Item 1. Business
Company Website
The Company has a website located at http://www.coastalcarib.com. The website can be used to access recent news releases, Securities and Exchange Commission (“SEC”) filings, and other items of interest. The contents of the Company’s website are not incorporated into this document. Securities and Exchange Commission filings, including supplemental schedules and exhibits can also be accessed free of charge through the SEC website at http://www.sec.gov.
General
Coastal Caribbean Oils & Minerals, Ltd. (“Company” or “Coastal Caribbean”), was organized in Bermuda on February 14, 1962. The Company is the successor to Coastal Caribbean Oils, Inc., a Panamanian corporation organized on January 31, 1953 to be the holding company for Coastal Petroleum Company (“Coastal Petroleum”). Coastal Caribbean, has been engaged, through its subsidiary, Coastal Petroleum, in the exploration for oil and gas reserves. At December 31, 2008, Coastal Caribbean's principal asset was its 100% interest in its subsidiary Coastal Petroleum. Coastal Petroleum's principal assets are its nonproducing oil and gas leases in the States of Montana and North Dakota in a fertile oil producing region know as the Williston Basin. Coastal Petroleum is the lessee under leases relating to the exploration for and production of oil and gas on approximately 114,832 net acres (87,415 net acres after some leases expired in March 2009) of land in Valley County, Montana and approximately 8,510 net acres of land in Billings, Slope and Stark Counties, North Dakota.
Prior to acquiring leases in Montana and North Dakota, and beginning in the 1940’s the Company held State of Florida oil, gas and mineral leases covering approximately 3,700,000 acres of submerged lands along the Gulf Coast and under certain inland lakes and rivers. For more than 15 years, the State of Florida used laws, policies and permit denials to prevent Coastal Petroleum from using its leases. The Company vigorously litigated to be able to use its leases or to be compensated for the State’s taking of them, but Florida courts ultimately ruled against the Company. On June 1, 2005 the Company, Coastal Petroleum and other royalty holders, based upon the court decisions and State policies, entered an agreement to exchange mutual releases, dismiss pending actions and to surrender the leases and royalty rights back to the State of Florida in exchange for a total compensation of $12.5 million to be divided among the parties in interest. The Company and its subsidiary received approximately $4,872,000 in net proceeds and the Company regained 100% ownership of its subsidiary, Coastal Petroleum.
The Company has utilized the funds it received from the Agreement with the State of Florida to acquire the leases in Montana and North Dakota described above and to begin drilling there. No economical oil or gas discoveries have yet been made on these properties; therefore, the Company has no proved reserves of oil and gas and has had no production.
Crude Oil and Natural Gas Exploration
Through its wholly owned subsidiary, Coastal Petroleum, the Company has begun to explore for oil and gas in Montana.
Under an agreement with Western Standard Energy Corp. (“Western Standard”) a well, the Federal 1-19, was drilled on our Valley County, Montana Leases to test a shallow gas prospect during October 2007. The well reached a total depth of 1,126 feet and confirmed the structural high that was targeted. The well also had gas shows in two zones. Casing was run into the hole and operations to complete and test the well were scheduled to begin at the end of November, but were delayed by equipment repairs. The well is located on Federal land and the Bureau of Land Management would not allow the completion and testing operations or any further drilling to begin until July 2008, so operations were suspended until that time. During the second and third quarters of 2008, the Company engaged in three stages of completion operations, including stimulation of the well, a common procedure in completing oil and gas wells.
The Company was unable to determine by this well whether the target formations contain economic quantities of gas. Drilling damage in the well prevented the testing of either of the prospective formations at this location. Completion efforts found that the Eagle formation was damaged by the initial drilling and the formation was not able to be tested from this well. Further drilling into the Eagle formation during completion did not yield gas like the gas show seen from the upper part of the formation that was damaged. The Judith River formation, a secondary target, was damaged by drilling fluids lost into the formation while drilling through it to get to the Eagle formation, the primary target. Future wells to test this structure will incorporate the information obtained from these wells to prevent that damage from occurring again in other locations on the structure.
Western Standard had 30 days after the completion of the Federal 1-19 to exercise an option to purchase a 50% interest in approximately 42,000 acres near the well location (referred to as “Valley County Shallow Gas Assembly”) for $1,000,000, but the deadline passed without being exercised. Western Standard no longer has an interest in these leases and Coastal Petroleum is now in control of them again.
On November 3, 2007, F-Cross Resources, LLC (“F- Cross”) spudded the first well under an Agreement with the Company. The well was drilled to test a Lodgepole reef oil prospect and drilling on the well has finished and is awaiting completion. As of this time it is uncertain whether F-Cross will proceed with completion. F-Cross did not meet the requirements in the agreement and in late March 2008 the option to acquire an interest in the additional 64,000 acres covered by the agreement expired, leaving F-Cross with rights only in the section in which it drilled the well.
In January 2006, the Company drilled a well in north-central Montana. The Company completed and tested multiple zones in the well that potentially could contain oil or gas. While the targeted Lodgepole reef was reached and while gas was encountered in uphole zones, the well did not contain economic quantities of oil or gas. This well was abandoned during 2007.
The Company also drilled a well, along with several other participants, in Valley County, Montana. The well was a twin to the Evaline 1-18 well, the only Lodgepole producer in Montana. The drilling began on September 5, 2006, and the well reached the targeted Lodgepole reef and encountered oil, but there were not sufficient quantities of oil to be economical for the Company to develop. The well was abandoned during 2007.
The Company is actively engaged in pursuing funding for our 2009 Drilling Program. The Program is an aggressive $9,500,000 exploration operation which would allow the Company to explore the potential of each of the areas held under its leases. The Program covers exploration in four areas: a development Red River Formation prospect in Slope County, North Dakota, on approximately 400 acres we acquired; the drilling of three Lodgepole Formation prospects on the Company’s North Dakota Leases; ten step out wells from the Federal 1-19 well on the Starbuck East prospect in Montana; and the drilling of two other shallow gas prospects in Montana, but located off from the Starbuck East prospect. The 2009 Drilling Program is currently being reviewed by prospective funding parties. The Company is proceeding with the relativily inexpensive process of permitting wells in its main block of leases in Valley County, Montana, in order to accommodate the drilling of the expected wells. We have no assurances at this time that any funding will be available for the Drilling Program.
Environmental Regulation
Coastal Caribbean is committed to responsible management of the environment, health and safety, as these areas relate to the Company’s operations. The Company strives to achieve the long-term goal of sustainable development within the framework of sound environmental, health and safety practices and standards.
All facets of the Company's operations are affected by a myriad of federal, state, regional and local laws, rules and regulations. The Company is further affected by changes in such laws and by constantly changing administrative regulations. Furthermore, government agencies may impose substantial penalties if the Company fails to comply with such regulations or for any contamination resulting from the Company's operations.
The costs incurred to ensure compliance with environmental, health and safety laws and other regulations are inextricably connected to normal operating expenses such that the Company is unable to separate the expenses related to these matters.
When acting as the operator and conducting drilling operations, Coastal Caribbean maintains insurance coverage that it believes is customary in the industry although it is not fully insured against all environmental or other risks. The Company is not currently conducting drilling operations and therefore does not currently have such insurance. The Company is not aware of any environmental claims existing as of December 31, 2008 that would have a material impact upon the Company's financial position, results of operations, or liquidity.
Regulation of Oil and Gas
The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases the Company's cost of doing business and, consequently, may affect profitability, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
The Company's operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities in which the Company operates may also regulate one or more of the following: the location of wells; the method of drilling and casing wells; the rates of production or "allowables;" the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and notice to surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company's interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas the Company can produce from its wells or limit the number of wells or the locations at which it can drill.
Moreover, each state generally imposes a property, production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
Competition
The oil and gas industry is highly competitive. The Company must compete with other companies that have substantially greater resources available to them. As an independent, the Company does not own any refining or retail outlets and, therefore, it would have little control over the price it may receive for any crude oil it produces. In acquisition activities, significant competition exists as integrated and independent companies and individual producers are active bidders for desirable oil and gas properties. Although many of these competitors have greater financial and other resources than the Company, Management believes that Coastal Caribbean is in a position to compete effectively due to its low cost structure, transaction flexibility, experience and determination.
Employees
The Company currently has one employee. The Company relies heavily on consultants for legal, accounting, geological and administrative services. The Company uses consultants because it believes it is more cost effective than employing a larger full time staff.
Oil and Gas Properties
Williston Basin
Valley County, Montana
The Company’s assets in Valley County consist of leases covering approximately 87,415 net acres. The Company’s working interest in these properties is 100% and would be reduced to 75% at payout, except as modified by the agreements described below. Most of the leases were acquired during 2005, but some were included in the approximately 27,780 gross acres (27,740 net acres) the Company acquired in February of 2006, most of which expired in March 2009. Two wells have been drilled on the leases held by the Company but one has not yet been completed and tested and the other was damaged during drilling and could not be tested, so the Company has no proved reserves on the property as yet. The Company currently has one active agreement covering part of its Valley County Leases. Two other agreements covering areas of the Valley County Leases expired during 2008.
In May 2008, the Company entered an agreement with Cobra Oil and Gas (“Cobra”). Under the agreement, Cobra paid Coastal $180,000 for the option to acquire a half interest in approximately 78,000 acres (originally 87,000 acres, but some have expired) of Coastal’s Valley County Leases. The agreement allowed the Company to pay its Lease rentals that were due June 1st and brought in a new party to explore on the Leases. Cobra has two years to exercise the option by spending $1,000,000 on behalf of the Company, drilling wells on the leases under the agreement. Those leases include approximately 62,000 acres of leases that were formally under an agreement with F-Cross Resources that expired earlier this year and more than 17,000 acres of other leases Coastal held in Valley County.
During 2008 two agreements the Company had with other entities on the Valley County Leases expired. First, in August 2007, the Company entered into a farm-out agreement with Western Standard. Under the agreement Western Standard paid $40,000 to Coastal and then paid an additional $384,000 to cover the costs of drilling the first well to test a shallow natural gas prospect in Valley County, Montana and to cover associated lease rentals. Western Standard would have had an interest in that well and the option to purchase a 50% interest in approximately 37,000 acres near the well location for $1,000,000, payable in $200,000 installments based on certain milestones related to drilling step-out wells.
