |
| — |
| — |
| — |
| — |
| — |
| 300,000 |
| 1,734,000 |
| 50,000 |
| 289,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ford Graham2 |
| 1,000,000 |
|
|
| 100,000 |
| 5.94 |
| 4/27/20 |
|
|
|
|
|
|
|
|
———————
1
Based upon the closing price of our common stock of $5.78 on April 30, 2010.
2
Mr. Graham resigned as an executive officer and director of our company on June 25, 2010. Under the terms of the severance arrangement with Mr. Graham in June 2010, he retained the warrants to purchase 1,000,000 shares granted in December 2009 but the rights to the 100,000 options which had not yet vested terminated.
Compliance with Section 16(a) of the Exchange Act
We did not have a class of our securities registered under either Section 12(b) or Section 12(g) of the Securities Exchange Act of 1934 during fiscal 2010. Accordingly, our officers, directors and 10% or greater shareholder were not required to file reports under Section 16(a) of the Securities Exchange Act of 1934 during fiscal 2010.
51
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
At July 22, 2010 we had 33,389,383 shares of our common stock issued and outstanding. The following table sets forth information regarding the beneficial ownership of our common stock as of July 22, 2010, by:
·
each person known by us to be the beneficial owner of more than 5% of our common stock;
·
each of our directors;
·
each of our named executive officers; and
·
our named executive officers, directors and director nominees as a group.
Unless otherwise indicated, the business address of each person listed is in care of 3651 Baker Highway, Huntsville, TN 37756. The percentages in the table have been calculated on the basis of treating as outstanding for a particular person, all shares of our common stock outstanding on that date and all shares of our common stock issuable to that holder in the event of exercise of outstanding options, warrants, rights or conversion privileges owned by that person at that date which are exercisable within 60 days of that date. Except as otherwise indicated, the persons listed below have sole voting and investment power with respect to all shares of our common stock owned by them, except to the extent that power may be shared with a spouse.
|
| Amount and Nature of Beneficial Ownership 1 |
| ||
Name |
| # of Shares |
| % of Class |
|
Deloy Miller 2 |
| 4,529,888 |
| 13.6 | % |
Scott M. Boruff 3 |
| 3,736,974 |
| 11.2 | % |
David M. Hall 4 |
| 322,450 |
| <1 | % |
Paul W. Boyd 5 |
| 300,000 |
| <1 | % |
Charles Stivers 6 |
| 0 |
| — |
|
Herman E. Gettelfinger 7 |
| 767,808 |
| 2.3 | % |
General Merrill A. McPeak 8 |
| 2,500 |
| <1 | % |
Jonathan S. Gross 9 |
| 0 |
| — |
|
David J. Voyticky 10 |
| 0 |
| — |
|
All named executive officers and directors as a group |
| 9,659,620 |
| 28.6 | % |
|
|
|
|
|
|
Prospect Energy Corporation 11 |
| 2,148,050 |
| 6.1 | % |
———————
1
The inclusion of any shares as deemed beneficially owned does not constitute an admission of beneficial ownership by the named shareholder.
2
The number of shares owned by Mr. Miller excludes options to purchase an additional 350,000 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020.
3
The number of shares owned by Mr. Boruff includes 8,000 shares owned for the benefit of his minor children and 62,500 shares of our common stock underlying vested options which are exercisable at $0.33 per share. The number of shares owned by Mr. Boruff excludes options to purchase an additional 187,500 shares of our common stock exercisable at $0.33 per share which have not yet vested and expire in August 2018, a restricted stock award of 187,500 shares which has not yet vested and options to purchase an additional 500,000 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020.
4
The number of shares owned by Mr. Hall excludes warrants to purchase 720,000 shares of our common stock exercisable at $1.00 per share and warrants to purchase 480,000 shares of our common stock at an exercise price of $2.00, both of which not vested and expire in December 2013, together with options to purchase an additional 100,000 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020.
5
The number of shares owned by Mr. Boyd includes options to purchase 275,000 shares of our common stock exercisable at $0.40 per share expiring in September 2011 and options to purchase 25,000 shares of common stock at $2.52 per share, but excludes options to purchase an additional 350,000 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020.
52
6
The number of shares owned by Mr. Stivers includes 225,000 shares held by his wife and 4,000 shares held by a partnership over which he had voting and dispositive control, but excludes options to purchase 100,000 shares of common stock at an exercise price of $5.94 which have not yet vested and expire in April 2020.
7
The number of shares owned by Mr. Gettelfinger excludes options to purchase 100,000 shares of common stock at an exercise price of $5.94 which have not yet vested and expire in April 2020.
8
The number of shares owned by General McPeak includes 2,500 shares held in a family trust but excludes options to purchase 200,000 shares of common stock at an exercise price of $5.94 which have not yet vested and expire in April 2020.
9
The number of shares owned by Mr. Gross excludes options to purchase 200,000 shares of common stock at an exercise price of $5.94 which have not yet vested and expire in April 2020.
10
The number of shares owned by Mr. Voyticky excludes options to purchase 200,000 shares of common stock at an exercise price of $5.94 which have not yet vested and expire in April 2020.
11
Prospect Energy Corporation has warrants to purchase 2,148,050 shares of our common stock. Prospect Energy Corporation’s address is US Bank Trust Security Services, 1515 North Rivercenter Drive, MK-WI-S302 Milwaukee, WI 53212.
Securities Authorized For Issuance Under Equity Compensation Plans
The following table sets forth securities authorized for issuance under any equity compensation plans approved by our shareholders as well as any equity compensation plans not approved by our shareholders as of April 30, 2010.
|
|
| Number of |
|
| Weighted and rights (b) |
|
| Number of |
|
Plan category |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plans approved by our shareholders: |
|
|
|
|
|
|
|
|
|
|
Miller Petroleum, Inc. Stock Plan |
|
| 2,625,000 |
| $5.94 |
|
| 375,000 |
| |
|
|
|
|
|
|
|
|
|
|
|
Plans not approved by shareholders: |
|
|
|
|
|
|
|
|
|
|
Warrants granted to Ford F. Graham in December 2009 |
|
| 1,000,000 |
| $0.74 |
|
| n/a |
| |
Warrants granted to employee in January 2010 |
|
| 100,000 |
| $2.00 |
|
|
|
| |
Warrants granted to employees in February 2010 |
|
| 150,000 |
| $2.52 |
|
|
|
| |
Employment agreement with Scott M. Boruff |
|
| 125,000 |
| $0.33 |
|
| 125,000 |
| |
Option agreement with Paul W. Boyd |
|
| 125,000 |
| $0.40 |
|
| 0 |
| |
Miller Petroleum, Inc. Stock Plan
In April 2010 our Board of Directors authorized the Miller Petroleum, Inc. Stock Plan which was subsequently approved by our shareholders at a special meeting held on April 27, 1010. The purpose of this plan, which is administered by the Compensation Committee of the Board of Directors, is to further the success of our company by making our common stock available to our employees through grants of incentive stock options, non-qualified stock options and restricted stock. We believe that the plan provides an incentive to such persons to continue in our service, to perform at and above targeted levels, and to give them a greater interest as shareholders in our success. We have reserved 3,000,000 shares of our common stock for issuance under this plan. Options and restricted stock awards may be granted under the plan only to our employees, officers or directors, or to members of any advisory panel or board established at the direction of the Board. In determining the persons to whom options or restricted stock awards will be granted and the number of shares to be covered by each option or award, the Compensation Committee may take into account the nature of the services rendered by the respective persons, their present and potential contributions to our and such other factors as the Compensation Committee in its discretion may believe relevant. The term of options granted under the stock option plan may not exceed 10 years or five years
53
for an incentive stock option granted to an optionee owning more than 10% of our voting stock. The exercise price for stock options cannot be less than fair market value on the date of grant. However, the incentive stock options granted to a 10% holder of our voting stock are exercisable at a price equal to or greater than 110% of the fair market value of the common stock on the date of the grant. As of April 30, 2010, we have granted options or awarded shares in the amount of 2,625,000 shares of our common stock under the plan.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
From time to time our company provides service work on oil and gas wells owned by Mr. Gettelfinger, a member of the Board of Directors, and his wife. The terms and pricing are the same as to third parties. At each of April 30, 2010 and 2009 Mr. and Mrs. Gettelfinger owed us $30,956 and $4,388, respectively.
Historically we engaged the accounting firm owned by Mr. Stivers, a member of our Board of Directors, to prepare our tax returns. At April 30, 2010 we owed his firm $0.
In April 2010 we entered into a consulting agreement with Jexco LLC, an entity owned by Mr. Jonathan Gross a member of our Board of Directors. Under the terms of this agreement, Mr. Gross’ firm provides advice to us in areas related to geological and geophysical activities of our Alaskan assets. The agreement was for a term of 30 days which can be extended upon the consent of the parties. As compensation for the services, we agreed to pay a fee of $250 per hour for work performed in the Houston metropolitan area and a fee of $2,500 per day for work performed outside of the Houston metropolitan area. We agreed to reimburse Jexco LLC for out of pocket expenses incurred in rendering the services to us. At April 30, 2010 we had accrued compensation under this agreement of $14,079. No decision has been made as of the date of this annual report regarding any renewal of this agreement.
On August 1, 2009 we entered into a Marketing Agreement with The Dimirak Companies, an affiliate of Dimirak Financial Corp. and Dimirak Securities Corporation, a broker-dealer and member of FINRA. Mr. Boruff, our CEO, is a director and 49% owner of Dimirak Securities Corporation. Under the terms of this agreement, we engaged The Dimirak Companies to serve as our exclusive marketing agent in a $20 million of income fund and a $25 million drilling offering, which included the MEI offering described earlier in this annual report. The term of the agreement will expire upon the termination of the offerings. We agreed to pay The Dimirak Companies a monthly consulting fee of $5,000, a marketing fee of 2% of the gross proceeds received in the offerings or within 24 months from the expiration of the term of the agreement, a wholesaling fee of 2% of the proceeds and a reimbursement of pre-approved expenses. The agreement contains customary indemnification, non-circumvention and confidentiality clauses. During 2010 we paid The Dimirak Companies and their affiliates a total of $25,468 under the terms of this agreement.
Transactions with MEI
In 2009 we formed both Miller Energy GP and MEI. MEI was organized to provide the capital required to invest in various types of oil and gas ventures including the acquisition of oil and gas leases, royalty interests, overriding royalty interests, working interests, mineral interests, real estate, producing and non-producing wells, reserves, oil and gas related equipment including transportation lines and potential investments in entities that invest in such assets except for other investment partnerships sponsored by affiliates of MEI.
Between August 2009 and April 2010 MEI sold 61.35 units of securities in a private placement resulting in gross proceeds to it of $3,067,500. Each unit consisted of a $50,000 limited partnership interest in MEI, together with 25,000 shares of our common stock and a five year warrant to purchase an additional 25,000 shares of our common stock with an exercise price of $1.00 per share. If purchasers did not subscribe for a full unit, the unit did not include our securities. We issued a total of 1,329,250 shares of our common stock and common stock purchase warrants to purchase an additional 1,329,250 shares of our common stock. As described above, MEI paid Dimirak Securities Corporation, a related party, $74,345 in connection with this offering.
Between November 2009 and December 2009 we borrowed an aggregate of $2,730,444 from MEI under the terms of four year secured promissory notes. Interest is payable at the rate of 12% per annum, with interest only payments due monthly. In connection with these loans, we granted MEI a first priority security interest in oil and gas drilling equipment owned by us. Pursuant to the terms of an escrow agreement, a third-party escrow agent has been retained to hold the certificates of title for the collateral to which title is evidenced by a certificate. The remaining equipment is subject to a financing statement that has been filed with the Tennessee Secretary of State. We used the
54
proceeds from these loans for general corporate purposes including reducing outstanding debt and to partially fund the Alaska transaction.
Loan commitment from Vulcan Capital Corporation, LLC
As described earlier in this annual report under “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Loan commitment from Vulcan Capital Corporation, LLC,” we have entered into a letter agreement with Vulcan Capital Corporation, LLC, an affiliate of Mr. Ford Graham, an executive officer and member of our Board of Directors from December 2009 to June 2010, to provide us up to $36.5 million of debt funding for our Alaskan operations. We have agreed to pay Vulcan Capital Corporation certain amounts in connection with this funding.
There are no assurances that the terms of the transactions with the related parties are comparable to terms we could have obtained from unaffiliated third parties.
Director Independence
Messrs. Stivers, Gettelfinger, Gross, McPeak and Voyticky are considered independent within The NASDAQ Stock Market’s director independence standards pursuant to Marketplace Rule 5605.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES.
The following table shows the fees that were billed for the audit and other services provided by Sherb & Co., LLP for 2010 and 2009.
|
| 2010 |
| 2009 |
| ||
|
|
|
|
|
|
|
|
Audit Fees |
| $ | 128,500 |
| $ | 65,000 |
|
Audit-Related Fees |
|
| 0 |
|
| 1,500 |
|
Tax Fees |
|
| 0 |
|
| 0 |
|
All Other Fees |
|
| 0 |
|
| 0 |
|
Total |
| $ | 128,500 |
| $ | 66,500 |
|
Audit Fees — This category includes the audit of our annual financial statements, review of financial statements included in our Quarterly Reports on Form 10-Q and services that are normally provided by the independent registered public accounting firm in connection with engagements for those fiscal years. This category also includes advice on audit and accounting matters that arose during, or as a result of, the audit or the review of interim financial statements.
Audit-Related Fees — This category consists of assurance and related services by the independent registered public accounting firm that are reasonably related to the performance of the audit or review of our financial statements and are not reported above under “Audit Fees.” The services for the fees disclosed under this category include consultation regarding our correspondence with the Securities and Exchange Commission and other accounting consulting.
Tax Fees — This category consists of professional services rendered by our independent registered public accounting firm for tax compliance and tax advice. The services for the fees disclosed under this category include tax return preparation and technical tax advice.
All Other Fees — This category consists of fees for other miscellaneous items.
