ITEM 1. BUSINESS
Introduction
Everflow Eastern Partners, L.P. (the "Company"), a Delaware limited partnership, engages in the business of oil and gas exploration and development. The Company was formed for the purpose of consolidating the business and oil and gas properties of Everflow Eastern, Inc., an Ohio corporation ("EEI"), and the oil and gas properties owned by certain limited partnerships and working interest programs managed or operated by EEI (the "Programs"). Everflow Management Limited, LLC (the "General Partner"), an Ohio limited liability company, is the general partner of the Company.
Exchange Offer. The Company made an offer (the "Exchange Offer") to acquire the common shares of EEI (the "EEI Shares") and the interests of investors in the Programs (collectively the "Interests") in exchange for units of limited partnership interest (the "Units"). The Exchange Offer was made pursuant to a Registration Statement on Form S-1 declared effective by the Securities and Exchange Commission on December 19, 1990 (the "Registration Statement") and the Prospectus dated December 19, 1990, as filed with the Commission pursuant to Rule 424(b).
The Exchange Offer terminated on February 15, 1991 and holders of Interests with an aggregate value (as determined by the Company for purposes of the Exchange Offer) of $66,996,249 accepted the Exchange Offer and tendered their Interests. Effective on such date, the Company acquired such Interests, which included partnership interests and working interests in the Programs, and all of the outstanding EEI Shares. Of the Interests tendered in the Exchange Offer, $28,565,244 was represented by the EEI Shares and $38,431,005 by the remaining Interests.
The parties who accepted the Exchange Offer and tendered their Interests received an aggregate of 6,632,464 Units. Everflow Management Company, a predecessor of the General Partner of the Company, contributed Interests with an aggregate Exchange Value of $670,980 in exchange for a 1% interest in the Company.
The Company. The Company was organized in September 1990. The principal executive offices of the Company, the General Partner and EEI are located at 585 West Main Street, Canfield, Ohio 44406 (telephone number 330-533-2692).
General
This Annual Report on Form 10-K contains forward-looking statements which involve risks and uncertainties. The Company's actual results may differ significantly from the results discussed in the forward-looking statements. All statements that address operating performance, events or developments that the Company anticipates will occur in the future,
including statements related to future revenue, profits, expenses, and income or statements expressing general optimism about future results, are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended ("Exchange Act"). In addition, words such as "expects," "anticipates," "intends," "plans," "believes," "estimates," variations of such words, and similar expressions are intended to identify forward-looking statements. Forward-looking statements are subject to the safe harbors created in the Exchange Act.
Factors that may cause differences in the Company's actual results versus results discussed in forward-looking statements include, but are not limited to, the competition within the oil and gas industry, the price of oil and gas in the Appalachian Basin area, the number of Units tendered pursuant to the Repurchase Right and the ability to locate productive oil and gas prospects for development by the Company. The Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
Description of the Business
General. The Company has participated on an on-going basis in the acquisition and development of undeveloped oil and gas properties and has pursued the acquisition of producing oil and gas properties.
Subsidiaries. The Company has two subsidiaries. EEI was organized as an Ohio corporation in February 1979 and, since the consummation of the Exchange Offer, has been a wholly-owned subsidiary of the Company. EEI is engaged in the business of drilling, developing and operating oil and gas properties and maintains a leasehold inventory from which the Company selects prospects for development.
A-1 Storage of Canfield, Ltd. ("A-1 Storage") was organized as an Ohio limited liability company in late 1995 and is 99% owned by the Company and 1% owned by EEI. A-1 Storage's business includes leasing of office space to the Company as well as rental of storage units to non-affiliated parties.
Current Operations. The properties of the Company consist in large part of fractional undivided working interests in properties containing Proved Reserves of oil and gas located in the Appalachian Basin region of Ohio and Pennsylvania. Approximately 91% of the estimated total future cash inflows related to the Company's oil and gas reserves as of December 31, 2004 are attributable to natural gas reserves. The substantial majority of such properties are located in Ohio and consist primarily of proved producing properties with established production histories.