The first well under the agreement with Western Standard was drilled during October 2007, and reached a total depth of 1,126 feet, casing was run into the hole after there were gas shows at two horizons during drilling. The well is located on Federal land and the Bureau of Land Management would not allow the completion and testing operations or any further drilling to begin between December 1st and July 1st, so operations were suspended until July 2008. In light of the delay an additional agreement was reached with Western Standard in which the Company received an additional $29,000 from Western Standard to cover costs associated with the delay in well completion. Western Standard also paid the estimated well completion costs of $65,000 and completion operations performed in two stages during the third quarter of 2008 and proceeded to the third stage during the fourth quarter. In October 2008, the Company received approximately $29,000 from Western Standard to pay for the third stage of operations which included stimulation of the well, a common procedure in completing oil and gas wells.
The Company was unable to determine by this well whether the target formations contain economic quantities of gas. Drilling damage in the well prevented the testing of either of the prospective formations at this location. Completion efforts found that the Eagle formation was damaged by the initial drilling and the formation was not able to be tested from this well. Further drilling into the Eagle formation during completion did not yield gas like the gas show seen from the upper part of the formation that was damaged. The Judith River formation, a secondary target, was damaged by drilling fluids lost into the formation while drilling through it to get to the Eagle formation, the primary target. Future wells to test this structure will incorporate the information obtained from these wells to prevent that damage from occurring again in other locations on the structure.
It is not unusual that the first well confirming a structure does not become a producing well. The test well did produce valuable information about the two gas bearing formations and their potential for economically feasible commercial gas production. Problems encountered in drilling the test well can now be avoided when future wells are drilled on the Starbuck East Prospect. With the first two objectives met, the Company will now focus on achieving the third objective, specifically finding commercial gas in either the Eagle or Judith River formations.
Western Standard had 30 days after the completion of the Federal 1-19 to exercise an option to purchase a 50% interest in approximately 37,000 acres near the well location for $1,000,000, but the deadline passed without being exercised. Western Standard no longer has an interest in these leases and Coastal Petroleum is now in control of them again.
The Company’s agreement with F-Cross was the other agreement that expired in 2008. Originally entered, in September 2007, the Company received $50,000 from F-Cross under the farm-out agreement covering approximately 64,000 acres on the northwest part of the Company’s Valley County Leases. F-Cross had the option to drill a Lodgepole test well at its cost within six months and after drilling that well had the further option to acquire an interest in surrounding acreage. F-Cross also could have extended its option to acquire the 50% working interest by drilling a second Lodgepole test well. On November 3, 2007, F-Cross spudded the first well under the Agreement with the Company. The well was drilled to test a Lodgepole reef oil prospect and drilling on the well has finished and is awaiting completion. As of this time it is uncertain whether F-Cross will proceed with completion. F-Cross, however, did not meet the requirements in the agreement and in late March 2008 the option to acquire an interest in the additional 64,000 acres covered by the agreement expired, leaving F-Cross with rights only in the section in which it drilled the well.
Billings, Slope and Stark Counties, North Dakota
The Company owns leases covering approximately 8,510 net acres in these three counties. Generally, the Company’s working interest in these properties is 100% and at payout is reduced to 75%. However, under a farm-out agreement with Western Standard, Coastal assigned leases over four of its high-graded Lodgepole Reef prospects to Western Standard in return for $80,000. Coastal retains a back-in working interest of 20% in those leases after payout. The leases cover all rights below the Tyler formation, including the Lodgepole formation, with an 80% net revenue interest. These and other leases in the area were acquired in 2005 by Coastal from Oil For America for $50,000 and Coastal has invested some additional funds to geochemically test and high-grade these and other prospects on the leases. Oil For America has agreed to waive the drilling obligation on the four prospects assigned to Western Standard. After the assignment, Coastal still retains additional Lodgepole reef prospects on its North Dakota leases under the general working interest described above. The Company has not yet begun any drilling on the property and has no proved reserves on the property.
Acreage and Wells
The following chart reflects the approximate acreage held under lease by Coastal Caribbean through its wholly owned subsidiary Coastal Petroleum, at December 31, 2008:
Acreage under lease at December 31, 2008
(1) A gross acre is an acre in which a working interest is owned.
(2) A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
(3) Subsequent to the end of 2008, leases covering 27,496.04 gross acres (27,417.04 net acres) on the Company’s Montana acreage expired in March 2009.
Completion efforts were undertaken on one well in 2008, but it could not be tested and two wells were drilled in 2007 on our leases.
Drilling Activity
During 2008 no wells were drilled, but completion efforts were undertaken on the Federal 1-19 well drilled in 2007, but the well could not be tested. The results for that well are discussed below.
During 2007, two wells were drilled on the Company’s Valley County, Montana Leases under two separate agreements, with two different entities and covering different areas within the Company’s Valley County Leases.
The first well, the Federal 1-19, was drilled by Western Standard to test a shallow natural gas prospect near the middle of the Company’s Valley County Leases. This well was the initial well drilled under an agreement with Western Standard. The well reached a total depth of 1,126 feet, and operations to complete and test the well were delayed until 2008 because the well is located on Federal land and the Bureau of Land Management would not allow the completion and testing operations or any further drilling to begin between December 1st and July 1st.
Once operations were resumed, the Company was unable to determine by this well whether the target formations contain economic quantities of gas. Drilling damage in the well prevented the testing of either of the prospective formations at this location. Completion efforts found that the Eagle formation was damaged by the initial drilling and the formation was not able to be tested from this well. Further drilling into the Eagle formation during completion did not yield gas like the gas show seen from the upper part of the formation that was damaged. The Judith River formation, a secondary target, was damaged by drilling fluids lost into the formation while drilling through it to get to the Eagle formation, the primary target. Future wells to test this structure will incorporate the information obtained from these wells to prevent that damage from occurring again in other locations on the structure.
The second well drilled on the Company’s Valley County Leases in 2007 was drilled by F-Cross under an agreement with F-Cross, covering the northwestern part of Coastal’s Valley County, Montana Leases. The first Lodgepole test well was spudded on November 3, 2007 and the well is awaiting completion and testing of several zones which have potential for both oil and gas. F-Cross, however, did not meet the requirements in the agreement and in late March 2008 the option to acquire an interest in the additional 64,000 acres covered by the agreement expired, leaving F-Cross with rights only in the section in which it drilled the well.
The Company also participated in and acted as operator in a twin well to the only known well to produce from the Lodgepole in Montana. The targeted Lodgepole reef contained oil, but not in sufficient quantities to be economical for the Company to develop. Likewise, an uphole test of the Mission Canyon Formation resulted in oil being encountered, but not in sufficient quantities to be economical for the Company to develop. The Company’s participation costs in the twin well were approximately $245,000, which was expensed in the fourth quarter of 2006. The total cost of the well was approximately $1,360,000. There are approximately $115,000 in unpaid expenses related to this well that are collectively the responsibility of the various partners. This amount is not reflected as a liability in the accompanying financial statements. This well was abandoned.
Item 1B.
Item 1B. Unresolved Staff Comments
None
Item 2.
Item 2. Properties
Properties
Information required by Item 2 “Properties” is included under Item 1 “Business.”
Disclosure Concerning Oil and Gas Operations.
Since the properties in which the Company has interests are undeveloped and nonproducing, items 2 through 4 of Securities Exchange Act Industry Guide 2 are not applicable.
(5)
Undeveloped Acreage.
The Company's undeveloped acreage as of December 31, 2008 was as follows:
_________________
*
Subsequent to the end of 2008, leases covering 27,496.04 gross acres (27,417.04 net acres) on the Company’s Montana acreage expired in March 2009.
(6)
Drilling Activity.
One well underwent completion efforts, but could not be tested during 2008 on the Company’s leases through a farm-out agreement. See Drilling Activity section under Item 1 Business at page 9.
(7)
Present Activities.
See Drilling Activity section under Item 1 Business at page 9.
Item 3.
Item 3. Legal Proceedings
None.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5.
Item 5. Market for the Company's Common Stock, Related
Stockholder Matters and Issuer Purchases of Equity Securities
Market Information.
The principal market for the Company's common stock is in the over-the-counter market on the "Electronic Bulletin Board" of the National Association of Securities Dealers, Inc. under the symbol COCBF. The quarterly high and low closing prices on the Electronic Bulletin Board during the last two years were as follows:
Holders.
The approximate number of record holders of the Company's common stock at March 12, 2009 was 8,263.
Dividends.
The Company has never declared or paid dividends on its common stock and it does not anticipate declaring or paying any dividends in the foreseeable future. The Company plans to retain any future earnings to reduce the deficit accumulated during the development stage of $36,215,202 at December 31, 2008 and to finance its operations.
Foreign Exchange Control Regulations
The Company is subject to the applicable laws of The Islands of Bermuda relating to exchange control, but has the permission of the Foreign Exchange Control of Bermuda to carry on business in, to receive, disburse and hold United States dollars and dollar securities under its designation as an External Account Company. The Company has been advised that, although as a matter of law it is possible for such designation to be revoked, there is little precedent for revocation under Bermuda law.
Income and Withholding Taxes
Coastal Caribbean is a Bermuda corporation. Bermuda currently imposes no taxes on corporate income or capital gains realized outside of Bermuda. Any amounts received by Coastal Caribbean from United States sources as dividends, interest, or other fixed or determinable annual or periodic gains, profits and income, will be subject to a 30% United States withholding tax. In addition, any dividends from its domestic subsidiary, Coastal Petroleum, will not be eligible for the 100% dividends received deduction, which is allowable in the case of a United States parent corporation. Shares of the Company held by persons who are citizens or residents of the United States are subject to federal estate and gift and local inheritance taxation. Any dividends received by such persons will also be subject to federal, State and local income taxation. The foregoing rules are of general application only, and reflect law in force as of the date of this report.
A convention between Bermuda and the United States relating to mutual assistance on tax matters became operative in 1988.
Passive Foreign Investment Company Rules
The Internal Revenue Code of 1986, as amended, provides special rules for distributions received by U.S. holders on stock of a passive foreign investment company (PFIC), as well as amounts received from the sale or other disposition of PFIC stock.