Our Board of Directors has adopted a procedure for pre-approval of all fees charged by our independent registered public accounting firm. Under the procedure, the Board approves the engagement letter with respect to audit, tax and review services. Other fees are subject to pre-approval by the Board, or, in the period between meetings, by a designated member of Board. Any such approval by the designated member is disclosed to the entire Board at the next meeting. The audit and tax fees paid to the auditors with respect to 2010 were pre-approved by the entire Board of Directors.
55
PART IV
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
The following documents are filed as a part of this report or are incorporated by reference to previous filings, if so indicated:
Exhibit No. |
| Description of Exhibit |
2.1 |
| Agreement and Plan of Reorganization dated December 20, 1996 between Triple Chip Systems, Inc. and Miller Petroleum, Inc. (1) |
3.1 |
| Certificate of Incorporation (2) |
3.2 |
| Certificate of Amendment of Certificate of Incorporation (2) |
3.3 |
| Certificate of Amendment of Certificate of Incorporation (2) |
3.4 |
| Certificate of Ownership and Merger and Articles of Merger between Triple Chip Systems, Inc. and Miller Petroleum, Inc. (3) |
3.5 |
| Amended and Restated Charter of Miller Petroleum, Inc. (18) |
3.6 |
| Amended and Restated Bylaws of Miller Petroleum, Inc. (18) |
4.1 |
| Form of Stock Purchase Warrant issued May 4, 2005 to Prospect Energy Corporation (4) |
4.2 |
| Form of Stock Purchase Warrant issued May 4, 2005 to Petro Capital III, L.P. (4) |
4.3 |
| Form of Stock Purchase Warrant issued May 4, 2005 to Petrol Capital Advisors, LLC (4) |
4.4 |
| Form of Stock Purchase Warrant issued December 31, 2005 to Petro Capital III, L.P. (5) |
4.5 |
| Form of Stock Purchase Warrant issued December 31, 2005 to Prospect Energy Corporation (5) |
4.6 |
| Form of Stock Purchase Warrant issued December 31, 2005 to Petro Capital Advisors, LLC (5) |
4.7 |
| Form of warrant issued to Cresta Capital Corporation (12) |
4.8 |
| Form of option granted to Paul W. Boyd (12) |
4.9 |
| Form of warrant issued to David M. Hall, Walter J. Wilcox, II and Troy Stafford (15) |
4.10 |
| 6% Convertible Secured Promissory Note (15) |
4.11 |
| Form of common stock purchase warrant for March 2010 private placement * |
4.12 |
| Form of common stock purchase warrant issued to purchasers in the Miller Energy Income Fund 2009-A, LP offering * |
4.13 |
| Form of common stock purchase warrant issued to Sutter Securities Incorporated* |
10.1 |
| Purchase and Sale Agreement dated December 16, 1997 between AKS Energy Corporation and Miller Petroleum, Inc. (6) |
10.2 |
| Assumption Agreement dated December 16, 1997 between AKS Energy Corporation and Miller Petroleum, Inc. (6) |
10.3 |
| Purchase and Sale Agreement dated September 6, 2000 between NAMI Resources Company, LLC and Miller Petroleum, Inc. (7) |
10.4 |
| Employment Agreement as of August 1, 2008 with Scott M. Boruff (8) |
10.5 |
| Amendment to Employment Agreement with Scott M. Boruff dated September 9, 2008 (9) |
10.6 |
| Form of Registration Rights Agreement dated May 4, 2005 by and among Miller Petroleum, Inc., Petro Energy Corporation, Petrol Capital III, L.P. and Petro Capital Advisors, LLC. (4) |
10.7 |
| Farmout Agreement dated September 3, 1999 between Tengasco, Inc. and Miller Petroleum, Inc. (3) |
10.8 |
| Registration Rights Agreement dated May 4, 2005 (4) |
10.9 |
| Purchase and Sale Agreement dated June 13, 2008 between Atlas Energy Resources, LLC and Miller Petroleum, Inc. (8) |
10.10 |
| Termination Agreement, General Release and Covenant No To Sue Dated June 13, 2008 with Cresta Capital Strategies, LLC (12) |
10.11 |
| Agreement dated June 8, 2009 between Ky-Tenn Oil, Inc. and Miller Petroleum, Inc. (13) |
10.12 |
| Agreement dated June 18, 2009 for Sale of Capital Stock of East Tennessee Consultants, Inc. and Sale of Membership Interests of East Tennessee Consultants II, LLC (14) |
10.13 |
| Agreement for Sale of Membership Interest in Cook Inlet Energy, LLC (15) |
10.14 |
| Form of Securities Purchase Agreement for December 2009 private placement (16) |
10.15 |
| First Secured Promissory Note from Miller Petroleum, Inc. to Miller Energy Income 2009-A, LP (17) |
10.16 |
| Second Secured Promissory Note from Miller Petroleum, Inc. to Miller Energy Income 2009-A, LP (17) |
10.17 |
| Loan and Security Agreement between Miller Petroleum, Inc and Miller Energy Income 2009-A, LP (17) |
56
Exhibit No. |
| Description of Exhibit |
10.18 |
| Escrow Agreement (17) |
10.19 |
| Form of Securities Purchase Agreement for March 2010 private placement * |
10.20 |
| Form of Registration Rights Agreement for March 2010 private placement * |
10.21 |
| Finder’s Agreement with Sutter Securities Incorporated dated December 28, 2009 * |
10.22 |
| Finder’s Agreement with Sutter Securities Incorporated dated March 18, 2010 * |
10.23 |
| Miller Petroleum, Inc. Stock Plan (18) |
10.24 |
| Consulting Agreement dated March 12, 2010 with Bristol Capital, LLC * |
10.25 |
| Marketing Agreement dated August 1, 2009 with The Dimirak Companies * |
10.26 |
| Consulting Agreement dated February 1, 2010 with Tyler Energy Consulting Group * |
10.27 |
| Letter Agreement dated November 5, 2009 between Vulcan Capital Corporation, LLC and Miller Petroleum, Inc. * |
10.28 |
| Assignment Oversight Agreement dated November 5, 2009 between Cook Inlet Energy, LLC and The State of Alaska Department of Natural Resources * |
10.29 |
| Cook Inlet Energy, LLC Master Services Agreement with Fairweather E&P Services, Inc. dated January 1, 2010 * |
10.30 |
| Purchase and Sale Agreement by and between Cook Inlet Energy, LLC and Pacific Energy Alaska Operating LLC and Pacific Energy Alaska Holdings, LLC dated as of November 24, 2009 (20) |
10.31 |
| Cook Inlet Spill Prevention and Response, Inc. Bylaws and Response Action Contract * |
10.32 |
| Separation Agreement and General Release with Ford F. Graham (19) |
14.1 |
| Code of Business Conduct and Ethics (10) |
21.1 |
| Subsidiaries of the registrant * |
23.1 |
| Consent of Ralph E. Davis Associates, Inc.* |
23.2 |
| Consent of Lee Keeling and Associates, Inc. * |
31.1 |
| Rule 13a-14(a)/15d-14(a) certification of Chief Executive Officer * |
31.2 |
| Rule 13a-14(a)/15d-14(a) certification of Chief Financial Officer * |
32.1 |
| Section 1350 certification of Chief Executive Officer * |
32.2 |
| Section 1350 certification of Chief Financial Officer * |
99.1 |
| Reserve Report of Ralph E. Davis Associates, Inc. at April 30, 2010 on Cook Inlet assets * |
99.2 |
| Reserve Reports of Lee Keeling and Associates, Inc. at April 30, 2010 on Appalachian region assets * |
———————
*
filed herewith
(1)
Incorporated by reference to the Current Report on Form 8-K dated January 15, 1997.
(2)
Incorporated by reference to the Annual Report on Form 10-KSB for the year ended December 31, 1995.
(3)
Incorporated by reference to the exhibits filed with the registration statement on Form SB-2, SEC File No. 333-53856, as amended.
(4)
Incorporated by reference to the Current Report on Form 8-K dated May 9, 2005.
(5)
Incorporated by reference to the Quarterly Report on Form 10-QSB for the period ended January 31, 2006.
(6)
Incorporated by reference to the Current Report on Form 8-K dated March 17, 1998.
(7)
Incorporated by reference to the Current Report on Form 8-K dated September 21, 2000.
(8)
Incorporated by reference to the Annual Report on Form 10-KSB for the year ended April 30, 2008.
(9)
Incorporated by reference to the Current Report on Form 8-K dated September 12, 2008
(10)
Incorporated by reference to the Annual Report on Form 10-KSB for the year ended April 30, 2007.
(11)
Incorporated by reference to the Current Report on Form 8-K dated August 21, 2008.
(12)
Incorporated by reference to the Annual Report on Form 10-K for the year ended April 30, 2009.
(13)
Incorporated by reference to the Current Report on Form 8-K filed on June 12, 2009.
(14)
Incorporated by reference to the Current Report on Form 8-K filed on June 24, 2009.
(15)
Incorporated by reference to the Current Report on Form 8-K filed on December 23, 2009.
(16)
Incorporated by reference to the Current Report on Form 8-K filed on January 4, 2010.
(17)
Incorporated by reference to the Quarterly Report on Form 10-Q for the period ended January 31, 2010.
(18)
Incorporated by reference to the Current Report on Form 8-K filed on April 29, 2010.
(19)
Incorporated by reference to the Current Report on Form 8-K filed on June 28, 2010.
(20)
Incorporated by reference to the Current Report on Form 8-K/A filed on July 27, 2010.
57
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.
Date: July 27, 2010
| MILLER PETROLEUM, INC. | |
|
|
|
|
|
|
| By: | /s/ SCOTT BORUFF |
|
| Chief Executive Officer |
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.
Signature |
| Title |
| Date |
|
|
|
|
|
/s/ DELOY MILLER |
| Chairman of the Board |
|
|
Deloy Miller |
|
|
| July 27, 2010 |
|
|
|
|
|
/s/ SCOTT M. BORUFF |
| Chief Executive Officer, director, principal |
|
|
Scott M. Boruff |
| executive officer |
| July 27, 2010 |
|
|
|
|
|
/s/ PAUL W. BOYD |
| Chief Financial Officer, principal financial and |
|
|
Paul W. Boyd |
| accounting officer |
| July 27, 2010 |
|
|
|
|
|
/s/ DAVID M. HALL |
| Director |
|
|
David M. Hall |
|
|
| July 27, 2010 |
|
|
|
|
|
/s/ CHARLES STIVERS |
| Director |
|
|
Charles Stivers |
|
|
| July 27, 2010 |
|
|
|
|
|
/s/ HERMAN GETTLEFINGER |
| Director |
|
|
Herman Gettlefinger |
|
|
| July 27, 2010 |
|
|
|
|
|
/s/ MERRILL A. MCPEAK |
| Director |
|
|
Merrill A. McPeak |
|
|
| July 27, 2010 |
|
|
|
|
|
/s/ JONATHAN S. GROSS |
| Director |
|
|
Jonathan S. Gross |
|
|
| July 27, 2010 |
|
|
|
|
|
/s/ DAVID J. VOYTICKY |
| Director |
|
|
David J. Voyticky |
|
|
| July 27, 2010 |
58
MILLER PETROLEUM, INC.
FORM 10-K
INDEX TO FINANCIAL STATEMENTS
| Pages |
Report of Independent Registered Public Accounting Firm | F-2 |
Consolidated Balance Sheets | F-3 |
Consolidated Statements of Operations | F-5 |
Consolidated Statements of Stockholders' Equity | F-6 |
Consolidated Statements of Cash Flows | F-7 |
Notes to the Consolidated Financial Statements | F-9 |
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Miller Petroleum, Inc.
We have audited the accompanying consolidated balance sheets of Miller Petroleum, Inc. as of April 30, 2010 and 2009 and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the years ended April 30, 2010 and 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of April 30, 2010 and 2009, and the results of its operations and cash flows for each of the years ended April 30, 2010 and 2009, in conformity with generally accepted accounting principles in the United States.
| /s/ Sherb & Co., LLP |
| SHERB & CO, LLP |
| Certified Public Accountants |
New York, New York
July 25, 2010
F-2
MILLER PETROLEUM, INC.