The Company's operations since February 1991 primarily involve the production and sale of oil and gas and the drilling and development of 324 (net) wells. The Company serves as the operator of approximately 75% of the gross wells and 85% of the net wells which comprise the Company's properties.
The Company expects to hold its producing properties until the oil and gas reserves underlying such properties are substantially depleted. However, the Company may from time to time sell any of its producing or other properties or leasehold interests if the Company believes that such sale would be in its best interest.
Business Plan. The Company continually evaluates whether the Company can develop oil and gas properties at historical levels given the current costs of drilling and development activities, the current prices of oil and gas, and the Company's experience with regard to finding oil and gas in commercially productive quantities. With the exception of 2004 when activity was higher than recent years, the Company has decreased its level of activity in the development of oil and gas properties compared with historical levels. Management of the Company has from time to time explored and evaluated the possible sale of the Company. The Company intends to continue to evaluate this and other alternatives to maximize value for its Unitholders. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS."
Acquisition of Prospects. The Company, through its wholly-owned subsidiary EEI, maintains a leasehold inventory from which the General Partner will select oil and gas prospects for development by the Company. EEI makes additions to such leasehold inventory on an on-going basis. The Company may also acquire leases from third parties. Prior to 2000, EEI generated approximately 90% of the prospects which were drilled. Beginning in 2000, the Company began generating fewer prospects and has participated in more joint ventures with other operators. EEI's current leasehold inventory consists of approximately 12 prospects in various stages of maturity representing approximately 360 net acres under lease.
In choosing oil and gas prospects for the Company, the General Partner does not attempt to manage the risks of drilling through a policy of selecting diverse prospects in various geographic areas or with the potential of oil and gas production from different geological formations. Rather, substantially all prospects are expected to be located in the Appalachian Basin of Ohio (and, to a lesser extent, Pennsylvania) and to be drilled primarily to the Clinton/Medina Sands geological formation or closely related oil and gas formations in such area.
Acquisition of Producing Properties. As a potential means of increasing its reserve base, the Company expects to evaluate opportunities which it may be presented with to acquire oil and gas producing properties from third parties in addition to its ongoing leasehold acquisition and development activities. The Company has acquired a limited amount of producing oil and gas properties.
The Company will continue to evaluate properties for acquisition. Such properties may include, in addition to working interests, royalty interests, net profit interests and production payments, other forms of direct or indirect ownership interests in oil and gas production, and properties associated with the production of oil and gas. The Company also may acquire general or limited partner interests in general or limited partnerships and interests in joint ventures, corporations or other entities that have, or are formed to acquire, explore for or
develop, oil and gas or conduct other activities associated with the ownership of oil and gas production.
Funding for Activities. The Company finances its current operations, including undeveloped leasehold acquisition activities, through cash generated from operations. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Results of Operations."
The Company is permitted to incur indebtedness for any partnership purpose. It is currently anticipated that any such indebtedness will consist primarily of borrowings from commercial banks. The Company and EEI have had no borrowings during 2004 and no principal indebtedness was outstanding as of March 20, 2005. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources."
Although the Partnership Agreement does not contain any specific restrictions on borrowings, the Company has no specific plans to borrow for the acquisition of producing oil and gas properties. The Company expects that borrowings may be made to enable it to repurchase any Units tendered in connection with the Repurchase Right. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources."
The Company has a substantial amount of oil and gas reserves. The Company generally would not expect to borrow funds, from whatever source, in excess of 40% of its total Proved Reserves (as determined using the Company's Standardized Measure of Discounted Future Net Cash Flows), although there can be no assurance that circumstances would not lead to the necessity of borrowings in excess of this amount. Based upon its current business plan, management has no present intention to have the Company borrow in excess of this amount. The Company has estimated Proved and Proved Developed Reserves, determined as of December 31, 2004, which aggregate $119,089,000 (Standardized Measure of Discounted Future Net Cash Flows) with no bank debt outstanding as of December 31, 2004.
Marketing
The ability of the Company to market oil and gas found in and produced on its properties will depend on many factors beyond its control, the effect of which cannot be accurately anticipated or predicted. These factors include, among others, the amount of domestic oil and gas production and foreign imports available from other sources, the capacity and proximity of pipelines, governmental regulations, and general market demand.