Under the PFIC rules, a non-U.S. corporation will be classified as a PFIC for U.S. federal income tax purposes in any taxable year in which, after applying certain look-through rules, either (1) at least 75 percent of its gross income is passive income or (2) at least 50 percent of the gross value of its assets is attributable to assets that produce passive income or are held for the production of passive income.
Passive income for this purpose generally includes dividends, interest, royalties, rents, and gains from commodities and securities transactions. Special rules apply in cases where a foreign corporation owns directly or indirectly at least a 25 percent interest in a subsidiary, measured by value. In this case, the foreign corporation is treated as holding its proportionate share of the assets of the subsidiary and receiving directly its proportionate share of the income of the subsidiary when determining whether it is a PFIC. Thus, Coastal Caribbean would be deemed to receive its pro rata share of the income and to hold its pro rata share of the assets, of Coastal Petroleum.
Based on certain estimates of its gross income and gross assets and the nature of its business, Coastal Caribbean would be classified as a PFIC for the years 1987 through 2006. Once an entity is considered a PFIC for a taxable year, it will be treated as such for all subsequent years with respect to owners holding the stock in a year that it was classified as a PFIC under the income or asset test described above. Whether the Company will be a PFIC under either of these tests in future years will be difficult to determine because the tests are applied annually. Based upon the estimated gross income of the Company during 2008, the major source of the income being from the farm-out agreements through which the Company sold an interest in parts of its leases to other companies, and the relatively small amount of interest the Company received, the Company believes that Coastal Caribbean would not be classified as a PFIC for the year 2008.
If Coastal Caribbean is classified as a PFIC with respect to a U.S. holder any gain from the sale of, and certain distributions with respect to, shares of our common stock, would cause a U.S. holder to become liable for U.S. federal income tax under Code section 1291 (the interest charge regime). The Company recommends that any such U.S. holder should consult his or her own tax advisor on this issue. The tax is computed by allocating the amount of the gain on the sale or the amount of the distribution, as the case may be, to each day in the U.S. shareholder’s holding period. To the extent that the amount is allocated to a year, other than the year of the disposition or distribution, in which the corporation was treated as a PFIC with respect to the U.S. holder, the income will be taxed as ordinary income at the highest rate in effect for that year, plus an interest charge. The interest charge would generally be calculated as if the distribution or gain had been recognized ratably over the U.S. holder's holding period (for PFIC purposes) for the shares. To the extent an amount is allocated to the year of the disposition or distribution, or to a year before the first year in which the corporation qualified as a PFIC, the amount so allocated is included as additional gross income for the year of the disposition or distribution. A U.S. holder also would be required to make an annual return on IRS Form 8621 that describes any distributions received with respect to our shares and any gain realized on the sale or other disposition of our shares.
As an alternative to taxation under the interest charge regime, a U.S. holder generally can elect, subject to certain limitations, to annually take into gross income the appreciation or depreciation in our common shares' value during the tax year (mark-to-market election). If a U.S. holder makes the mark-to-market election, the U.S. holder will not be subject to the above-described rule. Instead, if a U.S. holder makes the mark-to-market election, the U.S. holder recognizes each year an amount equal to the difference as of the close of the taxable year between the U.S. holder's fair market value of the common shares and the adjusted basis in the common shares. Losses would be allowed only to the extent of net gain previously included by the U.S. holder under the mark-to-market election for prior taxable years. Amounts included in or deducted from income under the mark-to-market election and actual gains and losses realized upon the sale or disposition of the common shares, subject to certain limitations, will be treated as ordinary gains or losses. If the mark-to-market election is made for a year other than the first year in the U.S. holder’s holding period in which the corporation was a PFIC, the first year’s mark-to-market inclusion, if any, is taxed as if it were a distribution subject to the interest charge regime discussed above.
Another alternative election which would allow a U.S. holder to elect to take its pro rata share of Coastal Caribbean's undistributed income into gross income as it is earned by Coastal Caribbean (QEF election) would only be available to a U.S. holder if Coastal Caribbean provided certain information to the shareholders of Coastal Caribbean. Coastal Caribbean has had no undistributed income for the years 1987 through 2008. If the QEF election is made in a year other than the first year of the U.S. holder’s holding period in which the foreign corporation is a PFIC, both the QEF regime and interest charge regime can apply, unless a special election is made. Under this special election, the taxpayer is treated as if it disposed of its PFIC stock in a transaction subject to the interest charge rules to the extent gain is deemed to be recognized. Once this election is made, the holder will be subject only to the QEF regime.
Recent Sales of Unregistered Securities
None
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None
Item 6.
Item 6. Selected Consolidated Financial Information
The following selected consolidated financial information (in thousands except for per share amounts) for the Company insofar as it relates to each of the three years in the period ended December 31, 2008 has been taken from the Company's consolidated financial statements.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Statements included in Management's Discussion and Analysis of Financial Condition and Results of Operations which are not historical in nature are intended to be forward looking statements. The Company cautions readers that forward looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those indicated in the forward looking statements. For a discussion of certain risk factors affecting the Company, please see “Risk Factors” above.
General
We are an active independent oil and gas exploration company and through our subsidiary, Coastal Petroleum, we hold mineral rights in Montana and North Dakota in the oil producing region known as the Williston Basin. Our objective formations on those leases include the Lodgepole and the Eagle among others. The Company's future growth will be driven primarily by exploration and development activities. Our business strategy is to increase shareholder value by acquiring and drilling reasonably priced prospects that have good potential, whether in the Williston Basin or in other parts of the United States, with the goal of shaping the Company into a producing independent oil and gas firm. We will continue to seek high quality exploration projects with potential for providing long-term drilling inventories that generate high returns.
In Montana, we have obtained the rights to explore for oil and gas in one area which will be our primary area of focus. This primary area is a large assembly of leases covering approximately 87,415 net acres in Valley County, located in northeastern Montana close to known production from a Lodgepole reef. At the end of 2008, the Company held 114,832 net acres in Valley County, but in March 2009, approximately 27,417 acres expired. Those expired leases were not covering our Starbuck East propect.
This area of Montana has a number of other producing formations in addition to the Lodgepole, including the Eagle sands. Currently we have one agreement with a party covering some of the areas of the leases and during 2008 we had two agreements expire under which exploration had begun on the leases. We also hold leases in southwestern North Dakota and have an agreement covering four Lodgepole prospects on those leases.
We are actively engaged in pursuing funding for our 2009 Drilling Program. The Program is an aggressive $9,500,000 exploration operation which would allow us to explore the potential of each of the areas we hold under lease. The Drilling Program covers exploration in four areas: a development Red River Formation prospect in Slope County, North Dakota, on approximately 400 acres we acquired; the drilling of three Lodgepole Formation prospects we have on our North Dakota Leases; ten step out wells from the Federal 1-19 well on the Starbuck East prospect in Montana; and the drilling of two other shallow gas prospects in Montana, but located off from the Starbuck East prospect. The Company is proceeding with the relativily inexpensive process of permitting wells in its main block of leases in Valley County, Montana, in order to accommodate the drilling of the expected wells. The 2009 Drilling Program is currently being reviewed by prospective funding parties. This Drilling Program is separate from the agreements described below.
In May 2008, we entered an agreement with Cobra. Under the agreement, Cobra paid Coastal $180,000 for the option to acquire a half interest in approximately 87,000 acres of Coastal’s Valley County Leases. The agreement allowed the Company to pay its Lease rentals that were due June 1st and brings in a new party to explore on the Leases. Cobra will have two years to exercise the option by spending $1,000,000 on behalf of the Company, drilling wells on the leases covered by the agreement. Those leases include approximately 62,000 acres of leases that were formally under an agreement with F-Cross Resources that expired earlier this year and more than 20,000 acres of other leases Coastal held in Valley County. No drilling has taken place yet under this agreement.
Two other agreements covering the leases expired during 2008. The first of the two agreements was a farm-out agreement with Western Standard, entered in August 2007. Under the agreement, Western Standard paid us $40,000 at execution and then paid an additional $384,000. From the $384,000, $255,000 was paid to cover the costs of drilling the first well to test a shallow natural gas prospect in Valley County, Montana and $129,000 was paid to cover associated lease rentals. Western Standard would have had an interest in the first well drilled as well as an option to purchase a 50% interest in the 42,000 acres under the lease. Upon receiving the funds to cover lease rentals, we repaid in full our loan of $126,000. Under the loan agreement, the individual that loaned us the money continues to hold a 5% overriding royalty on the same approximately 42,000 acres that are covered in the Western Standard farm-out agreement.
The first well under this agreement was drilled during October 2007, to test a shallow natural gas prospect near the middle of the Company’s Valley County Leases. The well, known as the Federal 1-19 Well, had three objectives: to confirm the 34,000 acre Starbuck East Prospect by finding that the Eagle formation was high to surrounding wells off the Prospect; to confirm that there were good natural gas shows in the Starbuck East Prospect; and to find commercial gas in either the Eagle formation or the Judith River formation. The first two objectives were met. Due to drilling damage, the third objective has not yet been met.
During October 2007, the Federal 1-19 well reached a total depth of 1,126 feet, and confirmed the structural high that was targeted. The well also had gas shows in two zones. Casing was run into the hole and operations to complete and test the well were scheduled to begin at the end of November, but were delayed by equipment repairs. The well is located on Federal land and the Bureau of Land Management would not allow the completion and testing operations or any further drilling to begin until July 2008, so operations were suspended until that time. The Company also received an additional $29,000 from Western Standard to cover additional drilling and other costs associated with the delay in well completion, which has been recorded as a reduction in capitalized petroleum lease costs. Western Standard paid the estimated well completion costs of $65,000 and operations to complete and test the well were performed in two stages during the third quarter and proceeded to the third stage in the fourth quarter of 2008. In October 2008, the Company received approximately $29,000 from Western Standard to pay for the third stage of operations which included stimulation of the well, a common procedure in completing oil and gas wells.
The Company was unable to determine by this well whether the target formations contain economic quantities of gas. Drilling damage in the well prevented the testing of either of the prospective formations at this location. Completion efforts found that the Eagle formation was damaged by the initial drilling and the formation was not able to be tested from this well. Further drilling into the Eagle formation during completion did not yield gas like the gas show seen from the upper part of the formation that was damaged. The Judith River formation, a secondary target, was damaged by drilling fluids lost into the formation while drilling through it to get to the Eagle formation, the primary target. Future wells to test this structure will incorporate the information obtained from these wells to prevent that damage from occurring again in other locations on the structure.