CONSOLIDATED BALANCE SHEETS
|
| April 30, |
| April 30, |
| ||
ASSETS |
|
|
|
|
|
|
|
CURRENT ASSETS |
|
|
|
|
|
|
|
Cash |
| $ | 2,750,841 |
| $ | 46,566 |
|
Cash – restricted |
|
| 126,064 |
|
| 1,982,552 |
|
Accounts receivable, net |
|
| 1,444,844 |
|
| 124,815 |
|
Accounts receivable - related parties |
|
| 47,446 |
|
| 19,882 |
|
Prepaid expenses |
|
| 521,639 |
|
| 87,120 |
|
Inventory |
|
| 275,610 |
|
| — |
|
Total Current Assets |
|
| 5,166,444 |
|
| 2,260,935 |
|
|
|
|
|
|
|
|
|
Fixed Assets |
|
| 116,782,535 |
|
| 5,751,017 |
|
Less: accumulated depreciation |
|
| (1,961,756 | ) |
| (1,022,017 | ) |
Net Fixed Assets |
|
| 114,820,779 |
|
| 4,729,000 |
|
|
|
|
|
|
|
|
|
OIL AND GAS PROPERTIES |
|
|
|
|
|
|
|
(On the basis of successful efforts accounting) |
|
| 376,216,621 |
|
| 1,787,911 |
|
|
|
|
|
|
|
|
|
Land |
|
| 526,500 |
|
| 406,500 |
|
Deferred Interest |
|
| — |
|
| 6,892 |
|
Prepaid Offering Cost |
|
| — |
|
| 666,476 |
|
Cash - restricted long-term |
|
| 2,071,839 |
|
| 84,019 |
|
Other assets |
|
| 1,649,972 |
|
| — |
|
Total Other Assets |
|
| 4,248,311 |
|
| 1,163,887 |
|
TOTAL ASSETS |
| $ | 500,452,155 |
| $ | 9,941,733 |
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES |
|
|
|
|
|
|
|
Accounts payable – trade |
| $ | 3,579,112 |
| $ | 301,082 |
|
Accrued expenses |
|
| 421,938 |
|
| 271,099 |
|
Current derivative liability |
|
| 720,840 |
|
| — |
|
Unearned revenue |
|
| 106,443 |
|
| 131,587 |
|
Current portion of notes payable |
|
| — |
|
| 1,870,732 |
|
Total Current Liabilities |
|
| 4,828,333 |
|
| 2,574,500 |
|
|
|
|
|
|
|
|
|
LONG-TERM LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes payable |
|
| 184,468,878 |
|
| 778 |
|
Asset retirement liability |
|
| 15,662,002 |
|
| 57,246 |
|
Long-term derivative liability |
|
| 16,708,947 |
|
| — |
|
Notes payable – related parties |
|
| 1,803,775 |
|
| — |
|
Notes payable – other |
|
| 1,239,399 |
|
| 88,473 |
|
Total Long-term Liabilities |
|
| 219,883,001 |
|
| 146,497 |
|
Total Liabilities |
|
| 224,711,334 |
|
| 2,720,997 |
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' EQUITY |
|
|
|
|
|
|
|
Common stock, 500,000,000 shares authorized and outstanding $0.0001 par value, 32,224,894 and 15,974,356 shares issued and outstanding, respectively |
|
| 3,223 |
|
| 1,597 |
|
Additional paid-in capital |
|
| 27,620,605 |
|
| 8,555,324 |
|
Retained earnings (accumulated deficit) |
|
| 248,116,993 |
|
| (1,336,185 | ) |
Total Stockholders' Equity |
|
| 275,740,821 |
|
| 7,220,736 |
|
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY |
| $ | 500,452,155 |
| $ | 9,941,733 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-3
MILLER PETROLEUM, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
|
| Year Ended |
| ||||
|
| April 30, |
| April 30, |
| ||
REVENUES |
|
|
|
|
|
|
|
Oil and gas revenue |
| $ | 4,437,215 |
| $ | 640,094 |
|
Service and drilling revenue |
|
| 1,429,789 |
|
| 927,210 |
|
Total Revenue |
|
| 5,867,004 |
|
| 1,567,304 |
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES |
|
|
|
|
|
|
|
Cost of oil and gas revenue |
|
| 2,583,383 |
|
| 240,389 |
|
Cost of service and drilling revenue |
|
| 1,342,509 |
|
| 1,184,901 |
|
Selling, general and administrative |
|
| 10,345,216 |
|
| 2,712,943 |
|
Depreciation, depletion and amortization |
|
| 2,709,308 |
|
| 649,070 |
|
Total Costs and Expenses |
|
| 16,980,416 |
|
| 4,787,303 |
|
|
|
|
|
|
|
|
|
LOSS FROM OPERATIONS |
|
| (11,113,412 | ) |
| (3,219,999 | ) |
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
Interest income |
|
| 25,616 |
|
| 62,741 |
|
Interest expense |
|
| (527,355 | ) |
| (87,526 | ) |
Loss on derivative securities |
|
| (15,861,007 | ) |
| — |
|
Loan fees and costs |
|
| (741,309 | ) |
| (124,085 | ) |
(Loss) gain on disposal of equipment |
|
| (9,755 | ) |
| 10,450 |
|
Gain on sale of oil and gas properties |
|
| — |
|
| 11,715,570 |
|
Gain on acquisitions |
|
| 461,111,924 |
|
| — |
|
Total Other Income |
|
| 443,998,114 |
|
| 11,577,150 |
|
|
|
|
|
|
|
|
|
NET INCOME BEFORE INCOME TAXES |
|
| 432,884,702 |
|
| 8,357,151 |
|
|
|
|
|
|
|
|
|
INCOME TAX EXPENSE |
|
| 183,431,522 |
|
| 778 |
|
|
|
|
|
|
|
|
|
NET INCOME |
| $ | 249,453,180 |
| $ | 8,356,373 |
|
|
|
|
|
|
|
|
|
INCOME PER SHARE |
|
|
|
|
|
|
|
BASIC |
| $ | 11.58 |
| $ | 0.56 |
|
DILUTED |
| $ | 8.29 |
| $ | 0.56 |
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING |
|
|
|
|
|
|
|
BASIC |
|
| 21,537,677 |
|
| 14,827,877 |
|
DILUTED |
|
| 30,092,017 |
|
| 14,827,877 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-4
MILLER PETROLEUM, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
|
| Common |
| Shares Amount |
| Additional |
| Accumulated |
| Total |
| |||||
Balance, April 30, 2008 |
|
| 11,666,856 |
|
| 1,166 |
|
| 6,949,761 |
|
| (9,692,558 | ) |
| (2,741,631 | ) |
Issuance of warrants |
|
| — |
|
| — |
|
| 174,000 |
|
| — |
|
| 174,000 |
|
Issuance of stock for compensation |
|
| 3,762,500 |
|
| 376 |
|
| 1,153,249 |
|
| — |
|
| 1,153,625 |
|
Stock option expense |
|
| — |
|
| — |
|
| 17,800 |
|
| — |
|
| 17,800 |
|
Issuance of warrants for financing cost |
|
| — |
|
| — |
|
| 122,818 |
|
| — |
|
| 122,818 |
|
Issuance of stock for financing cost |
|
| 350,000 |
|
| 35 |
|
| 136,965 |
|
| — |
|
| 137,000 |
|
Exercise of warrants |
|
| 195,000 |
|
| 20 |
|
| 731 |
|
| — |
|
| 751 |
|
Net income |
|
| — |
|
| — |
|
| — |
|
| 8,356,373 |
|
| 8,356,373 |
|
Balance, April 30, 2009 |
|
| 15,974,356 |
| $ | 1,597 |
| $ | 8,555,324 |
| $ | (1,336,185 | ) | $ | 7,220,736 |
|
Sale of equity for cash |
|
| 7,893,432 |
|
| 790 |
|
| 9,645,688 |
|
| — |
|
| 9,646,478 |
|
Issuance of equity for acquisitions |
|
| 2,000,000 |
|
| 200 |
|
| 2,641,455 |
|
| — |
|
| 2,641,655 |
|
Issuance of equity for compensation |
|
| 100,000 |
|
| 10 |
|
| 1,662,210 |
|
| — |
|
| 1,662,220 |
|
Issuance of stock for financing cost |
|
| 1,679,250 |
|
| 168 |
|
| 1,139,214 |
|
| — |
|
| 1,139,382 |
|
Exercise of warrants |
|
| 2,017,847 |
|
| 202 |
|
| 281,798 |
|
| — |
|
| 282,000 |
|
Issuance of equity for services |
|
| 469,100 |
|
| 47 |
|
| 1,735,861 |
|
| — |
|
| 1,735,908 |
|
Beneficial conversion features |
|
| — |
|
| — |
|
| 809,263 |
|
| — |
|
| 809,263 |
|
Conversion of notes |
|
| 2,090,909 |
|
| 209 |
|
| 1,149,791 |
|
| — |
|
| 1,150,000 |
|
Net income |
|
| — |
|
| — |
|
| — |
|
| 249,453,180 |
|
| 249,453,180 |
|
Balance, April 30, 2010 |
|
| 32,224,894 |
| $ | 3,223 |
| $ | 27,620,604 |
| $ | 248,116,995 |
| $ | 275,740,822 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-5
MILLER PETROLEUM, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
|
| Year Ended |
| ||||
|
| April 30, |
| April 30, |
| ||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
Net Income |
| $ | 249,453,180 |
| $ | 8,356,373 |
|
Depreciation, depletion and amortization |
|
| 2,709,308 |
|
| 649,070 |
|
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided |
|
|
|
|
|
|
|
Gain on sale of equipment |
|
| 9,755 |
|
| (10,450 | ) |
Gain on sale of oil and gas properties |
|
| — |
|
| (11,715,570 | ) |
Gain on acquisitions |
|
| (461,111,924 | ) |
| — |
|
Prepaid offering cost |
|
| 666,476 |
|
| (666,476 | ) |
Issuance of equity for services |
|
| 1,735,908 |
|
| 174,751 |
|
Issuance of equity for compensation |
|
| 1,662,220 |
|
| 1,171,425 |
|
Issuance of equity issuances for financing cost |
|
| 494,758 |
|
| 259,818 |
|
Changes in Operating Assets and Liabilities: |
|
|
|
|
|
|
|
Accounts receivable |
|
| (1,347,593 | ) |
| (8,251 | ) |
Inventory |
|
| (434,519 | ) |
| (21,264 | ) |
Prepaid expense |
|
| (275,610 | ) |
| — |
|
Accounts payable |
|
| 3,278,031 |
|
| (154,168 | ) |
Accrued expenses |
|
| 150,837 |
|
| 118,147 |
|
Derivative liability, net |
|
| 17,429,787 |
|
| — |
|
Unearned revenue |
|
| (25,144 | ) |
| 131,587 |
|
Income taxes payable |
|
| 184,468,100 |
|
| 778 |
|
Deferred interest |
|
| 6,891 |
|
| (6,892 | ) |
Other assets |
|
| (1,030,613 | ) |
| — |
|
Net Cash Used by Operating Activities |
|
| (2,160,152 | ) |
| (1,721,122 | ) |
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
Purchase of equipment and improvements |
|
| (409,735 | ) |
| (4,408,998 | ) |
Purchase of land |
|
| — |
|
| (110,000 | ) |
Sale of oil and gas properties |
|
| 25,000 |
|
| 12,519,713 |
|
Investment in oil and gas properties |
|
| (5,600,843 | ) |
| (1,268,942 | ) |
Proceeds from sale of equipment |
|
| 50,000 |
|
| 28,500 |
|
Cash paid for Alaska Acquisition |
|
| (4,541,252 | ) |
| — |
|
Net Cash Provided (Used) by Investing Activities |
|
| (10,476,830 | ) |
| 6,760,273 |
|
(continued)
The accompanying notes are an integral part of these consolidated financial statements.
F-6
MILLER PETROLEUM, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(continued)
|
| Year Ended |
| ||||
|
| April 30, |
| April 30, |
| ||
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
Payments on notes payable |
|
| (2,309,205 | ) |
| (726,630 | ) |
Asset Retirement Liability |
|
| 415,315 |
|
| — |
|
Deferred financing assets |
|
| (619,359 | ) |
| — |
|
Proceeds from borrowing |
|
| 5,926,444 |
|
| 2,025,180 |
|
Proceeds from sale of stock, net |
|
| 9,646,478 |
|
| — |
|
Cash acquired through acquisition |
|
| 203,993 |
|
| — |
|
Exercise of equity rights |
|
| 282,000 |
|
| — |
|
Restricted cash |
|
| 1,856,488 |
|
| (1,982,552 | ) |
Restricted cash non-current |
|
| (60,897 | ) |
| (1,019 | ) |
Stock repurchase |
|
| — |
|
| (4,350,000 | ) |
Net Cash Provided (Used) by Financing Activities |
|
| 15,341,257 |
|
| (5,035,021 | ) |
|
|
|
|
|
|
|
|
NET INCREASE IN CASH |
|
| 2,704,275 |
|
| 4,130 |
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR |
|
| 46,566 |
|
| 42,436 |
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, END OF YEAR |
| $ | 2,750,841 |
| $ | 46,566 |
|
|
|
|
|
|
|
|
|
CASH PAID FOR:INTEREST |
| $ | 603,034 |
| $ | 87,526 |
|
|
|
|
|
|
|
|
|
INCOME TAXES |
| $ | — |
| $ | — |
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND |
|
|
|
|
|
|
|
Portion of Alaska acquisition financed by equity |
| $ | 2,071,655 |
| $ | — |
|
Beneficial conversion right of debt issues |
| $ | 809,263 |
| $ | — |
|
Fair value of equity rights issued with debt |
| $ | 1,048,765 |
| $ | — |
|
Common stock issued for prepaid offering costs |
| $ | — |
| $ | — |
|
Financing costs from issuance of warrants and stock |
| $ | — |
| $ | 259,783 |
|
Cash acquired from issuance of stock |
| $ | 203,993 |
| $ | — |
|
Restricted cash acquired from issuance of stock |
| $ | 196,682 |
| $ | — |
|
Net assets acquired from issuance of stock |
| $ | (5,111,252 | ) | $ | — |
|
Conversion of debt for equity |
| $ | 1,150,000 |
| $ | — |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-7
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
APRIL 30, 2010 AND 2009
(1)
ORGANIZATION AND DESCRIPTION OF BUSINESS
These consolidated financial statements include the accounts of Miller Petroleum, Inc. and the accounts of its subsidiaries, Miller Drilling TN, LLC, Miller Rig & Equipment, LLC, Miller Energy Services, LLC, East Tennessee Consultants II, LLC, East Tennessee Consultants, Inc., Miller Energy GP, LLC, and Cook Inlet Energy, LLC.
The Company's principal business consists of oil and gas exploration, production and related property management in the Cook Inlet region of Alaska and the Appalachian region of eastern Tennessee. The Company's corporate offices are in Huntsville, Tennessee. The Company operates as one reportable business segment, based on the similarity of activities.
(2)
ACCOUNTING POLICIES
Oil And Gas Activities
The Company follows the successful efforts method of accounting for its oil and gas activities. Accordingly, costs associated with the acquisition, drilling and equipping of successful exploratory wells are capitalized. Geological and geophysical costs, delay and surface rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. Costs of drilling development wells are capitalized. Upon the sale or retirement of oil and gas properties, the cost and accumulated depreciation or depletion are removed from the accounts and any gain or loss is credited or charged to operations.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization of capitalized costs of proved oil and gas properties is provided on a pooled basis using the units-of-production method based upon proved reserves. Acquisition costs of proved properties are amortized by using total estimated units of proved reserves as the denominator. All other costs are amortized using total estimated units of proved developed reserves.
Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of
ASC 350-35, “Impairment or Disposal of Long-Lived Assets” (formerly SFAS 144, requires that an asset be evaluated for impairment when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In accordance with the provisions of ASC 360-35 (formerly SFAS 144), the Company reviews the carrying values of its long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets we grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The long-lived assets of the Company, which are subject to evaluation, consist primarily of oil and gas properties.
No equipment was considered impaired and written off during the years ended April 30, 2009 and 2010.
Net Earnings Per Share:
The Company presents "basic" earnings per share and, if applicable, "diluted" earnings per share pursuant to the accounting guidance, "Earnings Per Share." Basic earnings per share is calculated by dividing net income by the weighted average number of common shares outstanding during each period. The calculation of diluted earnings per share is similar to that of basic earnings per share, except that the denominator is increased to include the number of additional common shares that would have been outstanding if all potentially dilutive common shares of 8,554,340, such as those issuable upon the exercise of stock options and warrants, were issued during fiscal year 2010. There were no dilutive securities for fiscal year 2009.
F-8
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
Cash Equivalents
The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company, and its wholly-owned subsidiaries Miller Drilling TN, LLC, Miller Rig & Equipment, LLC, Miller Energy Services, LLC, East Tennessee Consultants II, LLC, East Tennessee Consultants, Inc., Miller Energy GP, LLC, and Cook Inlet Energy, LLC. All significant intercompany transactions have been eliminated.
Accounts Receivable
At April 30, 2010 and 2009 accounts receivable consists of amounts due from the sale of oil and gas. The Company deems all accounts receivable collectible at April 30, 2010 and 2009 after deducting $0 and $10,475, respectively, for an allowance for doubtful accounts.
Inventory
Inventory consists primarily of crude oil in tanks and is carried at cost.
Fixed Assets
Fixed assets are stated at cost. Depreciation and amortization are computed using the straight-line method for financial reporting purposes and accelerated methods for income tax purposes. The estimated useful lives are as follows:
Class |
| Lives in Years |
Building |
| 40 |
Oil Platform |
| 40 |
Pipelines |
| 30 |
Machinery and equipment |
| 5-20 |
Vehicles |
| 5-7 |
Office equipment |
| 5 |
Prepaid Offering Cost
Prepaid offering costs, primarily consisting of legal, accounting, printing and filing fees relating to an offering have been capitalized. The prepaid offering costs will be offset against offering proceeds in the event the offering is successful. In the event the offering is unsuccessful or is abandoned, the prepaid offering costs will be expensed. In 2010, all prepaid offering costs totaling $666,476 were expensed.
Revenue Recognition
Oil and gas production revenue is recognized as income as production is extracted and sold. Service and drilling income is recognized at the time it is both earned and we have a contractual right to receive the revenue. Turnkey contracts not completed at year-end are reported on the completed contract method of accounting. There were no uncompleted contracts at the end of fiscal 2010 and 2009, respectively. Sales of various parts and equipment is immaterial for the years ended April 30, 2010 and 2009 and has been combined with service and drilling revenue.
Concentrations of Credit Risk
Financial instruments, which potentially subject the Company to concentrations of credit risk, are primarily cash and cash equivalents and accounts receivable. The Company places its cash investments, which at times may exceed federally insured amounts, in highly rated financial institutions.
F-9
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
Accounts receivable arise from sales of gas and oil, equipment and services. Credit is extended based on the evaluation of the customer's creditworthiness, and, generally, collateral is not required. Accounts receivable more than 45 days old are considered past due. The Company does not accrue late fees or interest income on past due accounts. Management uses the aging of accounts receivable to establish an allowance for doubtful accounts. Credit losses are written off to the allowance at the time they are deemed not to be collectible. Credit losses have historically been minimal and within management's expectations. The allowance for doubtful accounts was $0 at April 30, 2010 and $10,475 at April 30, 2009. Accounts receivable more than 90 days old were $89,144 at April 30, 2010 and $14,410 at April 30, 2009. Bad debt expense for the year ended April 30, 2010 and 2009 was $0 and $15,081, respectively.
Financial instruments, which potentially subject us to concentration of credit risk, consist principally of cash described below.
For the year ended April 30, 2010 we had $1,400,839 in restricted and unrestricted cash balances in excess of the $250,000 limit insured by the Federal Deposit Insurance Corporation. For the year ended April 30, 2009 we had $1,732,552 in balances in excess of the $250,000 limit insured by the Federal Deposit Insurance Corporation.
Major Customers
The Company depends upon local purchasers of hydrocarbons to purchase our products in the areas where its properties are located. Currently, we are selling oil and natural gas to the following purchasers:
Oil: |
| Sunoco purchases oil from the Koppers Fields and accounted for $531,531 and $191,503 of the Company's total revenue, which was 9% and 12% of the Company's total revenue, respectively for fiscal 2010 and 2009. |
|
|
|
|
| Tesoro Corporation purchases all oil from our Alaska production facilities and accounts for 82% of the Company’s total revenue and 57% of all Accounts receivable, net. |
|
|
|
Gas: |
| Cumberland Valley Resources purchases natural gas produced from the joint venture with Delta Producers, Inc. in the Jellico East Field and Lindsay Land Company. Delta Producers Inc. accounted for $238,669 and $629,298 of the Company's total revenue, which was 4% and 40% of the Company's total revenue, respectively for fiscal 2010 and 2009. |
|
|
|
Drilling: |
| Vinland Energy, Delta Producers Inc. and Herman Gettelfinger accounted for $42,152 and $435,422, which was 3% and 47% of the Company's service and drilling revenue, respectively for fiscal 2010 and 2009. |
|
|
|
|
| Atlas America, LLC has contracted with us to perform drilling for them on an as needed basis. During fiscal 2010, Atlas America, LLC accounted for $461,302 and $436,935, which was 32% and 47% of the Company's service and drilling revenue, respectively for fiscal 2010 and 2009. |
F-10
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
Use of Estimates
Our financial statements are prepared in accordance with United States generally accepted accounting principles, or GAAP. Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the United States Securities and Exchange Commission (SEC) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. This Note describes our significant accounting policies. Our management believes the major estimates and assumptions impacting our financial statements are the following:
·
estimates of oil and gas reserve quantities, which affect the calculations of gains from acquisitions and amortization and impairment of capitalized costs of oil and gas properties;
·
estimates of the fair value of oil and gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells;
·
asset retirement obligation liabilities;
·
estimates of the fair value of stock options and warrants at date of grant;
·
estimates of the fair value of derivative liabilities; and
·
estimates as to the future realization of deferred income tax assets.
Oil and gas reserve estimates for Tennessee operations are developed from information provided by the Company's management to Lee Keeling & Associates, Inc. of Tulsa, Oklahoma for the years ended April 30, 2010 and 2009, respectively. Oil and gas reserve estimates for Alaska operations are developed from information provided by the Company's management to Ralph E. Davis Associates, Inc. of Houston, Texas for the year ended April 30, 2010.
The estimated fair values of our unevaluated oil and gas properties affect the calculation of gain on the sale of material properties and affect our assessment as to whether portions of unevaluated capitalized costs are impaired, which also affects the calculation of recorded amortization and impairment expense with regards to our capitalized costs of oil and gas properties.
The fair value of stock options at the date of grant to employees and members of our Board of Directors is based on judgment as to expected future volatility of our common stock and expected future choices by option holders as to when options are exercised.
The application of EITF 07-05 “Determining Whether an Instrument (or Embedded Feature) is Indexed to a Company's Own Stock,” which was codified into ASC Topic 815 – Derivatives and Hedging, was effective for the Company on May 1, 2009, for both freestanding and embedded derivative financial instruments in our financial statements. Generally, warrants, conversion features in debt, and similar terms that include “full-ratchet” or reset provisions, which mean that the exercise or conversion price adjusts to pricing in subsequent sales or issuances, no longer meet the definition of indexed to a company's own stock and are not exempt for equity classification provided in ASC Topic 815-15. This means that instruments that were previously classified in equity will require reclassification to liabilities and ongoing measurement under ASC Topic 815. The fair value amount of non-cash gains or losses we will record in future periods is unknown at this time as the measurement is based upon the fair market value of our common stock on the measurement date. The non-cash losses recorded for the fiscal year ended 2010 was $15,861,007.
Actual results may differ from estimates and assumptions of future events. Future production may vary materially from estimated oil and gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.
Reclassifications
Certain amounts and balances pertaining to the April 30, 2009 financial statements have been reclassified to conform to the April 30, 2010 financial statement presentations.
F-11
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
Stock Warrants And Options
The Company measures its equity transactions with employees using the fair value based method of accounting.
Income Taxes
The Company accounts for income taxes using the "asset and liability method." Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial reporting and tax basis of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets arise primarily from net operating loss carry forwards. Management evaluates the likelihood of realization of such assets at year-end reserving any such amounts not likely to be recovered in future periods.
We record deferred income tax using enacted tax laws and rates for the years in which we expect the tax to be paid. We provide deferred income tax when there is a temporary difference in recording such items for financial reporting and income tax reporting. The temporary differences that may give rise to deferred tax assets primarily are depletion, depreciation and impairments, which we reduced by a like amount because we are uncertain as to whether we will realize the deferred tax assets.
Fair Value of Financial Instruments
The carrying amounts reported in the balance sheet for cash, receivables, accounts payable and accrued expenses approximate fair value based on the short-term maturity of these instruments.
Recent Accounting Pronouncements
In June 2009, the FASB approved the FASB Accounting Standards Codification (“ASC”), which after its effective date of July 1, 2009 is the single source of authoritative, nongovernmental U.S. Generally Accepted Accounting Principles (GAAP). The Codification reorganizes all previous U.S. GAAP pronouncements into roughly 90 accounting topics and displays all topics using consistent structure. All existing standards that were used to create the Codification are now superseded, replacing the previous references to specific Statements of Financial Accounting Standards (“SFAS”) with numbers used in the Codification’s structural organization. The adoption of this guidance did not have a material impact on our financial statements. We have updated our disclosures accordingly.
Recent changes to SEC Regulation S-K and S-X pertaining to Modernization of Oil and Gas Reporting include changes to the price used to compute reserves, the definition of reserves, the use of technology and the optional disclosure of probable and possible reserves. The new regulations are effective for years ending after December 15, 2009.
In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-06, “Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements.” This ASU requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in Accounting Standards Codification (“ASC”) 820 (formerly SFAS No. 157). ASU 2010-06 amends ASC 820 (formerly SFAS No. 157) to now require: (1) a reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and (2) in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies the requirements of existing disclosures. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. The Company will comply with the additional disclosures required by this guidance upon its adoption in January 2010.
F-12
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
In January 2010, the FASB issued Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas—Oil and Gas Reserve Estimation and Disclosures.” This ASU amends the “Extractive Industries—Oil and Gas” Topic of the Codification to align the oil and gas reserve estimation and disclosure requirements in this Topic with the SEC’s Release No. 33-8995, “Modernization of Oil and Gas Reporting Requirements (Final Rule),” discussed below. The amendments are effective for annual reporting periods ending on or after December 31, 2009, and the adoption of these provisions on December 31, 2009 did not have a material impact on our consolidated financial statements.
On February 24, 2010, the FASB issued Accounting Standards Update ("ASU") 2010-09, effective immediately, which amended ASC Topic 855, Subsequent Events (formerly SFAS No. 165). The amendment was made to address concerns about conflicts with SEC guidance and other practice issues. Among the provisions of the amendment, the FASB defined a new type of entity, termed an "SEC filer," which is an entity required to file with or furnish its financial statements to the SEC. Entities other than registrants whose financial statements are included in SEC filings (e.g., businesses or real estate operations acquired or to be acquired, equity method investees, and entities whose securities collateralize registered securities) are not SEC filers. While an SEC filer is still required by U.S. GAAP to evaluate subsequent events through the date its financial statements are issued, it is no longer required to disclose in the financial statements that it has done so or the date through which subsequent events have been evaluated. The Company does not believe the changes have a material impact on our results of operations or financial position.
(3)
SALE OF OIL AND GAS PROPERTIES AND EQUIPMENT PURCHASES
On June 13, 2008 we sold approximately 30,000 acres of oil and gas leases and eight drilled but not completed wells to Atlas America, LLC ("Atlas") for $19.625 million. At that time Wind City Oil & Gas, LLC and related entities were paid $10.6 million for 2.9 million shares of the Company's common stock, eight drilled but not completed gas wells, two producing gas wells, and a RD20 drilling rig and related equipment in settlement of all litigation between the parties.
On November 10, 2008, the Company finalized a drilling contract with Atlas Energy Resources, LLC, an affiliate of Atlas. This is a two year agreement that will utilize two of the Company's drilling rigs operating in the East Tennessee area of the Appalachian Basin. We acquired a 2007 COPCO Model RD III drilling rig and related equipment drilling rig from Atlas to assist in drilling the wells. This rig has been mobilized to the site and has commenced drilling operations.
After the sale was completed, the Company paid off all notes, all undisputed payables, transaction fees of $600,000 to Cresta Capital/Consortium, and paid a transaction fee of $300,000 and issued 2,500,000 shares of common stock valued at $825,000 to Scott Boruff, a former associate of Cresta Capital. Boruff was subsequently hired effective August 1, 2008 as the new CEO of the Company (see Commitments note below). He is a son-in-law of Deloy Miller the former CEO and current Chairman of the Board of Directors. Cresta was also granted a warrant to purchase one million shares of the Company's common stock for $1.00 per share for a period expiring three years after the grant date and cancelled the five million performance warrants that it held.
The net gain on this sale of oil and gas property transaction was $11,715,570.
A third party interested in aforementioned sale of the oil and gas properties is contesting the sale, see the Litigation note below
(4)
PARTICIPANT AND RELATED PARTY RECEIVABLES AND RELATED PARTY TRANSACTIONS
Participant and related party receivables consist of receivables contractually due from our various joint venture partners in connection with routine exploration, betterment and maintenance activities. Our collateral for these receivables generally consists of lien rights over the related oil producing properties at both April 30, 2009 and 2010.