Oil. Any oil produced from the properties can be sold at the prevailing field price to one or more of a number of unaffiliated purchasers in the area. Generally, purchase contracts for the sale of oil are cancelable on 30 days' notice. The price paid by these purchasers is generally an established or "posted" price which is offered to all producers. All posted prices in the areas where the Company's properties are located are generally somewhat lower than the spot market prices, although there have been substantial fluctuations in crude oil prices in recent years.
The price of oil in the Appalachian Basin has ranged from a low of $8.50 per barrel in December 1998 to a high of $53.50 in March 2005. As of March 20, 2005, the posted field price in the Appalachian Basin area, the Company's principal area of operation, was $53.50 per barrel of oil. There can be no assurance that prices will not be subject to continual fluctuations. Future oil prices are difficult to predict because of the impact of worldwide economic trends, supply and demand variables, and such non-economic factors as the political impact on pricing policies by the Organization of Petroleum Exporting Countries ("OPEC") and the possibility of supply interruptions. To the extent the prices that the Company receives for its crude oil production decline or remain at current levels, the Company's revenues from oil production will be reduced accordingly.
Since January 1993, the Company has sold substantially all of its crude oil production to Ergon Oil Purchasing, Inc.
Natural Gas. The deliverability and price of natural gas is subject to various factors affecting the supply and demand of natural gas as well as the effect of federal regulations. Prior to 2000, there had been a surplus of natural gas available for delivery to pipelines and other purchasers. During 2000, decreases in worldwide energy production capability and increases in energy consumption brought about a shortage in natural gas supplies. This resulted in increases in natural gas prices throughout the United States, including the Appalachian Basin. During 2001, lower energy consumption and increased natural gas supplies reduced prices to historical levels. More recently, during 2002, shortages in natural gas supplies once again have resulted from increased energy consumption due to harsh weather conditions. From time to time, especially in summer months, seasonal restrictions on natural gas production have occurred as a result of distribution system restrictions.
Over the ten years prior to 2002, the Company had followed a practice of selling a significant portion of its natural gas pursuant to Intermediate Term Adjustable Price Gas Purchase Agreements (the "East Ohio Contracts") with Dominion Field Services, Inc. and its affiliates ("Dominion") (including The East Ohio Gas Company). Pursuant to the East Ohio
Contracts and subject to certain restrictions and adjustments, including termination clauses, Dominion was obligated to purchase, and the Company was obligated to sell, all natural gas production from a specified list of wells (the "Contract Wells"). Pricing under the East Ohio Contracts was adjusted annually, up or down, by an amount equal to 80% of the increase or decrease in Dominion's average Gas Cost Recovery ("GCR") rates.
The Company's last remaining East Ohio Contract terminated during 2001 and was replaced by a short-term contracts, which obligate Dominion to purchase, and the Company to sell and deliver certain quantities of natural gas production on a monthly basis throughout the contract periods. A summary of significant gas purchase contracts, including weighted average pricing provisions, with Dominion follows:
The Company also has a short-term contract with Interstate Gas Supply, Inc. ("IGS"), which obligate IGS to purchase, and the Company to sell and deliver certain quantities of natural gas production on a monthly basis throughout the contract periods. A summary of significant gas purchase contracts, including weighted average pricing provisions, with IGS follows:
As detailed above, the price paid for natural gas purchased by Dominion and IGS varies based on quantities committed by the Company from time to time. Natural gas sold under these contracts in excess of the locked in prices are sold at the month's closing price plus basis adjustments, as per the contracts. As of December 31, 2004, natural gas purchased by Dominion covers production from approximately 490 gross wells, while natural gas purchased by IGS covers production from approximately 220 gross wells. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Inflation and Changes in Prices."
For the year ended December 31, 2004, with the exception of Dominion and IGS, which accounted for approximately 52% and 23%, respectively, of the Company's natural gas sales, no one natural gas purchaser has accounted for more than 10% of the Company's gas sales. The Company expects that Dominion and IGS will be the only material natural gas customers for 2005.