It is not unusual that the first well confirming a structure does not become a producing well. The test well did produce valuable information about the two gas bearing formations and their potential for economically feasible commercial gas production. Problems encountered in drilling the test well can now be avoided when future wells are drilled on the Starbuck East Prospect. With the first two objectives met, the Company will now focus on achieving the third objective, specifically finding commercial gas in either the Eagle or Judith River formations. We have received one permit to drill a step-out well and are currently in the permitting process for two more.
After the completion efforts on the Federal 1-19 well were finished, Western Standard had the option to purchase a 50% interest in approximately 42,000 acres near the well location for $1,000,000. The time to exercise that option passed and Western Standard did not exercise it, so we regained complete control of the leases formerly under the Western Standard agreement and Western Standard no longer has an interest in them.
The other agreement that expired in 2008 was with F-Cross and was entered in September of 2007, covering approximately 64,000 acres on the northwest part of our Valley County Leases. Under the agreement, F-Cross had the option to drill a Lodgepole test well within six months and after drilling that well had the further option to acquire an interest in surrounding acreage. F-Cross was to pay for the cost of drilling the initial well and will receive a 100% working interest in the well until payout and an 80% working interest subsequent to payout. F-Cross exercised its option and the first Lodgepole test well was spudded on November 3, 2007. Drilling has finished, but the well is still awaiting completion and testing of several zones which have potential for both oil and gas. However, F-Cross did not meet the requirements in the agreement and in late March 2008 the option to acquire an interest in additional acreage expired, leaving F-Cross with rights only in the section in which it drilled the well.
The two wells we were involved with drilling during 2006 and that were abandoned during 2007 were drilled in areas outside of our Valley County Leases. The first of those wells we drilled ourselves on a small tract in Blaine County in north central Montana, more than 130 miles west of our Valley County acreage. We drilled to a depth of 4,600 feet and reached the targeted Lodgepole reef, but the reef had been flushed with water and there was no oil present. The well passed through multiple other zones that potentially contained oil or gas and each of the other zones was tested, but no gas or oil was present in economic quantities. We will not pursue any further drilling in this area.
The second well drilled under a farm-in agreement on a location in Valley County, south of our primary acreage. We participated in and acted as operator for the drilling of that well which was known as the Evaline twin well. It was drilled to total depth into the Lodgepole reef that was targeted and encountered oil, but not in sufficient quantities for us to earn an interest. We then moved uphole and perforated the Mission Canyon Formation which had a significant show of oil while we were drilling to the Lodgepole. We tested the Mission Canyon and it too contained oil, but again not in sufficient quantities for us to earn an interest in the well. Under the Agreement with farmor Helis, there was a production threshold that had to be met to earn the interest and that threshold could not be met. We have abandoned this well and will now focus on our primary area.
In North Dakota, we control the working interest on approximately 8,510 net acres in Slope, Billings, and Stark Counties, on which a number of drillable prospects have been mapped to date. The depth of wells in North Dakota is greater than in Montana (approximately 9,500 feet versus approximately 5,000 feet), and thus the cost of drilling is higher. A typical North Dakota wildcat well costs about $1.5 million to drill. We had originally intended to bring in others to share the risk and investment in wells it drills in North Dakota until the Company is in a stronger financial position, but are now actively seeking funding to allow us to begin such exploration on our own.
Through our efforts to bring in others to explore our North Dakota leases, in December of 2007 we entered a new farm-out agreement with Western Standard. Under the agreement, we assigned leases over four of our high-graded Lodgepole Reef prospects to Western Standard in return for $80,000. We received $40,000 in November 2007, $25,000 in February 2008 and the other $15,000 in April 2008. We will also retain a back-in working interest of 20% in the leases after payout. The leases cover all rights below the Tyler formation, including the Lodgepole formation, with an 80% net revenue interest. We acquired these and other leases in the area in 2005 from Oil For America for $50,000 and we have invested some additional funds to geochemically test and high-grade these and other prospects on the leases. Oil For America has agreed to waive the drilling obligation on these four prospects. We will still retain additional Lodgepole reef prospects on our North Dakota leases that are not covered by this farm-out agreement.
If our funding efforts are succesfull, we plan to drill or participate in as many as sixteen exploratory wells under our 2009 Drilling Plan. However, the number of wells that we drill in 2009 and their cost will be subject to various factors, including whether or not we can obtain sufficient funding to carry out the 2009 drilling program, whether Cobra will exercise its option and begin exploration under its agreements, the availability of drilling rigs that we can hire and whether we drill alone or with other participants. In addition, we could reduce the number of wells that we drill if oil and natural gas prices were to decline significantly. We expect the cost of drilling the sixteen wells to depend upon many factors, including those above, which may affect the cost of operations and whether and to what extent others participate with the Company.
Liquidity and Capital Resources
As more fully described in Note 1 to the consolidated financial statements, we have no recurring revenues, have experienced recurring losses and have a deficit accumulated during the development stage. We, along with various other related parties, settled several lawsuits in 2005, which were filed by the Company, our subsidiary Coastal Petroleum Company and other related parties against the State of Florida. All of these lawsuits were related to the State’s actions limiting our ability to commence development activities through our subsidiary. The cost of that litigation was substantial. Management believes its current cash position, the agreement with Cobra, and its active efforts to obtain funding will allow the Company to move forward to explore and develop profitable oil and gas operations, although there is no assurance these efforts will be successful. These situations raise substantial doubt about our ability to continue as a going concern. Our consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or amounts and classification of liabilities, which may result from the outcome of these uncertainties.
At December 31, 2008, we have approximately $1,000 in cash compared to approximately $30,000 at December 31, 2007. Our current liabilities exceed our current assets by approximately $816,000 at December 31, 2008. We have suspended payments to our directors, general legal counsel, and employee since the second quarter of 2007 and have accrued $817,000 in expenses as of December 31, 2008. We expect to continue to suspend payments to these parties for at least the first quarter of 2009 or until sufficient funding can be secured to resume exploration operations and cover normal operating expenses.
During 2008, we received approximately $218,000 under farm-out agreements for lease and drilling rights on our leases and options to acquire additional rights and redeemed a $50,000 certificate of deposit released from restrictions as a drilling bond. Also during 2008, we used the funds received during the year primarily to pay our annual lease payments and other operating expenses. We may need to sell additional lease rights to obtain the cash to make future lease rental payments, although there is no guarantee we will be able to sell additional lease rights.
During 2007, we abandoned the two wells we drilled and participated in 2006 and we spent $263,000 for well drilling costs and maintenance of our oil and gas lease rights including the payment of rentals on the approximately 124,882 net acres of leases we held at the time in Valley County, Montana, totaling $244,000, of which $126,000 was received from Western Standard. These leases are subject to various overriding royalty interests held by others of up to 19.5%. The leases expire in years from 2011 to 2014.
We expect to continue to participate with others or to obtain sufficient funding to allow the Company to drill additional wells both in Montana and North Dakota.
Results of Operations and Critical Accounting Policies and Estimates
Development Stage Enterprise Presentation
The Company is a development stage enterprise. It has never had substantial revenues and has operated at a loss each year (except 2005) since its inception in 1953.
Oil and Gas Accounting
The Company follows the full cost method of accounting for its oil and gas properties. All costs associated with property acquisition, exploration and development activities whether successful or unsuccessful are capitalized.
The capitalized costs are subject to a ceiling test which basically limits such costs to the aggregate of the estimated present value discounted at a 10% rate of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties. The Company assesses whether its unproved properties are impaired on a periodic basis. This assessment is based upon work completed on the properties to date, the expiration date of its leases and technical data from the properties and adjacent areas.
During 2007, we drilled two wells on Company leases under two farm-out agreements. We expect to determine the success of these wells in July 2008. We expensed an additional $53,000 related to abandoning the 2006 wells.
During 2008, we did not conduct drilling activities due to weather and/or landowner access restrictions on our leases from January 1st to July 1st. We performed some completion work in two stages during the 3rd quarter and finished the remainder of the operations, including completion work, stimulation and testing of the well, during the 4th quarter of 2008. Substantially all the drilling activity on our leases during 2007 and 2008 was financed under farm-out agreements with other entities, and we expect that to continue, although there is no guarantee we will enter additional farm-out agreements.
2008 vs.
During 2007, two wells were drilled on our leases under two farm-out agreements and completion efforts were carried out on one of those wells in 2008. Substantially all drilling costs were financed by our farm-out partner. We also continued to seek additional leases and prospects as well as capital partners with whom to drill. However, we did not recognize any revenue in 2007 or 2006. Our net loss for 2008 was $(546,000) compared to a net loss of $(690,000) for 2007.
For 2008 and 2007, we focused on seeking other entities to drill wells on our leases and in drilling wells. Our expenses did not change significantly in 2008 from 2007, except we wrote off our well drilling costs of $53,000 in 2007. Our expenses consist of administrative corporate and regulatory costs, and the administrative, travel, and lodging costs to conduct drilling operations in Montana.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
Not applicable.
Item 8.
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Board of Directors
Coastal Caribbean Oils & Minerals, Ltd.
Apalachicola, Florida
We have audited the consolidated balance sheets of Coastal Caribbean Oils & Minerals, Ltd. and subsidiary as of December 31, 2008 and 2007, and the related consolidated statements of operations, cash flows and common stock and capital in excess of par value, for the years then ended, and for the period from January 31, 1953 (inception) to December 31, 2008. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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 the overall financial statement presentation. We believe that our audit provided 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 Coastal Caribbean Oils & Minerals, Ltd. and subsidiary as of December 31, 2008 and 2007, and the results of their operations and cash flows for the years then ended, and for the period from January 31, 1953 (inception) to December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company suffered recurring losses from operations and has not yet realized any revenues from development activities. This raises substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
We were not engaged to examine management’s assertion about the effectiveness of Coastal Caribbean Oils & Minerals, Ltd’s internal control over financial reporting as of December 31, 2008 included in the accompanying Management’s annual report on internal control over financial reporting and, accordingly, we do not express an opinion thereon.
/s/ Baumann, Raymondo & Company PA
Tampa, Florida
March 27,
COASTAL CARIBBEAN OILS & MINERALS, LTD.