F-13
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
The Company had an account receivable from a member of the Board of Directors, and his wife, at April 30, 2009 and April 30, 2009 in the amount of $29,950 and $19,882, respectively for work performed on oil and gas wells. This board member and his wife own partial interests in the oil and gas wells the Company also owns.
The Company had notes payable at April 30, 2010 and April 30, 2009 of $2,721,444 and $0, respectively, to Miller Energy Income 2009-A, LP. Miller Energy Income 2009-A, LP’s general partner is Miller Energy GP, LLC, a 100% owned subsidiary of the Company.
(5)
FIXED ASSETS
Fixed assets consist of the following:
|
| April 30, |
| April 30, |
| ||
Machinery & Equipment |
| $ | 4,620,219 |
| $ | 4,218,556 |
|
Pipelines |
|
| 17,000,000 |
|
| — |
|
Oil platform |
|
| 6,000,000 |
|
| — |
|
Vehicles |
|
| 1,402,094 |
|
| 938,624 |
|
Buildings |
|
| 87,682,810 |
|
| 544,546 |
|
Office Equipment |
|
| 77,411 |
|
| 49,291 |
|
|
|
| 116,782,534 |
|
| 5,751,017 |
|
Less: accumulated depreciation |
|
| (1,961,755 | ) |
| (1,022,017 | ) |
Net Fixed Assets |
| $ | 114,820,779 |
| $ | 4,729,000 |
|
Machinery and equipment was $4,620,219 at April 30, 2010 as compared to $4,218,556 at April 30, 2009. Vehicles were $1,381,592 at April 30, 2010 as compared to $938,624 at April 30, 2009. Buildings increased from $544,546 at April 30, 2009 to $87,682,810 at April 30, 2010. All aforementioned increases were due primarily to the acquisition of $110.5 million of Alaska assets. Office equipment was $77,411 at April 30, 2010 as compared to $49,291 at April 30, 2009. This increase resulted from the purchase of new accounting software and new computers. Depreciation expense for the years ended April 30, 2010 and 2009 was $968,158 and $427,605 respectively.
(6)
ACQUISITIONS
KTO Acquisition
On June 8, 2009, we closed on the acquisition of certain assets of privately owned Ky-Tenn Oil, Inc., ("KTO") which includes approximately 35,325 leased acres located on the Chattanooga Shale and 153 natural gas and oil producing wells. For these assets we issued 1,000,000 shares of our common stock, which was valued at $320,000 on the date of acquisition. The acquired assets included the aforementioned 35,325 leased acres with 153 producing oil and gas wells as well as $194,400 in restricted bond certificates for well reclamation with a related liability. In addition a complaint has been filed in United States District Court for the Eastern District of Tennessee, Northern Division by Gunsight Holdings, LLC, a Florida limited liability company pertaining to KTO and the Company. The lease which is the subject of the litigation was included in the assets purchased by us from KTO. The Plaintiff is alleging that the Company and KTO have failed or refused to pay royalties due to the Plaintiff's predecessors and have breached the implied duty of further exploration by failing to drill required wells, failing to reasonably develop or explore the property, failing to maintain an active interest in further development of the property and otherwise failing to act as a prudent operator of the property thereby causing damages to the Plaintiff exceeding $75,000. The Plaintiff is seeking a declaratory judgment of its allegations, removal of the Company and KTO from the property, a full accounting of activities related to the property and all monies received from those activities, damages and costs of action. We have filed an answer denying the various claims and asserting affirmative defenses including that there has been continuous production from the subject lease. While we intend to vigorously defend this action, we are unable at this time to predict the outcome of the action or whether the company will have any liability to the Plaintiff. See Note 10. No cash or receivables were acquired from KTO. A third-party analysis was performed to determine the fair value of the assets acquired. The report was prepared utilizing methods and procedures regularly used by petroleum engineers to estimate oil and gas reserves for properties of this type and
F-14
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
character. The value as determined by this evaluation was $252,455. The value of the restricted bond certificates had an offsetting retirement liability, therefore, under the guidance of SFAS 141(R)(FASB ASC 805-10) the difference between the value of the oil and gas properties less the value of the common stock resulted in a loss of $67,545 and was recorded in the Consolidated Statements of Operations as a net to Gain on Acquisitions. Pursuant to this FASB guidance, we originally valued these assets at $252,455 and recorded a loss on the transaction of $67,545. Subsequently, we completed the determination of the value of all undeveloped reserves for this acreage during the quarter ended October 31, 2009 and accordingly we recorded an additional gain of $1,057,564 on this transaction.
No additional supplemental pro-forma information with regards to results of operations have been provided as the KTO acquisition was a purchase of select assets only.
ETC Acquisition
On June 18, 2009 the Company acquired 100% of the stock of East Tennessee Consultants, Inc., a Tennessee corporation ("ETC") and 100% of the membership interests in East Tennessee Consultants II, LLC, a Tennessee limited liability company ("LLC") from the owners of these entities. The acquisition included 221 producing oil and gas wells and consisted of approximately 4,442 acres. The Company issued 1,000,000 shares for all of ETC and LLC membership interest. Our common shares were valued at $250,000 on the date of acquisition. The acquisition included the following balance sheet items:
Assets |
|
|
|
| Liabilities and equity |
|
|
|
|
Cash |
| $ | 203,993 |
| Accounts payable |
| $ | 202,760 |
|
Receivables |
|
| 24,904 |
| Deferred tax |
|
| 580,864 |
|
Fixed assets, net |
|
| 313,458 |
| Value of shares issued |
|
| 250,000 |
|
Oil and gas properties |
|
| 1,319,140 |
| Bargain Purchase Gain |
|
| 828,745 |
|
Other assets |
|
| 874 |
|
|
|
|
|
|
Total assets |
| $ | 1,862,369 |
| Total liabilities and equity |
| $ | 1,862,369 |
|
We valued this acquisition under the FASB guidance and, accordingly, a Bargain purchase of $828,745 was recorded as of the acquisition date. For the twelve months ended April 30, 2010 the consolidation of this entity increased the Company revenues by $808,159 and increased costs of revenues by $381,674. The impacts of consolidation on all other line items within our Consolidated Statements of Operations were not significant.
Alaska Acquisition
On December 10, 2009, the Company acquired former Alaskan assets of Pacific Energy Resources (“Pacific Energy”) valued at more than $479 million through a Delaware Chapter 11 Bankruptcy proceeding. The Company acquired the Alaskan oil and gas assets, which include onshore and offshore production facilities, $215 million in proven energy reserves, $122 million in probable energy reserves and $31 million in possible energy reserves, providing total reserves of $368 million. The purchased assets include the West McArthur River oil field, the West Foreland natural gas field, and the Redoubt unit with the Osprey offshore platform, all located along the west side of the Cook Inlet. Also included in the asset purchase are 602,000 acres of oil and gas leases and licenses as well as completed 3D seismic geology and other production facilities. At closing Miller paid Pacific Energy a purchase price of $2.25 million and provided $2.22 million for bonds, contract cure payments and other federal and State of Alaska requirements to operate the facilities. The Company will operate the facilities through its recently acquired wholly-owned subsidiary, Cook Inlet Energy LLC ("Cook"), which has been approved by the State of Alaska as the long-term operator for the Alaskan oil and gas wells. In October 2009, the Company entered into an agreement to acquire the majority of Pacific Energy's Alaskan assets. In November of 2009, the Court approved the sale and the acquisition closed on December 10, 2009.
On December 10, 2009, the Company acquired 100% of the membership interests in Cook Inlet Energy, LLC, an Alaska limited liability company from the owners of this entity. As consideration for this company we issued the sellers, who were unrelated third parties, stock warrants to purchase three million five hundred thousand (3,500,000) shares of our common stock. The Warrants were issued in three tranches with vesting features ranging from immediate to four years and with exercise prices ranging from $0.01 to $2.00, the fair value of the warrants
F-15
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
issued were determined to be $2,071,655 and were expensed as a cost of the transaction. In addition, the Company was obligated to deliver $250,000 in cash by March 10, 2010 to satisfy certain expenses as well as reimbursement for reasonable out of pocket expenses. As of the date of this filing, this obligation is still outstanding. Under the terms of the stock purchase agreement, the sellers agreed not to engage in oil and gas operations for a period of three years following the closing date. We also agreed that each of the sellers, Messrs. David M. Hall, Walter J. Wilcox II and Troy Stafford, would continue their employment with the acquired company for at least three years from the closing date of the transaction at their specifically defined compensation and benefit levels. However, subsequent to the balance sheet date, Mr. Stafford left the Company. In addition, Mr. Hall was appointed as a member of the Company's Board of Directors and as Chief Executive Officer of Cook Inlet Energy, LLC., Mr. Hall will receive an annual salary of $195,000.
The acquisition included the following balance sheet items:
Assets |
|
|
| Liabilities and equity |
|
|
|
| |
Inventory |
| $ | 212,228 |
| Asset Retirement Liability |
| $ | 15,289,995 |
|
Fixed Assets |
|
| 110,516,500 |
| Accounts Payable |
|
| 3,667,522 |
|
Oil and gas properties |
|
| 368,035,281 |
| Deferred Income Tax Payable |
|
| 184,703,206 |
|
Restricted Cash Long |
|
|
|
| Fair value of equity issued |
|
| 2,071,655 |
|
Term |
|
| 1,789,995 |
| Bargain Purchase Gain |
|
| 274,821,626 |
|
Total Assets |
| $ | 480,554,004 |
| Total Liabilities & Equity |
| $ | 480,554,004 |
|
In addition, in a related transaction, the Company issued a $3,000,000 6% Convertible Secured Promissory Note program ("Note"). The Company had raised $2,855,000 through this program to provide to the Alaskan asset transaction. $500,000 of this came from related parties; Director and Chief Executive Officer Scott Boruff and Director Deloy Miller. Interest on the Notes is paid quarterly and the principal is due December 4, 2016. The Note contains a convertible feature which the Note holder has the right, but not the obligation, at the Holder's option, at any time prior to payment in full of the principal balance of the Note, to convert the unpaid principal amount of the Note, in whole or in part, into fully paid and non-assessable shares of Miller's Common Stock at the conversion price of $0.55 per share.
A second program issued by the Company during the quarter ended January 31, 2010 was a securities purchase program whereas the company sold 6,015,000 shares of stock to accredited investors for $1.00 per share. This was a discount of 16.67% from market value on the date of determination. The Company received $6,015,000 in cash, which was used for general corporate purposes, including reducing debt and partially financing the Alaska asset acquisition.
As a result of Miller Petroleum, Inc acquiring a portion of the assets And liabilities Alaskan oil and gas assets from Pacific Energy Alaska Operating LLC and Pacific Energy Alaska Holdings, LLC through a Chapter 11 U.S. bankruptcy proceeding via a newly formed entity Cook, and these oil and gas producing assets were not operational for several months prior to the acquisition due to the bankruptcy nor were accounting records maintained by Pacific Energy Alaska Operating LLC and Pacific Energy Alaska Holdings, LLC on an adequate basis to carve out historical operational results on these specified assets as they were part of a larger enterprise, the resulting assets and liabilities were deemed not to have been a separate business for purposes of preparing pro forma financials with historical results for the past year and / or related stub period. A pro forma balance sheet has been presented only to reflect the acquisition.
(7)
DERIVATIVE LIABILITIES
Effective May 1, 2009, the Company adopted the provisions of EITF 07-05 “Determining Whether an Instrument (or Embedded Feature) is Indexed to a Company's Own Stock,” which was codified into ASC Topic 815 – Derivatives and Hedging. ASC 815 applies to any freestanding financial instruments or embedded features that have characteristics of a derivative and to any freestanding financial instruments that are potentially settled in an entity’s own common stock. The Company has 4,016,715 of warrants with exercise reset provisions, which are considered freestanding derivative instruments. ASC 815 requires these warrants to be recorded as liabilities as they are no longer afforded equity treatment. The derivative liability as of April 30, 2010 of $17,429,787 is comprised
F-16
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
three transactions, 3,000,000 warrants issued in the current and past years, which are subject to an ongoing litigation matter, 716,715 warrants issued in an equity financing in March 2010 and 300,000 warrants issued pursuant to a consulting arrangement in March 2010. The terms of the exercise reset provision on the 716,715 warrants expire in September 2010, hence the related fair value of this derivative of $720,840 has been recorded as a current liability. The Company utilized the Black-Scholes pricing model with the following weighted average assumptions: risk free rate of 1.47%, expected life terms ranging from .42 years to 2.5 years, an expected volatility range of 49% to 140% depending on the term of such equity contracts and a dividend rate of 0.0%. The fair value of the warrants issued and outstanding at May 1, 2009, attributed to this derivative liability has been determined to be immaterial due to the low stock price in comparison to the exercise price, hence there was no adjustment to make upon adoption of this accounting standard. During fiscal year 2010, the Company has recorded non-cash losses of $15,861,006 relating to the change in fair value of these derivative instruments.
Additional Fair Value Language
The accounting guidance establishes a fair value hierarchy based on whether the market participant assumptions used in determining fair value are obtained from independent sources (observable inputs) or reflect the Company's own assumptions of market participant valuation (unobservable inputs). A financial instrument's categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The accounting guidance establishes three levels of inputs that may be used to measure fair value:
·
Level 1—Quoted prices in active markets that are unadjusted and accessible at the measurement date for identical, unrestricted assets or liabilities;
·
Level 2—Quoted prices for identical assets and liabilities in markets that are inactive; quoted prices for similar assets and liabilities in active markets or financial instruments for which significant inputs are observable, either directly or indirectly; or
·
Level 3—Prices or valuations that require inputs that are both unobservable and significant to the fair value measurement.
The Company considers an active market to be one in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis, and views an inactive market as one in which there are few transactions for the asset or liability, the prices are not current, or price quotations vary substantially either over time or among market makers. Where appropriate the Company's or the counterparty's non-performance risk is considered in determining the fair values of liabilities and assets, respectively.