Seasonality
During summer months, seasonal restrictions on natural gas production have occurred as a result of distribution system restrictions. These production restrictions, and the nature of the Company's business, result in seasonal fluctuations in the Company's revenue, with the Company receiving more income in the first and fourth quarters of its fiscal year.
Title to Properties
As is customary in the oil and gas industry, the Company performs a limited investigation as to ownership of leasehold acreage at the time of acquisition and conducts a title examination and necessary curative work prior to the commencement of drilling operations on a tract. Title examinations have been performed for substantially all of the producing oil and gas properties owned by the Company with regard to (i) substantial tracts of land forming a portion of such oil and gas properties and (ii) the wellhead location of such properties. The Company believes that title to its properties is acceptable although such properties may be subject to royalty, overriding royalty, carried and other similar interests in contractual arrangements customary in the oil and gas industry. Also, such properties may be subject to liens incident to operating agreements and liens for current taxes not yet due, as well as other comparatively minor encumbrances.
Competition
The oil and gas industry is highly competitive in all its phases. The Company encounters strong competition from major and independent oil companies in acquiring economically desirable prospects as well as in marketing production therefrom and obtaining external financing. Major oil and gas companies, independent concerns, drilling and production purchase programs and individual producers and operators are active bidders for desirable oil and gas properties, as well as the equipment and labor required to operate those properties. Many of the Company's competitors have financial resources, personnel and facilities substantially greater than those of the Company.
The availability of a ready market for the oil and gas production of the Company depends in part on the cost and availability of alternative fuels, the level of consumer demand, the extent of other domestic production of oil and gas, the extent of importation of foreign oil and gas, the cost of and proximity to pipelines and other transportation facilities, regulations by state and federal authorities and the cost of complying with applicable environmental regulations. The volatility of prices for oil and gas and the continued oversupply of domestic natural gas have, at times, resulted in a curtailment in exploration for and development of oil and gas properties.
There is also extensive competition in the market for gas produced by the Company. Decreases in worldwide energy production capability and increases in energy consumption have brought about a shortage in energy supplies recently. This, in turn, has resulted in substantial competition for markets historically served by domestic natural gas resources both with alternate sources of energy, such as residual fuel oil, and among domestic gas suppliers. As a result, at times there has been volatility in oil and gas prices, widespread curtailment of gas production and delays in producing and marketing gas after it is discovered. Changes in government regulations relating to the production, transportation and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry. Generally, these changes have resulted in the abandonment by many pipelines of long-term contracts for the purchase of natural gas, the development by gas producers of their own marketing programs to take advantage of new regulations requiring pipelines to transport gas for
regulated fees, and an increasing tendency to rely on short-term sales contracts priced at spot market prices. See "Marketing" above.
Gas prices, which were once effectively determined by government regulations, are now influenced largely by the effects of competition. Competitors in this market include other producers, gas pipelines and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies.
Regulation of Oil and Gas Industry
The exploration, production and sale of oil and natural gas are subject to numerous state and federal laws and regulations. Such laws and regulations govern a wide variety of matters, including the drilling and spacing of wells, allowable rates of production, marketing, pricing and protection of the environment. Such regulations may restrict the rate at which the Company's wells produce oil and natural gas below the rate at which such wells could produce in the absence of such regulations. In addition, legislation and regulations concerning the oil and gas industry are constantly being reviewed and proposed. Ohio and Pennsylvania, the states in which the Company owns properties and operates, have statutes and regulations governing a number of the matters enumerated above. Compliance with the laws and regulations affecting the oil and gas industry generally increases the Company's costs of doing business and consequently affects its profitability. Inasmuch as such laws and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations.