(A Bermuda Corporation)
A Development Stage Company
CONSOLIDATED BALANCE SHEETS
(Expressed in U.S. dollars)
See accompanying notes.
COASTAL CARIBBEAN OILS & MINERALS, LTD.
(A Bermuda Corporation)
A Development Stage Company
CONSOLIDATED STATEMENTS OF OPERATIONS
(Expressed in U.S. Dollars)
See accompanying notes.
COASTAL CARIBBEAN OILS & MINERALS, LTD.
(A Bermuda Corporation)
A Development Stage Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Expressed in U.S. Dollars)
See accompanying notes.
COASTAL CARIBBEAN OILS & MINERALS, LTD.
(A Bermuda Corporation)
A Development Stage Company
CONSOLIDATED STATEMENT OF COMMON STOCK
AND CAPITAL IN EXCESS OF PAR VALUE
(Expressed in U.S. dollars)
For the period from January 31, 1953 (inception) to December 31, 2008
See accompanying notes.
1.
Summary of significant accounting policies
Consolidation
The accompanying consolidated financial statements include the accounts of Coastal Caribbean Oils & Minerals, Ltd., a Bermuda corporation (“Coastal Caribbean”) and its wholly owned subsidiary, Coastal Petroleum Company (“Coastal Petroleum”), referred to collectively as the Company. The Company, which has been engaged in a single industry and segment, is considered to be a development stage company since its exploration for oil, gas and minerals has not yielded any significant revenue or reserves. All intercompany transactions have been eliminated. Certain prior year amounts have been reclassified to conform with the current year presentation.
Cash and Cash Equivalents
The Company considers all highly liquid short-term investments with maturities of three months or less at the date of acquisition to be cash equivalents.
Equipment
Equipment is recorded at cost. Depreciation is provided using straight-line over five years, the estimated useful lives of the assets.
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. The ability to develop the Company’s oil and gas properties will have a significant effect on the Company’s financial position and results of operations. Actual results could differ from those estimates.
Unproved Oil, Gas and Mineral Properties
The Company follows the full cost method of accounting for its oil and gas properties. All costs associated with property acquisition, exploration and development activities whether successful or unsuccessful are capitalized.
Once the Company has proved reserves the capitalized costs will be subject to a ceiling test which basically limits such costs to the aggregate of the estimated present value discounted at a 10% rate of future net revenues from proved reserves, based on current economic and operating conditions. Currently the capitalized costs are carried at the lower of cost or fair market value of unproved properties.
The Company assesses whether its unproved properties are impaired on a periodic basis. This assessment is based upon work completed on the properties to date, the expiration date of its leases and technical data from the properties and adjacent areas. As of December 31, 2008, no impairment existed. Sales of unproved nonoperating interests in oil and gas leases are accounted for as a reduction in the capitalized amount of the leases.
Sale of Subsidiary Shares
All amounts realized from the sale of Coastal Petroleum shares have been credited to capital in excess of par value.
Net Income (Loss) Per Share
Net income (loss) per common share is based upon the weighted average number of common and common equivalent shares outstanding during the period. The Company’s basic and diluted calculations of EPS are the same because the exercise of options is not assumed in calculating diluted EPS, as the result would be anti-dilutive.
1. Summary of significant accounting policies (Cont'd)
Financial instruments
The carrying value for cash and cash equivalents, certificates of deposit, and accounts payable approximates fair value based on anticipated cash flows and current market conditions.
Stock Based Compensation
The Company uses the fair value based method of accounting for its stock option plans. Effective January 1, 2006, the Company adopted SFAS No. 123 (Revised 2004), Share-Based Payments, which requires companies to expense stock options and other share-based payments. SFAS No. 123R supersedes SFAS No. 123, which permitted either expensing stock options or providing pro forma disclosure. The Company adopted the modified prospective application transition method as proscribed by SFAS No. 123R, which applies to all new awards and to awards granted, modified, canceled, or repurchased after January 1, 2006, as well as the unvested portion of the prior awards. The adoption of SFAS No. 123R resulted in no changes to the 2006 or prior financial statement amounts or disclosures.
New Accounting Pronouncements
The Financial Accounting Standards Board (“FASB”) has issued several new standards which have implementation dates subsequent to the Company’s year end. Management does not believe that any of these new standards will have a material impact on the Company’s financial position, results of operations or cash flows.
Going Concern
The Company has no recurring revenues, had recurring losses since 2006 and prior to 2005, and has a deficit accumulated during the development stage. The Company's current cash position is not adequate to fund existing operations or exploration and development of its oil and gas properties. Curently, management is actively pursuing funding to allow the Company to undertake exploration efforts on its own. The Company
has had contact with several parties interested in investing in the Company so that the Company could explore its leases on its own. In addition, the Company has been in contact with other parties interested in working with the Company, in buying some of the Company’s leases or in buying an interest in those leases. There is no assurance that the Company will be able to obtain any funding, that sufficient funding can be obtained, or that the Company will be able to raise necessary funds through the sale of some of its leases or interests in those leases.
These situations raise substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or amounts and classification of liabilities, which may result from the outcome of this uncertainty.
2. Unproved Oil, Gas and Mineral Properties
Farm-out Agreements and Drilling Activity
In May 2008, the Company entered an agreement with Cobra Oil and Gas (“Cobra”). Under the agreement, Cobra paid Coastal $180,000 for the option to acquire a half interest in approximately 78,000 acres of Coastal’s Valley County Leases. The agreement allowed the Company to pay its Lease rentals that were due June 1st and brings in a new party to explore on the Leases. Cobra will have two years to exercise the option by spending $1,000,000 on behalf of the Company, drilling wells on the leases under the agreement. Those leases include approximately 62,000 acres of leases that were formally under an agreement with F-Cross Resources (“F-Cross”) that expired earlier this year and more than 17,000 acres of other leases Coastal held in Valley County.
2. Unproved Oil, Gas and Mineral Properties (Cont'd)
In August 2007, the Company entered into a farm-out agreement with Western Standard Energy Corp. (“Western Standard”) Under the agreement Western Standard paid $40,000 up front to Coastal and then paid an additional $255,000 to cover the costs of drilling the first well to test a shallow natural gas prospect in Valley County, Montana and $129,000 to cover associated lease rentals. The Company did not record the receipt of the $255,000 or the cost of the associated well and recorded the remaining $169,000 as a reduction in capitalized petroleum lease costs. The Agreement expired in 2008 when Western Standard did not exercise its option under the Agreement.
The first well under this agreement was drilled during October 2007, to test a shallow natural gas prospect near the middle of the Company’s Valley County Leases. The well reached a total depth of 1,126 feet, and confirmed the structural high that the Company believed to be there. The well also had gas shows in two zones. Casing was run into the hole and operations to complete and test the well were delayed but took place in 2008. The Company also received an additional $29,000 from Western Standard to cover additional drilling and other costs associated with the delay in well completion, which has been recorded as a reduction in capitalized petroleum lease costs. Western Standard also paid the estimated well completion costs of $65,000 before operations began in 2008. The completion efforts revealed that the well had been damaged and could not be tested. Once completion efforts were finished on the well, Western Standard had 30 days to exercise its option to purchase a 50% interest in the leases, but did not so exercise.
In September 2007, the Company received $50,000 from F-Cross when the two parties entered into a farm-out agreement covering approximately 64,000 acres on the northwest part of the Company’s Valley County Leases. Under the agreement, F-Cross had the option to drill a Lodgepole test well within six months and after drilling that well had the further option to acquire an interest in surrounding acreage. F-Cross was to pay for the cost of drilling the initial well and receive a 100% working interest in the well until payout and an 80% working interest subsequent to payout with the Company retaining the other 20%. The first Lodgepole test well was spudded on November 3, 2007 and drilling has finished, but the well is awaiting completion and testing of several zones which have potential for both oil and gas. However, F-Cross did not meet the requirements in the agreement and in late March the option to acquire an interest in additional acreage expired, leaving F-Cross with rights only in the section in which it drilled the well.
During 2006, the Company drilled one well and participated in the drilling of a second well, neither of which proved economic quantities of oil or gas, and expensed the $53,000 and $1,018,000 of drilling costs in 2007 and 2006, respectively. The Company’s initial well in Blaine County, Montana in January 2006 hit the target Lodgepole reef, but the reef had been flushed with fresh water. Several other formations were tested and while gas was encountered, the well did not contain economic quantities of oil or gas. The Company expensed $800,000 in drilling costs related to this well in 2006. This well was abandoned by the Company.
The Company also participated in and acted as operator in a twin well to the only known well to produce from the Lodgepole in Montana. The targeted Lodgepole reef contained oil, but not in sufficient quantities to be economical for the Company to develop. Likewise, an uphole test of the Mission Canyon Formation returned oil, but not in sufficient quantities to be economical for the Company to develop. The Company’s participation costs in the twin well were approximately $245,000, which was expensed in the fourth quarter of 2006. The total cost of the well was approximately $1,360,000. There are approximately $115,000 in unpaid expenses related to this well that are collectively the responsibility of the various partners. This amount is not reflected as a liability in the accompanying financial statements. This well was abandoned.
Montana Leases
The Company’s primary presence in Montana is in Valley County, where it holds leases covering approximately 114,832 net acres (87,415 net acres after approximately 27,417 net acres expired in March 2009), which are the remaining unexpired leases from those leases the Company acquired in three separate acquisitions between July 2005 and February 2006. The leases acquired in those acquisitions are contiguous to each other and are referred to collectively as “the Valley County Leases.”
2. Unproved Oil, Gas and Mineral Properties (Cont'd)
The first acquisition of the Valley County Leases was in July 2005, when the Company acquired the rights to drill two 6,500 foot wells to test Mississippian Lodgepole reefs in Valley County, in northeast Montana for a one time fee of $50,000 from an entity controlled by one of the Company’s Directors. That acquisition included a small amount of acreage and the option to drill fifty additional prospects in the Valley County area.
The second acquisition of the Valley County Leases was in November 2005, when the Company acquired a group of oil and gas lease rights to approximately 109,423 net acres in eastern Montana for $1,568,000 from EOG Resources, Inc. and Great Northern Gas Company. These leases are subject to various overriding royalty interests to others ranging up to 19.5%. These leases expire in years from 2007 to 2014.