The fair value of our financial instruments at April 30, 2010 and 2009 follows:
|
| Fair Value Measurements at Reporting Date Using |
| |||||||
Description |
| Quoted |
| Significant |
| Significant |
| |||
Derivative securities – |
|
|
|
|
|
|
|
|
|
|
April 30, 2009 |
| $ | — |
| $ | — |
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative securities – |
|
|
|
|
|
|
|
|
|
|
April 30, 2010 |
| $ | — |
| $ | — |
| $ | 17,429,787 |
|
F-17
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
(8)
LONG-TERM DEBT, WARRANTS, LOAN FEES AND RESTRICTED CASH
The Company had the following debt obligations at April 30, 2010 and April 30, 2009
|
| April 30, |
| April 30, |
| ||
Notes Payable: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6% convertible secured promissory notes, secured by 35,235 lease acreage, bearing interest at 6.00%, due December 4, 2016 |
| $ | 1,705,000 |
| $ | — |
|
|
|
|
|
|
|
|
|
Secured promissory notes – related party, secured by Certain equipment, bearing interest at 12%, due November 1, 2013 and December 15, 2013 |
|
| 2,721,444 |
|
| — |
|
|
|
|
|
|
|
|
|
Note payable to Commercial Bank, secured by a certificate of deposit, Bearing interest at 3.75%, due December 22, 2008 |
|
| — |
|
| 1,850,000 |
|
Note payable to Commercial Bank, secured by vehicle, dated March 31, 2009, bearing interest at 7.50%, due in monthly payments of $1,376.22, with the final payment due March 31, 2013 |
|
| — |
|
| 55,786 |
|
|
|
|
|
|
|
|
|
Note payable to GMAC Financing, secured by vehicle, dated June 27, 2008, bearing zero interest, due in monthly payments of $861.58, with the final payment due June 27, 2012 |
|
| — |
|
| 53,419 |
|
|
|
|
|
|
|
|
|
Total Notes Payable |
|
| 4,426,444 |
|
| 1,959,205 |
|
|
|
|
|
|
|
|
|
Less current maturities on other notes payable |
|
| — |
|
| (1,870,732 | ) |
Less debt discount |
|
| (1,383,271 | ) |
| — |
|
|
|
|
|
|
|
|
|
Notes Payable - Long-term |
| $ | 3,043,173 |
| $ | 88,473 |
|
The five-year maturities of long-term debt is as follows:
Year ended April 30, |
|
|
|
2011 |
| $ | — |
2012 |
|
| — |
2013 |
|
| — |
2014 |
|
| 2,721,444 |
2015 |
|
| — |
In December 2009, the Company raised $2,855,000 as 6% convertible secured promissory notes. These convertible secured notes bear interest at 6% per annum and mature in December 2016. The convertible secured notes, including any accrued and unpaid interest are convertible into common stock at $.55 per share, at the option of the holder. During the year ended April 30, 2010, $1,150,000 was converted into 2,090,909 shares of common stock. The conversion price was below market at the time of this debt raise, as a result the fair value of beneficial conversion feature was computed to be $809,263. This beneficial conversion feature was recorded as a debt discount and is being amortized over the term of the debt. The amortization expense recorded for the year ended April 30, 2010 was $363,662.
On November 1, 2009 we borrowed $2,365,174 from Miller Energy Income 2009-A, LP ("MEI"), a limited partnership of which our wholly-owned subsidiary, Miller Energy GP, LLC, is the general partner. Under the four year Secured Promissory Note we issued MEI to evidence this loan, interest is payable at the rate of 12% per annum, with interest only payments due monthly. On December 15, 2009 we borrowed an additional $356,270 from MEI and issued it a second four year Secured Promissory Note which also pays interest at the rate of 12% per annum with
F-18
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
interest only payments due monthly. In connection with these loans, we granted MEI a first priority security interest in oil and gas drilling equipment owned by us. Pursuant to the terms of an Escrow Agreement, a third-party escrow agent has been retained to hold the certificates of title for the collateral to which title is evidenced by a certificate. The remaining equipment is subject to a financing statement that has been filed with the Tennessee Secretary of State. We used the proceeds from these loans for general corporate purposes including reducing outstanding debt and to partially fund the Alaska transaction.
(9)
ASSET RETIREMENT OBLIGATION
In 2001, the Financial Accounting Standards Board approved the issuance of SFAS No. 143, "Accounting for Asset Retirement Obligations” (now ASC 410-20). SFAS 143 (now ASC 410-20) addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires companies to record the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the estimated costs to capitalize a well and site remediation once a well is abandoned. Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset.
The changes in the Company's liability for the years ended April 30, 2010 and 2009 as follows:
Asset retirement obligation as of April 30, 2008 |
| $ | 45,216 |
|
Accretion expense for 2009 |
|
| 12,030 |
|
|
|
|
|
|
Asset retirement obligation as of April 30, 2009 |
|
| 57,246 |
|
Asset retirement obligation acquired through Alaska acquisition |
|
| 15,289,995 |
|
Accretion expense for 2010 |
|
| 314,761 |
|
|
|
|
|
|
Asset retirement obligation as of April 30, 2010 |
| $ | 15,662,002 |
|
Cash - restricted long-term at April 30, 2010 and 2009 consisted of several certificates of deposits pledged to various Tennessee and Alaska state agencies for reclamation bonds.
(10)
STOCKHOLDERS’ EQUITY
In July 2008 we issued 300,000 shares for past services to our directors valued and expensed at $99,000. These shares were valued at the July 2008 market price of such shares issued.
In May 2005 the Company entered into a $4.15 million credit agreement which had terms that specified that the Company would prepare, and file a Registration Statement that would cover the resale of all of the Registrable Securities, which Registration Statement, to the extent allowable under the 1933 Act and the rules and regulations promulgated hereunder (including Rule 416),shall state that such Registration Statement also covers such indeterminate number of additional shares of Common Stock as may become issuable upon conversion of or otherwise pursuant to the Notes and Warrants to prevent dilution resulting from stock splits, stock dividends or similar transactions. Company would agree to provide certain registration rights under the Securities Act of 1933, as amended, and the rules and regulations thereunder, or any similar successor statute, and applicable state securities laws. The Company is required to issue 40,000 penalty warrants each month. The Company has not registered the aforementioned underlying securities. The shares are not registered and the Company issued 360,000 and 480,000 penalty warrants at an average exercise price of $1.15 per share with a five-year term valued and expensed at $235,508 and $122,818 during the years ended April 30, 2010 and 2009, respectively. There are cumulatively 3,000,000 warrants outstanding attributed to this financing, while 1,000,000 of them technically expired in May 2010, there is ongoing litigation with regards to the continuing terms of the penalty provisions. These warrants have been reclassified as a derivative liability due to the reset provisions of the warrants.
F-19
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
In August 2008 we engaged a broker-dealer and member of FINRA to assist us in raising capital by means of a private placement of securities. As initial compensation for their services, we paid 250,000 shares of our common stock, valued at $115,000. These shares were valued at the August 2008 market price of such shares issued.
In September 2008 we recorded stock-based compensation expense of $17,800 related to stock options granted.
During the fiscal year 2009, we repurchased 2,900,000 shares of common stock at $4,350,000, which was previously recorded as equity subject to being repurchased as of April 30, 2008.
In October 2008 we issued 800,000 shares to employees and a consultant as compensation, which in the aggregate were valued at $176,000 expensed, respectively. Also, in October 2008 we issued 100,000 shares of our common stock to two individuals as compensation for a finder's fee related to the introduction of our company to a broker-dealer, and expensed at $22,000. These shares were valued at the October 2008 market price of such shares issued.
In February 2009, a warrant holder exercised 200,000 warrant options using a cashless exercise option which netted them 195,000 common shares.
During the year ended April 30, 2009, we issued 2,662,500 shares of common stock to our Chief Executive Officer, Mr. Boruff, and expensed $878,625. 2,500,000 shares of this stock was issued to Mr. Boruff as a transaction fee for the sale to Atlas America of approximately 30,000 acres of oil and gas leases and eight drilled but not completed wells for $19,625 million on June 13, 2008. 162,500 shares of stock are to be issued to Mr. Boruff as part of his employment agreement. During the year, Mr. Boruff was also issued 250,000 stock options with a grant price of $0.33 which vest over a four year period.
During the twelve months ended April 30, 2010, we issued 16,250,538 shares of common stock as well as warrants and options for various reasons.
Acquisitions -
We issued 2,000,000 shares of common stock for the acquisition of KTO and ETC, discussed earlier, which were valued at the then fair market value of the shares issued of $570,000.
There was 3,500,000 of warrants issued to the sellers of CIE at exercise prices varying from $.01 to $2.00 a share, which the fair value of these warrants was recorded at $2,071,655.
Equity and Debt Financings -
In June 2009, the Company sold in a private transaction to accredited investors 350,000 shares of common stock, which resulted in gross proceeds to the Company of $119,000.
In November 2009, the Company borrowed $350,000, maturing in sixty days. The Company also issued 350,000 shares of common stock as an inducement for such loan. The fair value of such shares issued of $245,000 was expensed as a cost of such debt raise.
In December 2009, the Company borrowed from a related party MEI, discussed earlier of $2,721,444, which the Company issued 1,329,250 shares of common stock and 1,329,250 warrants exercisable at $1.00,as an inducement to aid in raising such funds from investors. The fair value of these shares and warrants issued of $1,048,765 was recorded as a debt discount and is to be amortized over the term of this debt.
In December 2009, the Company raised $2,855,000 of convertible debt, discussed earlier. The Company recorded a beneficial conversion feature attributed to the conversion feature of $809,263, which has been recorded as a debt discount and will be amortized over the term of such debt.
F-20
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
In December 2009 and January 2010, we sold 6,015,000 shares of common stock for $1.00 a share, which $326,000 was incurred as costs to raise such equity, including the issuance of 332,500 warrants to consultants for this equity sale of common stock.
In March 2010, we sold for $5,017,002, 1,433,432 shares of common stock and 716,716 warrants exercisable at $2.50 a share. The warrants have an exercise price reset provision, which expire in September 2010. The fair value of this derivative amounted to $542,094 at inception, hence such value was allocated to a derivative liability. In addition these equities sold have registration rights penalties, which if the Company had not filed a registration statement to register such shares to be freely tradeable within 30 days then the Company is subject to a 2% percent a month penalty for a total penalty of 12% of this equity raise. As a result of the short time line to register such shares, the Company has accrued on day one the full registration penalty of $602,040 as a allocation of such proceeds, due to the anticipation of not being able to timely fulfill the terms of the registration requirements. The Company also incurred $361,190 of direct costs related to this equity raise and issued 100,339 of warrants to consultants for this sale of equity.
In March 2010, the Company sold 95,000 shares of common stock in a private transaction resulting in $326,800 of gross proceeds to the Company.
In April 2010, $1,150,000 of the 6% Convertible debt holders converted their debt for 2,090,909 shares of common stock.
Shares and Warrants Issued for Services and Compensation -
During the fiscal year 2010, we issued 100,000 shares of common stock and 3,900,000 warrants and qualified and non qualified stock options to our employees and directors, pursuant to employment arrangements or discretionary issues at the directive of the board of directors. The five year warrants and ten year stock options issued had exercise prices ranging from $.10 to $5.94 and vesting terms ranging from an immediate vesting to vesting over three years. These common shares, warrants and stock options issued had a fair value of $7,194,156, which $1,662,220 has been expensed. The balance of $5,531,936 will be expensed over the next three years as such equities vest.
During the fiscal year 2010, we issued 469,100 shares of common stock and 450,000 five year warrants with exercise prices ranging from $.01 to $2.50, which all vested immediately. These common shares and warrants had a fair value of $2,372,743, which has been expensed. There was one batch of 300,000 warrants issued which had an exercise price reset provision. The value of these warrants of $636,835 has been classified to be a derivative liability.
Exercise of Warrants –
During the fiscal year 2010, there were 2,397,500 amount of warrants converted for cash or cashless resulting in 2,017,847 of common shares being issued with net proceeds of $282,000.
(11)
STOCK OPTIONS
We record share-based payments at fair value and record compensation expense for all share-based awards granted, modified, repurchased or cancelled after the effective date, in accord to the FASB guidance. We record compensation expense for outstanding awards for which the requisite service had not been rendered as of the effective date over the remaining service period.
F-21
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
We estimated the fair value of options granted during the years ended April 30, 2010 and 2009 on the date of grant, using the Black-Scholes pricing model with the following assumptions:
|
| 2010 |
|
| 2009 |
|
Weighted average of expected risk-free interest rates (Approximate 3 year |
| 1.56 | % |
| 1.85 | % |
Expected years from vest date to exercise date |
| 2.9 |
|
| 2.4 |
|
Expected stock volatility |
| 50-216 | % |
| 293-527 | % |
Expected dividend yield |
| 0 | % |
| 0 | % |
The Company recorded $2,019,877 and $247,425 of compensation expense, net of related tax effects, relative to stock options for the years ended April 30, 2010 and 2009, respectively in accordance with the FASB guidance. Net loss per share basic and diluted for this expense is $0.09 and $0.07.
The Company has adopted ASC 718-25, “Stock Compensation Recognition” (. ASC 718-25 requires companies to expense the value of employee stock options and similar awards and applies to all outstanding and vested stock-based awards. In computing the impact, the fair value of each option is estimated on the date of grant based on the Black-Scholes options-pricing model utilizing certain assumptions for a risk free interest rate; volatility; and expected remaining lives of the awards. The assumptions used in calculating the fair value of share-based payment awards represent management's best estimates, but these estimates involve inherent uncertainties and the application of management judgment. As a result, if factors change and the Company uses different assumptions, the Company's stock-based compensation expense could be materially different in the future. In addition, the Company is required to estimate the expected forfeiture rate and only recognize expense for those shares expected to vest. In estimating the Company's forfeiture rate, the Company analyzed its historical forfeiture rate, the remaining lives of unvested options, and the amount of vested options as a percentage of total options outstanding. If the Company's actual forfeiture rate is materially different from its estimate, or if the Company reevaluates the forfeiture rate in the future, the stock-based compensation expense could be significantly different from what we have recorded in the current period. The impact of applying ASC 718-25 approximated $2,019,877 in additional compensation expense during the year ended April 30, 2010 and none in 2009. Such amount is included in general and administrative expenses on the statement of operations.
The aggregate intrinsic value is calculated as the difference between the exercise price of the underlying awards and the quoted price of our common stock for those awards that have an exercise price currently below the closing price. During the year ended April 30, 2010 and 2009, the aggregate intrinsic value of stock options and warrants exercised was $3,752,093 and $46,800, respectively, determined as of the date of exercise.
A summary of the stock options and warrants as of April 30, 2010 and 2009 and changes during the periods is presented below:
|
| 2010 |
| 2009 |
| ||||||||
|
| Number of |
| Weighted |
| Number of |
| Weighted |
| ||||
Balance at beginning of year |
|
| 4,090,000 |
| $ | 0.88 |
|
| 7,535,000 |
| $ | 0.40 |
|
Granted |
|
| 10,688,805 |
|
| 2.62 |
|
| 1,855,000 |
|
| 0.91 |
|
Exercised |
|
| 2,397,500 |
|
| 0.03 |
|
| 200,000 |
|
| 0.01 |
|
Expired |
|
| 75,000 |
|
| 5.67 |
|
|
|
|
|
|
|
Cancelled |
|
| 0 |
|
| 0.96 |
|
| 5,100,000 |
|
| 0.23 |
|
Balance at end of year |
|
| 12,306,305 |
|
| 1.50 |
|
| 4,090,000 |
|
| 0.88 |
|
Options exercisable at April 30 |
|
| 6,843,805 |
|
|
|
|
| 3,840,000 |
| $ | 0.91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-22
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
The following table summarizes information concerning stock options and warrants outstanding and exercisable at April 30, 2010:
Options and Warrants Outstanding |
| Options and Warrants | ||||||||
Range of |
| Number |
| Weighted |
| Weighted |
| Number |
| Weighted |
$0.01 to 0.69 |
| 2,080,000 |
| 3.1 |
| $0.31 |
| 1,892,500 |
| $0.31 |
1.00 to 1.82 |
| 5,034,250 |
| 3.5 |
| 1.09 |
| 3,534,250 |
| 1.13 |
2.00 to 2.52 |
| 1,750,000 |
| 4.1 |
| 2.13 |
| 600,000 |
| 2.25 |
5.28 to 6.53 |
| 3,442,055 |
| 8.8 |
| 5.84 |
| 817,055 |
| 5.28 |
|
| 12,306,305 |
| 5.0 |
| 2.44 |
| 6,843,805 |
| $1.50 |
All options and warrants were issued at the fair market of common stock on the date of grant.
(12)
INCOME TAX
At April 30, 2010, we had federal net operating loss carryforwards amounting to approximately $10,158,833, which expire through 2023. We have recorded a full valuation allowance against deferred tax assets (approximately $3,955,993 using a tax rate of 35%) resulting from the net operating loss carryforwards, because we do not consider the realization of such deferred tax assets to be more likely than not.
A reconciliation of our net operating loss carryforwards (NOL) is as follows:
|
| Federal |
|
| State |
|
NOL at April 30, 2008 |
| (9,976,523 | ) |
| (9,578,378 | ) |
Adjusted Pre-tax income at April 30, 2009 |
| 9,591,444 |
|
| 9,591,444 |
|
|
|
|
|
|
|
|
Taxable income (loss) |
| (385,079 | ) |
| 13,066 |
|
Tax depreciation in excess of book depreciation |
| (1,303,742 | ) |
| (901,358 | ) |
|
|
|
|
|
|
|
NOL at April 30, 2009 |
| (1,688,821 | ) |
| (888,292 | ) |
Adjusted net Loss |
| (9,201,370 | ) |
| (9,201,370 | ) |
Taxable Loss |
| (10,890,191 | ) |
| (10,089,662 | ) |
|
|
|
|
|
|
|
Tax depreciation in excess of book value |
| (170,330 | ) |
| (288,965 | ) |
Book amortization in excess of tax depletion |
| 901,688 |
|
| 901,688 |
|
NOL at April 30, 2010 |
| (10,158,833 | ) |
| (9,476,939 | ) |
|
|
|
|
|
|
|
Federal income tax at 35% and 6.5% state tax benefit net of federal benefit |
| (3,555,592 | ) |
| (400,401 | ) |
F-23
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
The difference between the recorded income tax benefit and the computed tax benefit using a 35% federal tax rate is:
|
| April 30, 2010 |
| April 30, 2009 |
| ||||||||
|
| Federal |
| State |
| Federal |
| State |
| ||||
Pre-tax book income (loss) |
| $ | 432,884,702 |
| $ | 432,884,702 |
| $ | 8,357,151 |
| $ | 8,357,151 |
|
Non-timing Schedule M items Stock for services |
|
| 482,250 |
|
| 482,250 |
|
| 1,153,624 |
|
| 1,153,624 |
|
Other non-timing items |
|
| 11,152,607 |
|
| 11,152,607 |
|
| 80,668 |
|
| 80,668 |
|
|
|
| 444,519,559 |
|
| 444,519,559 |
|
| 1,234,292 |
|
| 1,234,293 |
|
Pre-tax net income(loss) after Non-timing Schedule M's |
|
|
|
|
|
|
|
| 9,591,444 |
|
| 9,591,444 |
|
Federal tax (benefit)at 35% and State tax (benefit) at 9.4% and 6.5% |
|
| 155,581,846 |
|
| 27,160,145 |
|
| 3,261,091 |
|
| 623,444 |
|
Income tax benefit from NOL carryforward |
|
| — |
|
| — |
|
| (3,261,091 | ) |
| (622,666 | ) |
Valuation reserve |
|
| — |
|
| — |
|
| — |
|
| — |
|
Deferred tax |
|
| 155,581,846 |
|
| 27,160,145 |
|
| — |
|
| 778 |
|
Income tax benefits from net operating loss carryforwards are as follows:
|
| April 30, |
| |||||
|
| 2010 |
|
| 2009 |
| ||
Expected income tax (benefit) |
|
| (3,555,592 | ) |
| $ | (574,197 | ) |
State taxes, net of federal benefit |
|
| (400,401 | ) |
|
| (38,108 | ) |
Valuation allowance |
|
| 3,955,993 |
|
|
| 612,305 |
|
Deferred tax asset |
| $ | — |
|
| $ | — |
|
The Company operates several oil and gas wells in Alaska and has leased properties for other oil and gas exploration purposes. Alaska has investment tax incentives whereby through June 30, 2010, up to 20% of certain qualified expenditures are reimbursable via a tax credit which can be sold to other oil and gas companies at a discount to obtain an immediate realization of such benefits or such tax credits could be utilized by the Company to offset taxes due or obtain a refund based on certain future reinvestment criteria. Effective July 1, 2010, the state of Alaska has increased the tax incentive rate from 20% to 40% and relaxed the criteria for a refund requirement to be obtained from the state of Alaska. The Company has recorded $1,107,000 as an other asset for an estimate of an investment tax credit incentive refund due from the state of Alaska, as of April 30, 2010.
(13)
COMMITMENTS
On August 6, 2008 the Board of Directors employed Scott M. Boruff as CEO of the Company. The employment contract, as amended, provided for the following compensation:
·
Base salary of $250,000 per annum, with provision for cost-of-living increases.
·
Options to purchase 250,000 shares of the Company's common stock at an exercise price per share of $0.33, with vesting in equal annual installments over a period of four years.
·
A restricted stock grant of 250,000 shares of common stock, with vesting in equal annual installments over a period of four years.
·
Incentive Compensation - For each year of the employment term, (i) cash up to 100% of base salary and (ii) up to 100,000 shares of restricted common stock, in both instances based upon, and subject to, two performance benchmarks, gross revenue and EBITDA. One half of each element of incentive compensation is earned if the gross revenue benchmark is achieved, and the other half of each element is earned if the EBITDA benchmark is achieved.
F-24
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
Based on this employment agreement, bonuses, net of certain expenses, were accrued for $186,452 on April 30, 2010. Also as part of this agreement, we will issue 100,000 shares of restricted common stock and expense $53,625 as compensation expense in 2010.
In August 2008 we engaged a broker-dealer and member of FINRA to assist us in raising capital by means of a private placement of securities. As initial compensation for their services, we paid a $25,000 retainer, and issued 250,000 shares of our common stock, valued at $115,000 and agreed to pay a monthly consulting fee of $5,000. Upon the successful completion of the private offering we will be obligated to pay the firm certain cash compensation and issue them up to an additional 150,000 shares of our common stock in amounts to be determined based upon the gross proceeds received by us from the financing. The Company leases office space on a month-to-month basis. The rental expense incurred for fiscal 2010 and 2009 was $79,737 and $8,027, respectively.
The Company has leases and licenses to explore acreage in Alaska that are renewable, at The Company’s discretion, annually. A summary of anticipated annual payments is as follows:
2011 |
| $ | 279,455 |
2012 |
|
| 279,455 |
2013 |
|
| 279,455 |
2014 |
|
| 279,455 |
2015 |
|
| 279,455 |
|
|
|
|
On April 10, 2010 the Company entered into an agreement with a limited liability company to act as exclusive placement agent (“Agent”) for the Company, on a reasonable best efforts basis, in connection with a proposed offer and placement by the Company of securities of the Company (the “Offering”). If successful, the Company shall pay the Agent a cash placement fee equal to 6% of the aggregate purchase price paid by each purchaser of equity or equity-linked Securities, to the Company during the Term hereof that are placed in the Offering, and 2% of the aggregate purchase price paid by each purchaser of debt Securities, to the Company during the Term hereof that are placed in the Offering. As additional compensation for the Services, the Company shall issue warrants to the Agent to purchase that number of shares of common stock of the Company (“Shares”) equal to 6% of the aggregate number of Shares placed in the Offering to each purchaser, to the Company during the Term hereof, plus any Shares underlying any convertible Securities placed in the Offering to such purchasers.
On November 5, 2009, Cook Inlet Energy, LLC entered into an Assignment Oversight Agreement with the Alaska DNR which set our certain terms under which the Alaska DNR would approve the assignment of certain specified state oil and gas leases from Pacific Energy Resources to Cook Inlet Energy. This agreement remains in place following our acquisition of Cook Inlet Energy in December 2009. Generally, the agreement requires Cook Inlet Energy to provide the Alaska DNR with additional information and oversight authority to ensure that Cook Inlet Energy is acting diligently to develop the oil and gas from Redoubt Shoal, West McArthur River Field and West Foreland Field. Under the terms of the agreement, until the Alaska DNR determines, in its sole discretion, that Cook Inlet Energy has completed its development and operation obligations under the assigned leases, Cook Inlet Energy agreed to the following:
·
file a monthly summary of expenditures by oil and gas filed, tied to objectives in Cook Inlet Energy’s business plan and plan of development previously presented to the Alaska DNR,
·
meet monthly with the Alaska DNR to provide an update on operations and progress towards meeting these objectives,
·
notify the Alaska DNR 10 days prior to commitment when Cook Inlet Energy is preparing to spend funds on a purchase, project or item of more than $100,000 during the first 12 months, more than $1 million during the second 12 months and more than $5 million thereafter, and
·
submit a new plan of development and plan of operations for the Alaska DNR’s approval on or before December 15, 2009 and submit a plan of development annually thereafter on or before February 1, 2010. Cook Inlet Energy timely met both of these deadlines.
F-25
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
The agreement required Cook Inlet Energy to obtain financing in the minimum amount of $5,150,000 to provide funds to be used for expenditures approved by the Alaska DNR as part of Cook Inlet Energy’s plan of development. The funds are to be used for workover and repair of the wells, repair of the physical infrastructure, construction of a grind and inject plant at the West McArthur River facility, normal operating expenses associated with the leases and infrastructure and other capital project which are to be pre-approved by the Alaska DNR. The agreement also required Cook Inlet Energy to demonstrate funding commitments to support restoration of the base production at the Redoubt Unit, including bringing a number of the shut-in wells back on line, which was estimated at $31 million in the agreement but which we have internally increased to $35 million to accommodate the purchase of a drilling right. These funding commitments necessary under the agreement were provided to us under the terms of the Vulcan Capital Corporation, LLC letter agreement described earlier in this annual report. We have subsequently provided these funds through for the West McArthur River facility using a portion of the proceeds of our capital raising efforts described elsewhere herein, and intend to seek alternative sources of funding for the balance of the necessary capital.
Cook Inlet Energy is prohibited from using any of the approximate $36.15 million or any proceeds from the operations under the assigned leases of the funding commitments for non-core oil and gas activities under the assigned leases, or any activities outside the assigned leases, without the prior written approval of the Alaska DNR until the parties mutually agree that the full dismantlement obligation under the assigned leases is funded. The assigned leases will be subject to default and termination should Cook Inlet Energy fail to submit the information required under the agreement and expenditure of funds for items or activities do not support core oil and gas activities, as reasonably determined by the Alaska DNR.