The final acquisition of acreage within the Valley County Leases was in February 2006, when the Company acquired additional oil and gas leases in eastern Montana covering 27,740 net acres contiguous to its existing Montana leases. These leases were acquired from the Bureau of Land Management and United States Department of the Interior.
The Company borrowed $126,000 in May 2007 to pay its lease obligations that were due in June 2007. The note required the loan to be repaid prior to the Company spudding the first well on any of the approximately 42,000 acres its leases covered by the loan agreement. Coastal assigned a 5% overriding royalty interest (before all expenses) in 8/8ths of the oil or natural gas produced from those Valley County Montana leases to the lender. The loan was repaid on October 15, 2007, prior to the spudding of the first well on the acreage, out of the money advanced by Western Standard to cover lease rentals under their agreement with the Company.
North Dakota Leases
In July 2005, the Company acquired leases to the deeper rights in approximately 21,688 net acres in and near Slope County, North Dakota for a one time fee of $50,000 from an entity controlled by one of the Company’s Directors and the Company has invested some additional funds to geochemically test and high-grade these and other prospects on the leases. Since that time, some of the leases have expired and the Company currently holds leases on approximately 8,748 gross and 8,510 net acres in North Dakota. The Company is obligated to drill a test well on the original leases totaling 7,031.08 acres before June 1, 2009, and has the option to drill the remaining Lodgepole Reef prospects on these leases. The Company had intended to team with other entities to share the cost of the initial 9,700 foot test well, the total estimated drilling cost of which is estimated to be $1,500,000, however, it is unlikely that the Company will be able to identify and contract with a team prospect prior to the expiration date. The leases making up the remaining acreage were leased by the Company and have no obligation associated with them. The Company is actively seeking funding sufficient to allow it to explore its lease on its own.
In an effort to explore the North Dakota leases, in December of 2008 the Company entered a new farm-out agreement with Western Standard. Under the agreement, the Company assigned leases over four of its high-graded Lodgepole Reef prospects to Western Standard in return for $80,000. The Company received $40,000 in November 2007, $25,000 in February 2008 and received the other $15,000 in April of 2008, which was recorded as a reduction in capitalized petroleum lease costs. The Company will also retain a back-in working interest of 20% in the leases after payout. Oil For America has agreed to waive the drilling obligation on these four prospects. The Company still retains additional Lodgepole reef prospects on its North Dakota leases that are not covered by this farm-out agreement.
(Intentionally left blank.)
3. Common Stock
The Company's Bye-Law No. 21 provides that any matter to be voted upon must be approved not only by a majority of the shares voted at such meeting, but also by a majority in number of the shareholders present in person or by proxy and entitled to vote thereon.
The following represents shares issued upon sales of common stock:
The following represents shares issued upon exercise of stock options:
4. Stock Option Plans
At December 31, 2008, the Company maintains two stock-based employee compensation plans.
During 1995, the Company adopted a Stock Option Plan covering 1,000,000 shares of the Company’s common stock. In July 2005, the Company issued an option to its president to acquire 50,000 shares of the Company’s common stock at a price of $.15 per share under the Company’s stock option plan. The option expires in ten years and was fully vested when issued. The Company determined the fair value of the stock did not exceed the exercise price on the date of issue and no expense was recorded in 2005.
Unexercised options that existed prior to the 2005 Agreement with the State of Florida were terminated by the Agreement or the releases exchanged during the process of closing that Agreement.
In December 2005, the Company issued options to its directors to acquire 200,000 shares of the Company’s common stock at a price of $.15 per share. The option expires in December 2015 and was fully vested when issued. The Company determined the fair value of the stock did not exceed the exercise price on the date of issue.
During 2005, the Company adopted a Stock Option Plan covering 2,300,000 shares of the Company’s common stock. In September 2005, the Company issued an option to its president to acquire 250,000 shares of the Company’s common stock at a price of $.20 per share under the Company’s stock option plan, subject to the approval of the Plan by shareholders. The Plan was approved at the shareholders meeting on December 9, 2005. The option expires in ten years and was fully vested when issued. The Company determined the fair value of the stock did not exceed the exercise price on the date of issue.
Effective January 1, 2006, the Company adopted SFAS No. 123 (Revised 2004), Share-Based Payments, which requires companies to expense stock options and other share-based payments. The Company did not issue any stock options or share-based payments in 2007 or in 2008.
The following table summarizes employee stock option activity:
4. Stock Option Plans (Cont'd)
Summary of Employee Options Outstanding at December 31, 2008
The weighted-average remaining contractual life of the outstanding stock options at December 31, 2008, and 2007 was 7 years and 8 years, respectively.
Nonqualified Stock Options
In July 2005, the Company issued an option to its legal counsel to acquire 25,000 shares of the Company’s common stock at a price of $.15 per share. The option expires in July 2015 and was fully vested when issued. The market value of the stock equaled the exercise price on the date of issue.
A summary of non-employee option activity follows:
Effective January 1, 2006, the Company adopted SFAS No. 123 (Revised 2004), Share-Based Payments, which requires companies to expense stock options and other share-based payments. The Company did not issue any stock options or share-based payments to non-employees in 2006 or in 2007.
The following table summarizes information about non-employee stock options:
Summary of Non Employee Options Outstanding at December 31, 2008
5. Income taxes
The Company is organized under the laws of Bermuda. Bermuda currently imposes no taxes on corporate income or capital gains outside of Bermuda. The Company’s subsidiary is a U.S. corporation and is subject to U.S. income tax and files income tax returns in the U.S. and the State of Florida. For 2008 and 2007, the subsidiary has net taxable loss. The subsidiary will have approximately $10,000,000 in net operating losses to carry forward to 2009. The remaining net operating loss carry forwards expire in periods from 2009 through 2028 as follows: $62,000 in 2009, $571,000 in 2010, $955,000 in 2011, $1,281,000 in 2012, $757,000 in 2018, $622,000 in 2019, $749,000 in 2020, $1,884,000 in 2021, $1,693,000 in 2022, $132,000 in 2023, $57,000 in 2024, $1,434,000 in 2026, $195,000 in 2027, and $90,000 in 2028. For financial reporting purposes, a valuation allowance has been recognized to offset the deferred tax assets relating to those carry forwards.
Significant components of the Company’s deferred tax assets were as follows:
Components of the income tax provision for the years ended December 31, are as follows:
6. Related party transactions
Oil and Gas Exploration Activities
Pursuant to a written agreement with respect to the Valley County Leases, the Company uses an entity controlled by an individual who is a shareholder, officer and director of the Company to perform geotechnical analysis of potential drilling sites at a cost of $1,000 per site. The Company capitalized $2,000 paid to this entity for the year ended December 31, 2007 and made no such payments for the year ending December 31, 2008.
Services
The Company expensed $144,000 and $144,000 in fees by Angerer & Angerer in 2008 and 2007, respectively. The Company owes $240,000 to Angerer & Angerer at December 31, 2008. Robert Angerer, Sr. was elected a director of Coastal Caribbean and of Coastal Petroleum on January 30, 2003 and re-elected a Vice President of Coastal Caribbean and Coastal Petroleum in December 2005.
The Company expensed $8,193 and $16,062 for legal fees by the law firm of Igler & Dougherty, PA, during 2008 and 2007, respectively. The Company owed Igler & Dougherty, PA $1,625 at December 31, 2008. Mr. Herbert D. Haughton, a shareholder of the firm, was elected a director of Coastal Caribbean and of Coastal Petroleum in December 2005.
7. Concentrations of credit risk
All demand and certificate of deposits are held by commercial banks. The Company has no policy requiring collateral or other security to support its deposits, although all demand and certificate of deposits with banks are federally insured up to $250,000 under FDIC protection. Demand deposit bank balances totaled $752 and $44,096 at December 31, 2008 and 2007, respectively. Certificate of deposit balances were $84,765 and $135,364 at December 31, 2008 and 2007, respectively.
Item 9.
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None
Item 9A.
Item 9A. Controls and Procedures
a.
Management’s annual report on internal control over financial reporting.
1. Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed to provide reasonable assurance that assets are safeguarded against loss from unauthorized use or disposition, transactions are executed in accordance with appropriate management authorization and accounting records are reliable for the preparation of financial statements in accordance with generally accepted accounting principles.
2. Internal control over financial reporting is a process tailored to the Company’s unique circumstances, designed under the supervision of the Company's Chief Executive and Chief Financial Officer, and effected by the Company's Board of Directors, its consultants and other personnel, taking into account the small size of the Company, small number of employees and others involved in the Company’s finances. The process uses a system of checks and balances to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
· pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company's assets and the review of those transactions and dispositions by the Company’s compliance officer;
· provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that the Company's receipts and expenditures are being made only in accordance with authorizations of management or the Company's Board of Directors; and
· provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material adverse effect on the Company's financial statements.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control - Integrated Framework.
3. As required by Rule 13a-15(b) under the Exchange Act, management carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report. Based on that assessment, management believes that, as of December 31, 2008, the Company’s internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f), is effective based on the COSO criteria.
4. This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.
b.
Changes in internal controls. The Company made no changes in its internal control over financial reporting that occurred during the Company’s fourth fiscal quarter that has materially affected, or which is reasonably likely to materially affect the Company’s internal control over financial reporting.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Company
Directors
As of December 31, 2008, the board of directors included three members, two of whom, Mr. Ware and Mr. Angerer, also serve as executive officers. In October of 2008, Directors Anthony Randazzo and Matthew Cannon resigned, citing personal reasons. Their positions have not been filled and the board will remain divided into three classes, with each class serving a term of office of three years or until such time as their successors are elected, qualified, and assume office. One class currently has no directors. The Company has not held an annual meeting since the annual meeting held in December 2005 due to the high cost of holding such a meeting. Therefore, the directors whose terms expired at the annual meetings to be held in 2007 and 2008 continue to serve until their successors are elected and assume office.
Director
Other Offices Held
Age and Business Experience For the
Name
Since
With the Company
Past Five Years
Directors With Three Year Terms Expiring at the 2008 Annual Meeting:
Phillip W. Ware
President, Chief
Executive Officer and
Principal
Accounting Officer
Mr. Ware, age 59, has been employed by Coastal Petroleum Company since 1976. He has served as President of Coastal Petroleum since April 1985. Mr. Ware is a 1975 graduate of the University of Florida and is a professional geologist registered with the State of Florida.