(14)
ASC 932-S50 EXTRACTIVE ACTIVITIES – OIL AND GAS DISCLOSURES (FORMERLY SFAS NO. 69) (UNAUDITED)
a. Capitalized Costs Relating to Oil and Gas Producing Activities at April 30, 2010 and 2009 are as follows:
|
| 2010 |
| 2009 |
| ||
Natural gas and oil properties: |
|
|
|
|
|
|
|
Proved properties |
| $ | 225,128,384 |
| $ | 2,227,191 |
|
Unproved properties |
|
| 154,244,658 |
|
| — |
|
|
|
| 379,373,042 |
|
| 2,227,191 |
|
Accumulated depletion |
|
| (3,156,421 | ) |
| (1,415,271 | ) |
Net capitalized costs |
| $ | 376,216,621 |
| $ | 811,920 |
|
b. Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities:
|
| 2010 |
| 2009 |
| ||
Property Acquisition Costs |
|
|
|
|
|
|
|
Proved properties |
| $ | 216,559,484 |
| $ | — |
|
Unproved properties |
|
| 154,244,658 |
|
| — |
|
Acquisition Costs |
|
| 370,804,142 |
|
| — |
|
Exploration costs |
|
| — |
|
| — |
|
Development costs |
|
| 5,822,391 |
|
| — |
|
Total |
| $ | 376,626,533 |
| $ | — |
|
c. Results of Operations for Producing Activities:
|
| 2010 |
| 2009 |
| ||
Production revenues |
| $ | 4,437,215 |
| $ | 640,094 |
|
Production costs |
|
| (96,240 | ) |
| (240,389 | ) |
Depreciation and amortization |
|
| (1,741,150 | ) |
| (221,465 | ) |
Results of operations for producing activities (excluding |
| $ | 2,599,825 |
| $ | 178,240 |
|
F-26
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
d. Reserve Quantity Information
The following schedule estimates proved oil and natural gas reserves attributable to the Company. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in barrels of oil (Bbls) and thousands of cubic feet of natural gas (Mcf). Geological and engineering estimates of proved oil and natural gas reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates reported represent the most accurate assessments possible, these estimates are by their nature generally less precise than other estimates presented in connection with financial statement disclosures.
|
| Oil (Bbls) |
| Gas (Mcf) |
|
Proved reserves |
|
|
|
|
|
Balance, April 30, 2008 |
| 74,413 |
| 1,851,858 |
|
Discoveries and extensions |
| — |
| — |
|
Revisions of previous estimates |
| (16,390 | ) | 58,892 |
|
Production |
| (4,580 | ) | (47,213 | ) |
Balance, April 30, 2009 |
| 53,443 |
| 1,863,537 |
|
Discoveries and extensions |
| — |
| — |
|
Revisions of previous estimates |
| 89,516 |
| (912,402 | ) |
Acquisitions |
| 10,288,075 |
| 4,831,879 |
|
Production |
| (86,611 | ) | (324,298 | ) |
Balance, April 30, 2010 |
| 10,344,423 |
| 5,458,716 |
|
Proved developed producing reserves at April 30, 2010 |
| 1,803,272 |
| 1,704,552 |
|
Proved developed producing reserves at April 30, 2009 |
| 42,657 |
| 562,600 |
|
Acquisitions, as noted above, were comprised of several entities. On June 8, 2009, we closed on the acquisition of certain assets of privately owned Ky-Tenn Oil, Inc., ("KTO") which includes approximately 35,325 leased acres located on the Chattanooga Shale and 153 natural gas and oil producing wells. On June 18, 2009 the Company acquired 100% of the stock of East Tennessee Consultants, Inc., a Tennessee corporation ("ETC") and 100% of the membership interests in East Tennessee Consultants II, LLC, a Tennessee limited liability company ("LLC") from the owners of these entities. The acquisition included 221 producing oil and gas wells and consisted of approximately 4,442 acres. On December 10, 2009, the Company acquired 100% of the membership interests in Cook Inlet Energy, LLC, an Alaska limited liability company from the owners of this entity and simultaneously acquired former Alaskan assets of Pacific Energy Resources ("Pacific Energy") valued at more than $479 million through a Delaware Chapter 11 Bankruptcy proceeding. The Company acquired the Alaskan oil and gas assets, which include onshore and offshore production facilities, $215 million in proven energy reserves, $122 million in probable energy reserves and $31 million in possible energy reserves, providing total reserves of $368 million. The purchased assets include the West McArthur River oil field, the West Foreland natural gas field, and the Redoubt unit with the Osprey offshore platform, all located along the west side of the Cook Inlet. Also included in the asset purchase are 602,000 acres of oil and gas leases, which includes 471,474 acres under the Susitna Basin Exploration License. See note 6 for complete details of these acquisitions.
In addition to the proved developed producing oil and gas reserves reported in the geological and engineering reports, the Company holds ownership interests in various proved undeveloped properties. The reserve and engineering reports performed for the Company were by Lee Keeling and Associates, Inc. for the years ended April 30, 2010 and April 30, 2009 for all of the Tennessee reserves and by Ralph E. Davis Associates, Inc. for the year ended April 30, 2010 for all of the Alaska reserves.
F-27
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
With the closing of these acquisitions, our management is now able to focus the majority of its efforts on growing our company. In addition to raising capital we are also continuing to focus our short-term efforts on three distinct areas, including:
·
Increase our overall oil and gas production through maintenance and repairs of nonperforming or underperforming wells,
·
Organically growing production through drilling for our own benefit on existing leases and under license rights, leveraging our 100,000 plus well log database and over 660,000 acres which are either under lease or part of the Susitna Basin Exploration License, with a view towards retaining the majority of working interest in the new wells, and
·
Expanding our contract drilling and service capabilities and revenues, including drilling and service contracts with third parties.
Our ability, however, to implement one or more of these goals is dependent upon the availability of additional capital. To fully expand our operations as set forth above, we will need up to $75 million to $100 million to fund the balance of our expansion plans, including up to approximately $67.4 million associated with obligations arising from our purchase of the Alaskan assets To provide the required capital, we are seeking to leverage our existing assets as well as raise additional capital through the sale of equity and/or debt securities. We do not have any firm commitments for the additional capital we are need to fully fund our operations and there are no assurances the capital will be available to us upon terms acceptable to us, if at all.
The following schedule presents the standardized measure of estimated discounted future net cash flows from the Company's proved developed reserves for the years ended April 30, 2010 and 2009. Estimated future cash flows were based on independent reserves evaluation from Lee Keeling and Associates, Inc. for the years ended April 30, 2010 and April 30, 2009 for all Tennessee reserves and by Ralph E. Davis Associates, Inc. for the year ended April 30, 2010 for all of the Alaska reserves. Because the standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at April 30, 2010 and 2009, it should be emphasized that such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of the Company's recoverable reserves or in estimating future results of operations.
Each of the engineering reports also projected future cash flows from our net reserves and the present value, discounted at 10% per annum. Future cash flows are based upon gross income from future production, less direct operating expenses and taxes. Estimated future capital for development costs was also deducted from gross income at the time it will be expended. No allowance was made for depletion, depreciation, income taxes or administrative expense. In the following table, the price per barrel of oil was $73.01 and the price per MMcf of natural gas was $4.84 for the Cook Inlet reserves and $71.85 per barrel of oil and $5.15 per MMcf of natural gas for the Appalachian region reserves. In each instance these prices are computed in accordance with the SEC’s rule and represent the average fiscal year prices.
Operating costs and production taxes are estimated based on current costs with respect to producing gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.
Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved.
The future net revenue information assumes no escalation of costs or prices, except for gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.
F-28
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
Standardized measures of discounted future net cash flows at April 30, 2010 and 2009 are as follows:
|
| 2010 |
| 2009 |
| ||
Future cash flows |
| $ | 662,317,776 |
| $ | 7,981,612 |
|
Future production costs and taxes |
|
| (123,537,182 | ) |
| (1,812,885 | ) |
Future development costs |
|
| (50,232,400 | ) |
| (1,185,201 | ) |
Future income tax expense |
|
| (132,463,555 | ) |
| (1,544,893 | ) |
Future cash flows |
|
| 356,084,639 |
|
| 3,438,633 |
|
Discount at 10% for timing of cash flows |
|
| (126,410,047 | ) |
| (1,903,824 | ) |
Discounted future net cash flows from proved reserves |
| $ | 229,674,592 |
| $ | 1,534,809 |
|
|
|
|
|
|
|
|
|
Of the Company's total proved reserves as of April 30, 2010 and 2009, approximately 18% and 38%, respectively, were classified as proved developed producing, 8% and 4%, respectively, were classified as proved developed non-producing and 74% and 58%, respectively, were classified as proved undeveloped. All of the Company's reserves are located in the continental United States.
The following table sets forth the changes in the standardized measure of discounted future net cash flows from proved reserves for April 30, 2010 and 2009.
|
| April 30, |
| ||||
|
| 2010 |
| 2009 |
| ||
Balance, beginning of year |
| $ | 1,534,809 |
| $ | 6,744,139 |
|
Sales, Net of production costs and taxes |
|
| (4,340,975 | ) |
| (399,705 | ) |
Changes in prices and production costs |
|
| (16,027,414 | ) |
| (2,775,928 | ) |
Purchase of reserves in place |
|
| 366,479,122 |
|
| — |
|
Revisions of quantity estimates and return of proved |
|
| 66,269,898 |
|
| (1,338,495 | ) |
Sale of minerals in place |
|
| — |
|
| — |
|
Development costs incurred |
|
| (50,232,400 | ) |
| — |
|
Net changes in income taxes |
|
| (134,008,448 | ) |
| (695,202 | ) |
Balances, end of year |
| $ | 229,674,592 |
| $ | 1,534,809 |
|
(15)
LITIGATION
CNX Gas Company, LLC commenced litigation on June 11, 2008 in the Chancery Court of Campbell County, State of Tennessee in a case style CNX Gas Company, LLC vs. Miller Petroleum Inc., Civil Action No. 08-071, to enjoin us from assigning or conveying certain leases described in the Letter of Intent signed by CNX and our company on May 30, 2008, to compel us to specifically perform the assignments as described in the Letter of Intent; and for damages. A Notice of Lien Lis Pendens was issued June 11, 2008. We moved for entry of summary judgment dismissing the claims asserted against us by CNX and on January 30, 2009 the court found that CNX’s claims had no merit. The court granted our motion and dismissed all claims asserted by CNX in that action. CNX has appealed the ruling, and briefs have been submitted to the Court of Appeals of Tennessee. Oral arguments were held on May 18, 2010, and an opinion from the Court of Appeals is expected sometime in the fall of 2010.
On May 20, 2009 Gunsight Holdings, LLC, a Florida limited liability company, filed a complaint in the United States District Court for the Eastern District of Tennessee, Northern Division, against us styled Gunsight Holdings, LLC, Plaintiff, v Miller Petroleum, Inc. and Ky-Tenn Oil, Inc., Defendants, Case No. 3-09-CV-221. The litigation surrounds certain rights related to approximately 6,800 acres in Scott County, Tennessee which KTO purportedly acquired under a lease assignment from an unrelated party in August 2004. In September 2008, KTO assigned us 75% of its interest in the subject lease and the working interest in all the wells on the leased land, retaining a 25% interest in the wells consisting of landowner's royalty and overriding royalty. On June 8, 2009 we acquired certain assets from KTO including KTO's undivided interest in approximately 170 oil and gas wells in Morgan, Scott and Fentress counties in Tennessee, together with all property, fixtures and improvements, leasehold
F-29
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
APRIL 30, 2010 AND 2009
interest and contract rights related to these wells and undivided interest in approximately 35,325 acres of oil and gas leases in Scott and Morgan counties, Tennessee. The lease which is the subject of the litigation was included in the assets purchased by us from KTO. The plaintiff is alleging that our company and KTO have failed or refused to pay royalties due to the plaintiff’s predecessors and have breached the implied duty of further exploration by failing to drill required wells, failing to reasonably develop or explore the property, failing to maintain an active interest in further development of the property and otherwise failing to act as a prudent operator of the property thereby causing damages to the plaintiff exceeding $75,000. The plaintiff is seeking a declaratory judgment of its allegations, removal of our company and KTO from the property, a full accounting of activities related to the property and all monies received from those activities, damages and costs of action. We have filed an answer denying the various claims and asserting affirmative defenses including that there has been continuous production from the subject lease. We are currently in discovery.
On October 8, 2009 we filed an action styled Miller Petroleum, Inc. v. Maynard, Civil Action No. 9992 in the Chancery Court for Scott County, Tennessee, seeking a declaratory judgment that there has been continuing commercial production of oil, and oil and gas lease owned by us is still in full force and effect. The defendant filed an Answer and Counterclaim, seeking in the Counterclaim a declaration that the oil and gas lease has expired. Although no compensatory monetary damages have been sought against us, the Counterclaim does seek attorney fees, expenses and costs. There has been no discovery to date and a trial date has not been assigned. Plaintiff’s attorney left his firm, and the case has been delayed as Plaintiff’s new counsel (with the same firm) becomes familiar with the case.
On March 26, 2010, Petro Capital III, LP filed an action styled Petro Capital III, LP v. Miller Petroleum, Inc., Civil Action No. 3:10-cv-00606P in the United States District Court for the Northern District of Texas, Dallas Division, seeking damages for breach of contract; damages for alleged negligent misrepresentation; a declaratory judgment regarding the proper number of and exercise price of the original warrants to which Petro Capital is entitled under a warrant and registration rights agreement, the number of penalty warrants to which Petro Capital may be entitled under a warrant and registration rights agreement, as well as the proper exercise price thereof, and damages resulting from the alleged breach of contract; and attorney’s fees. On April 6, 2010, Petro Capital filed an Amended Complaint that did not include additional causes of action. We filed an Answer and Counterclaim on April 28, 2010. The Counterclaim seeks a declaratory judgment to declare void the issuance of any penalty warrants after May 4, 2007 (the latest date upon which the shares underlying the warrants would become freely tradable under Rule 144). The Counterclaim further seeks a declaratory judgment as to the number of shares and proper exercise price for the original warrant.
We are also party to various routine legal proceedings arising in the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.
(16)
SUBSEQUENT EVENTS
On June 29, 2010, a wholly owned subsidiary, Cook Inlet Energy, LLC was the successful high bidder on all seven tracts that it pursued at the State of Alaska’s Cook Inlet Area-Wide 2010 Oil & Gas Lease Sale. Cook Inlet Energy bid on seven tracts and was the successful high bidder on each of those tracts which cover an estimated 27,520 acres. Cook Inlet Energy’s winning bid for these seven tracts was $908,800. Cook Inlet Energy paid a deposit of $181,767 at the time of the auction and the balance will be due once the title work is complete which we presently anticipate to be in January 2012. All of Cook Inlet Energy’s bids completed acreage positions covering prospects acquired in its purchase of a portfolio of Pacific Energy Alaska assets late last year.
F-30