Robert J. Angerer, Sr.*
Vice President and
Chairman of the
Board
Mr. Angerer, age 62, is a partner in Oil For America, an oil exploration business formed in 2002, with operations primarily in North Dakota and Montana. He is a lawyer and an engineer and has been a member of the Florida Bar since 1974. He has been a partner in the Tallahassee law firm of Angerer & Angerer since 1994. He is a graduate of the University of Michigan and of Florida State University College of Law. He has served as a director of Coastal Petroleum since 2003.
Directors With Two Year Terms Expiring at the 2007 Annual Meeting
Herbert D. Haughton*
None
Mr. Haughton, age 67, is a banking, corporate and securities lawyer. He is a shareholder in the Tallahassee, Florida law firm of Igler & Dougherty, PA, where he has practiced law since 1994, following his admission to the Florida Bar. Prior to entering the practice of law, Mr. Haughton spent over 30 years in the banking industry serving as president and chief executive officer of three different community banks in Florida from 1977 to 1991. He is a graduate of Cleary University and Florida State University College of Law.
* Members of the Bord of Directors Compensation Committee.
Executive Officers
Phillip W. Ware has been President of Coastal Petroleum and Vice President of Coastal Caribbean for many years and became President of Coastal Caribbean effective March 1, 2003, and Robert J. Angerer, Sr., became a director of Coastal Caribbean on January 30, 2003 and Vice President of Coastal Caribbean on February 27, 2003. Effective August 18, 2005, Mr. Ware was appointed Principle Accounting Officer.
Officers of Coastal Caribbean are elected annually by the board and report directly to it.
Only Mr. Ware received direct compensation for his services as an officer of Coastal Caribbean or Coastal Petroleum. During 2008, all $125,000 of Mr. Ware’s compensation for his services was accrued. Mr. Ware devotes 100% of his professional time to the business and affairs of Coastal Caribbean and Coastal Petroleum. The other executive officer devotes a significant portion of his professional time as an officer on behalf of the Companies.
The business experience described for each director or executive officer above covers the past five years.
We are not aware of any arrangements or understandings between any of the individuals named above and any other person by which any of the individuals named above was selected as a director and/or executive officer. We are not aware of any family relationship among the officers and directors of Coastal Caribbean or its subsidiary except for the father and son relationship between Mr. Angerer, Sr. and Robert J. Angerer, Jr., who serves as the Company’s Secretary. Neither Robert J. Angerer, Sr. or Robert J. Angerer, Jr. are paid a salary or other compensation by the Company for this service as a Company officer.
Compliance with Section 16(a) of the Securities Exchange Act of 1934
Section 16(a) of the Securities Exchange Act of 1934 requires the Company's executive officers, directors and persons who beneficially own more than 10% of the Company's Common Stock to file initial reports of beneficial ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission (the "SEC"). Such persons are required by the SEC regulations to furnish the Company with copies of all Section 16(a) forms filed by such persons. Based solely on its copies of forms received by it, or written representations from certain reporting persons that no Form 5's were required for those persons, the Company believes that during the just completed fiscal year, its executive officers, directors, and greater than 10% beneficial owners compiled with all applicable filing requirements.
Code of Ethics
The Company has adopted a Code of Ethics applicable to principle executive and financial officers. The Code of Ethics is posted on the Company’s website at www.coastalcarib.com and may be reviewed by following the link entitled “Corporate Governance Materials.”
Item 11.
Item 11. Executive Compensation
Compensation Discussion and Analysis
Compensation Philosophy
The Company’s executive compensation program reflects the Company’s philosophy that executive’s compensation should be structured so as to closely align executives’ interests with the interests of our shareholders. The primary objectives of the Company in determining compensation are to emphasize operating performance criteria that enhance shareholder value and to establish and maintain a competitive executive compensation program that enables the Company to retain and motivate a highly qualified executive who will contribute to the long-term success of the Company. When used in this Compensation Discussion and Analysis section, the term “named executive officer” means the person listed in the Summary Compensation Table.
Consistent with this philosophy, we seek to provide compensation for the named executive officer that is similar to comparable companies in the oil and gas industry. In making these determinations, we annually review each compensation component and compare it to market reference points. The application of our compensation philosophy to our named executive officer is described below in this Compensation Discussion and Analysis section.
Executive Compensation Program Design
The objective of the Company and the Compensation Committee is to attract, retain and motivate the most highly qualified executive officer who will contribute to the Company’s goals by consistently delivering exceptional performance while working within the annual budget of a development stage Company. In order to accomplish the Company’s goals, we believe compensation paid to the executive officer should be designed around a combination of a competitive based salary combined with performance-based pay including equity-based or other incentives which thereby align the interest of our executive officer with those of the Company’s shareholders.
Base salary constituted nearly all of the compensation package of the indicated named executive officer during the year ended December 31, 2008.
At the request of the Compensation Committee, our compensation program is reviewed on an annual basis to ensure it meets the objectives of our compensation program and is benchmarked with the market. Prior compensation from the Company, such as gains from previously awarded stock options, is not generally taken into account in setting other elements of compensation, such as base pay and long-term incentive awards. We believe that our executive officer should be fairly compensated each year relative to market pay levels of our peer groups and internal equity within the Company.
Compensation Program Benchmarking
The Compensation Committee endeavors to conduct its review on an annual basis for the named executive officer to ensure that our compensation program works as designed and intended. This review by the Compensation Committee also facilitates discussion among the members of the Compensation Committee regarding our compensation program.
Compensation Program Overview
Following is an overview of the principal components of our compensation program:
How Amounts for Compensation Components are Determined
In addition to the information provided above, following are other details on specific compensation components for 2008:
2008 Base Salary. Base salary level of the named executive officer is determined based on a combination of factors, including our compensation philosophy, market compensation data, competition for key executive talent, the named executive officer’s experience, leadership, achievement of specified business objectives and contribution to the Company’s success, the Company’s overall annual budget for merit increases and the named executive officer’s individual performance. In the Compensation Committee’s first meeting of each year, the Compensation Committee conducts an annual review of the base salary of our named executive officer by taking into account these factors.
The base salary of the named executive officer did not increase during 2008 based upon the factors set out above. The Compensation Committee focused on the Company’s annual budget and the beginning of new operations in an effort to establish production and revenue for the Company.
2008 Long-Term Incentives. The Company has in the past provided long-term incentives. Primarily this has been done through the issuance of stock options, however there is no set program or requirements for issuance of the stock options. Instead, stock options may be issued at the discretion of the Compensation Committee in conjunction with the Board of Directors.
In addition to our philosophy, internal equity, current share price, and individual performance during the prior year are considered. We do not target long-term incentive opportunities to be a particular percentage of total compensation. The Compensation Committee did not grant any stock options in 2008 to any individuals (including our Chief Executive Officer).
Another long-term incentive used in the oil and gas industry is the granting of overriding interest in wells to be drilled. On June 22, 2005, the Company approved of its subsidiary granting such an incentive to Mr. Ware and that incentive was granted as a 1% overriding interest in any well that he recommends that is drilled by the Company or its subsidiary Coastal Petroleum. No payments under this incentive plan were earned or paid during 2008.
Retirement and Other Benefits
We currently do not offer retirement programs within the Company that are intended to supplement the employee’s personal savings and social security. However, the Company contributes to the SEP-IRA of the named executive employee. The Company believes that this contribution assists the Company in maintaining a competitive position in terms of retaining our named executive employee.
Other Benefits
The Company does not provide the named executive officer with perquisites or other personal benefits. The Company does provide healthcare insurance for its named executive officer, which the Company believes assists in maintaining a competitive position in terms of retaining him.
Board Process and Independent Review of Compensation Program
The Compensation Committee is responsible for determining the compensation of our directors and our Chief Executive Officer. In addition, the Compensation Committee is authorized to exercise all the powers granted to it in its charter. The Compensation Committee charter provides that the Compensation Committee will have access to the necessary corporate resources to carry out its charter authority.
For our Chief Executive Officer, the Compensation Committee evaluates and assesses our Chief Executive Officer’s performance related to leadership, financial and operating results, board relations, and other material considerations. These considerations as well as market information concerning compensation for similar positions are then incorporated into the Compensation Committee’s compensation adjustment decisions. Market information is obtained through various sources including reference to materials published by the American Association of Petroleum Geologists (AAPG) annually in their AAPG Explorer. These materials review compensation being paid to geologists holding various degrees and of varying years of experience in oil and gas companies across the country.
The following table sets forth the compensation of the President of the Company, Mr. Ware, who served as our Chief Executive Officer and Principal Financial Officer for the three years ending with 2008. We have determined that Mr. Ware is our only named executive officer pursuant to the applicable rules of the SEC (the “named executive officer”). No other company employee received $100,000 or more in total compensation. Mr. Ware’s current base salary is $125,000.
(Intentionally left blank)
Summary Compensation Table
(1) Annual Cash Bonus Award - Annual incentive awards, which were paid during the year or immediately following the year indicated.
(2) Other Annual Compensation - All additional forms of cash and non-cash compensation paid, awarded or earned, including automobile allowances, 401(k) Plan matching contributions, and club membership costs.
(3) Payment of $89,700 was accrued and not paid in 2007.
(4) Payment of 125,000 was accrued and not paid in 2008.
(5) Payment to SEP-IRA pension plan (2007 and 2008 amounts have been deferred).
The Company does not have a contract with its named executive officer nor does it have a change of control employment agreement which would be effective upon change of control of the Company or in the event of termination of employment.
Stock Options
The Company has not adjusted or amended the exercise price of any stock options during the year end December 31, 2008.
The following table sets forth certain information with respect to outstanding equity awards at December 31, 2008 held by the named executive officer.
Outstanding Equity Awards at Fiscal Year-End
Option Exercises
In March 2008, the Company received $7,500 from the exercise of outstanding stock options for 50,000 shares from Robert J. Angerer, Sr., a vice president and a director of the Company.
Compensation of Directors
The Compensation Committee of our Board sets the compensation of our directors. In determining the appropriate level of compensation for our directors, the Compensation Committee considers the commitment required from our directors in performing their duties on behalf of the Company, as well as comparative information the committee obtains from various sources. Set forth below is a description of the compensation of our directors.
Annual Retainers and Other Fees and Expenses.
We pay our directors an annual retainer of $25,000. There is currently no provision for paying directors additional fees based upon attending meetings, service on a committee, or serving as chair of a committee. We do not regularly compensate directors for their service through stock options, although in the past the Company has issued stock options to Directors. We do reimburse directors for travel, lodging and related expenses they may incur in attending shareholder, Board and committee meetings.
We did not pay our directors in 2008 and accrued $112,500 owed to them at December 31, 2008. Directors fees of $125,000 were also accrued and not paid in 2007. The following table shows the compensation of the Company’s directors for the year ended December 31, 2008.
(Intentionally left blank)
Director Compensation
(1) All fees were accrued but not paid.
Compensation Committee Interlocks and Insider Participation
The Compensation Committee serves with regard to compensation and personnel policies, programs and plans, including management development and succession, and to approve employee compensation and benefit programs. The Compensation Committee’s charter was adopted on December 20, 2005. A copy of the Compensation Committee Charter may be obtained by a written request addressed to Mr. Robert J. Angerer, Jr., Secretary, P.O. Box 10468, Tallahassee, Florida 32302. Members of the Compensation Committee are: Herbert D. Haughton and Robert J. Angerer, Sr.
Compensation Committee Report
To the Shareholders of
Coastal Caribbean Oils & Minerals, Ltd.:
The Compensation Committee has reviewed and discussed with management of the Company the Compensation Discussion and Analysis included in this annual report on Form 10-K. Based on such review and discussion, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.
March 27,
COMPENSATION COMMITTEE
Herbert D. Haughton, Chair
Robert J. Angerer, Sr.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Security Ownership of Certain Beneficial Owners
As of December 31, 2008, Mr. Robert J. Angerer, Sr. owned 1,583,757 shares, or 3.42% of our common stock and his son, Mr. Robert J. Angerer, Jr., owned 1,016,914 shares, or 2.19% of our common stock. Mr. Angerer, Sr. disclaims beneficial ownership of any shares owned by his son.
As of March 27, 2009, no persons or apparent groups of persons are known by management to own beneficially five percent or more of the Company’s outstanding shares.
Security Ownership of Management
The following table sets forth information as to the number of shares of the Company's common stock owned beneficially at December 31, 2008, by each director of the Company and by all directors and executive officers as a group:
EQUITY COMPENSATION PLAN INFORMATION
The following table provides information about the Company’s common stock that may be issued upon the exercise of options and rights under the Company’s 1995 Stock Option Plan and the Company’s 2005 Employee’s Incentive Stock Option Plan as of December 31, 2008
(1) 1995 Stock Option Plan
(2) 2005 Employee’s Incentive Stock Option Plan
(3) Options to acquire 100,000 shares of the Company’s common stock under the 1995 Stock Option Plan granted to former directors Cannon and Randazzo expired one month after their resignation and were returned to the options available to be issued.
The Company’s 1995 Stock Option Plan was adopted by the Board of Directors of the Company in March 1995. 1,000,000 shares of the Company's common stock were authorized for issuance under the terms of the plan. Options under the plan may be granted only to directors, officers, key employees of, and consultants and consulting firms to, (i) the Company, (ii) subsidiary corporations of the Company from time to time and any business entity in which the Company from time to time has a substantial interest, who, in the sole opinion of the Committee of the Board administering the Plan, are responsible for the management and/or growth of all or part of the business of the Company. The exercise price of each option to be granted under the plan shall not be less than the fair market value of the stock subject to the option on the date of grant of the option.
The Company’s 2005 Employees’ Stock Option and Limited Rights Plan (“Employees’ Plan”) was adopted by the Board on September 27, 2005, for the benefit of officers and other key employees of Coastal and Coastal Caribbean. The Plan was approved by the shareholders at the Annual General Meeting held on December 9, 2005. The Employees’ Plan provides for 2,300,000 shares of Coastal common stock to be reserved for future issuance pursuant to the exercise of stock options. This represents 5% of the total number of shares of the Company’s outstanding common stock. Employees of Coastal or Coastal Petroleum may be granted options to purchase shares of common stock, as determined by the Board in its sole discretion.
Options granted under the Program will be “incentive stock options” within the meaning of section 422A of the Internal Revenue Code of 1986, as amended, which are designed to result in beneficial tax treatment to the employee but no tax deduction to Coastal. The per share exercise price at which the shares of common stock may be purchased upon exercise of a granted option will be equal to or greater than the Fair Market Value of a share of common stock as of the date of grant. Fair Market Value of a share of common stock is defined in the Employees’ Plan. At no time will Coastal have total cumulative stock options outstanding to acquire more than 15% of the outstanding common stock of Coastal under all of its plans.
Item 13.
Item 13. Certain Relationships and Related Transactions
Angerer & Angerer
The law firm of Angerer & Angerer, Tallahassee, Florida, has been litigation counsel to the Company for more than twenty-five years and continues to serve the Company in that capacity as well as others including general counsel services, management services, public relations, shareholder relations and representing the Company before state and federal agencies for permitting. Mr. Robert J. Angerer, Sr., a partner of the firm, was elected a director of Coastal Caribbean and of Coastal Petroleum on January 30, 2003, and a Vice President of Coastal Caribbean and Coastal Petroleum on February 28, 2003. During 2008 and 2007, Angerer & Angerer billed Coastal Petroleum $144,000 and $144,000 respectively for legal fees.
Robert J. Angerer, Sr.
On July 15, 2005 Coastal Petroleum acquired a lease and the rights to drill two 5,100 foot wells to test a Mississippian Lodgepole reef in Valley County, in northeast Montana. Coastal Petroleum acquired these rights for $50,000 from Oil For America, a partnership in which Robert J. Angerer, Sr. is a partner. Included in the agreement is the right to drill additional prospects in the Valley County area.
Coastal Petroleum also acquired leases from Oil For America to the deeper rights in approximately 21,688 net acres in and near Slope County, North Dakota for an additional $50,000. The Company has the option to drill the remaining Lodgepole reef prospects on these leases.
The leases were acquired on terms and under circumstances that are substantially the same or at least as favorable as those prevailing at the time for comparable transactions with or involving other non-affiliated companies.
Igler & Dougherty, PA
The law firm of Igler & Dougherty, PA, Tallahassee, Florida, has been SEC counsel to the Company for almost five years. Mr. Herbert D. Haughton, a shareholder of the firm, was elected a director of Coastal Caribbean and of Coastal Petroleum in December 2005. During 2008 and 2007, Igler & Dougherty billed Coastal Petroleum $8,193 and $16,062, respectively for legal fees.
Item 14.
Item 14. Principal Accountant Fees and Services
Baumann, Raymondo and Company, P.A. audited the Company’s financial statements for 2008 and 2007 and performed the reviews for 2008 and 2007. Fees related to services performed by Baumann, Raymondo and Company, P.A. in 2008 and 2007 were as follows:
(1)
Audit fees represent fees for professional services provided in connection with the audit of our financial statements and review of our quarterly financial statements. The Audit Committee must pre-approve audit related and non-audit services not prohibited by law to be performed by the Companies independent auditors. Since their appointment on December 9, 2005, directors Matthew D. Cannon and Anthony F. Randazzo served as the members of the Audit Committee until their resignation in October of 2008. With those resignations, there are currently not enough independent directors to comprise an Audit Committee, so since that time the entire Board of Directors has carried out the duties that would otherwise be carried out by an Audit Committee. The Audit Committee, or the Board of Directors after October 2008, pre-approved all audit related and non-audit services in 2008 and 2007.
The Board of Directors has reviewed Coastal Caribbean’s audited financial statements as of, and for, the fiscal year ended December 31, 2008, and met with both management and Coastal Caribbean’s independent auditors to discuss those financial statements. Management has represented to the Audit Committee that the financial statements were prepared in accordance with accounting principles generally accepted in the United States of America.
The Audit Committee has received from, and discussed with Baumann, Raymondo & Company, PA, the written disclosure and the letter required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent accountant’s communications with the audit committee concerning independence. These items relate to that firm’s independence from Coastal Caribbean. The Board of Directors has also discussed with Baumann, Raymondo & Company any matters required to be discussed by Statement on Auditing Standards No. 61 (Communication with Audit Committees).
Based on the reviews and discussions referred to above, the Board approved the inclusion of Coastal Caribbean’s audited financial statements in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, and filed with the Securities and Exchange Commission.
(2)
Tax fees principally included tax advice, tax planning and tax return preparation.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
Financial Statements
The financial statements listed below and included under Item 8 above are filed as part of this report.
Financial Statement Schedules
All schedules have been omitted since the required information is not present or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and the notes thereto.
Exhibits
The following exhibits are filed as part of this report:
10.
Material contracts.
(g)
Stock Option Plan adopted March 7, 1995 filed as Exhibit 4A to form S-8 dated July 28, 1995 (File Number 001-04668) is incorporated herein by reference.
(h)
Memorandum of Settlement dated June 1, 2005 between Coastal Petroleum Company, et al. and the State of Florida filed as Exhibit 10(h) to form 10K-A dated July 27, 2005 (File Number 001-04668) is incorporated herein by reference.
(i)
Incentive Stock Option Plan adopted September 30, 2005 and approved by the shareholders on December 9, 2005 filed as Appendix A to form DEF 14A dated November 3, 2005 (File Number 001-04668) is incorporated herein by reference.
(j)
Code of Ethics applicable to principle executive and financial officers adopted December 20, 2005 filed as Exhibit 10(j) to form 10K dated March 8, 2006 (File Number 001-04668) is incorporated herein by reference.
21.
Subsidiaries of the registrant.
The Company has one subsidiary, Coastal Petroleum Company, a Florida corporation which is 100 % owned.
23.
Consent of experts and counsel.
23.1
Consent of Baumann, Raymondo & Company PA
31.1
Certification of Chief Executive Officer and Principal Financial Officer Required by Rule 13a-14(a)-15d-14(a) under the Exchange Act
32.1
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by Phillip W. Ware.
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.
Dated: March 27, 2008
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
INDEX TO EXHIBITS
Exhibit No.
23.1
Consent of Baumann, Raymondo & Company, PA
31.1
Certification pursuant to Rule 13a-14 by Phillip W. Ware
32.1
Certification pursuant to Section 906 by Phillip W. Ware