The interstate transportation and sale for resale of natural gas is regulated by the Federal Energy Regulatory Commission (the "FERC") under the Natural Gas Act of 1938 ("NGA"). The wellhead price of natural gas is also regulated by FERC under the authority of the Natural Gas Policy Act of 1978 ("NGPA"). Subsequently, the Natural Gas Wellhead Decontrol Act of 1989 (the "Decontrol Act") was enacted on July 26, 1989. The Decontrol Act provided for the phasing out of price regulation under the NGPA commencing on the date of enactment and completely eliminated all such gas price regulation on January 1, 1993. In addition, FERC recently has adopted and proposed several rules or orders concerning transportation and marketing of natural gas. The impact of these rules and other regulatory developments on the Company cannot be predicted. It is expected that the Company will sell natural gas produced by its oil and gas properties to a number of purchasers, including various industrial customers, pipeline companies and local public utilities, although the majority will be sold to East Ohio as discussed earlier.
As a result of the NGPA and the Decontrol Act, the Company's gas production is no longer subject to price regulation. Gas which has been removed from price regulation is subject only to that price contractually agreed upon between the producer and purchaser. Under current market conditions, deregulated gas prices under new contracts tend to be substantially lower than most regulated price ceilings originally prescribed by the NGPA. FERC has proposed and enacted several rules or orders concerning transportation and marketing of natural gas. In 1992, the FERC finalized Order 636, a rule pertaining to the restructuring of interstate pipeline services. This rule requires interstate pipelines to unbundle transportation and sales services by
separately pricing the various components of their services, such as supply, gathering, transportation and sales. These pipeline companies are required to provide customers only the specific service desired without regard to the source for the purchase of the gas. Although the Partnership is not an interstate pipeline, it is likely that this regulation may indirectly impact the Partnership by increasing competition in the marketing of natural gas, possibly resulting in an erosion of the premium price historically available for Appalachian natural gas. The impact of these rules and other regulatory developments on the Company cannot be predicted.
Regulation of the production, transportation and sale of oil and gas by federal and state agencies has a significant effect on the Company and its operating results. Certain states, including Ohio and Pennsylvania, have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning the spacing of wells.
Environmental Regulation
The activities of the Company are subject to various federal, state and local laws and regulations designed to protect the environment. The Company does not conduct activities offshore. Operations of the Company on onshore oil properties may generally be liable for clean-up costs to the federal government under the Federal Clean Water Act for up to $50,000,000 for each incident of oil or hazardous pollution substance and for up to $50,000,000 plus response costs under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 ("Superfund") for hazardous substance contamination. Liability is unlimited in cases of willful negligence or misconduct, and there is no limit on liability for environmental clean-up costs or damages with respect to claims by the state or private persons or entities. In addition, the Company is required by the Environmental Protection Agency ("EPA") to prepare and implement spill prevention control and countermeasure plans relating to the possible discharge of oil into navigable waters; and the EPA will further require permits to authorize the discharge of pollutants into navigable waters. State and local permits or approvals may also be needed with respect to waste-water discharges and air pollutant emissions. Violations of environment-related lease conditions or environmental permits can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations. Such enforcement liabilities can result from prosecution by public or private entities.
Various state and governmental agencies are considering, and some have adopted, other laws and regulations regarding environmental protection which could adversely affect the proposed business activities of the Company. The Company cannot predict what effect, if any, current and future regulations may have on the operations of the Company.
In addition, from time to time, prices for either oil or natural gas have been regulated by the federal government, and such price regulation could be reimposed at any time in the future.
Operating Hazards and Uninsured Risks
The Company's oil and gas operations are subject to all operating hazards and risks normally incident to drilling for and producing oil and gas, such as encountering unusual formations and pressures, blow-outs, environmental pollution and personal injury. The Company maintains such insurance coverage as it believes to be appropriate taking into account the size of the Company and its operations. Losses can occur from an uninsurable risk or in amounts in excess of existing insurance coverage. The occurrence of an event which is not insured or not fully insured could have an adverse impact on the Company's revenues and earnings.
In certain instances, the Company may continue to engage in exploration and development operations through drilling programs formed with non-industry investors. In addition, the Company also will conduct a significant portion of its operations with other parties in connection with the drilling operations conducted on properties in which it has an interest. In these arrangements, all joint interest parties, including the Company, may be fully liable for their proportionate share of all costs of such operations. Further, if any joint interest party defaults on its obligations to pay its share of costs, the other joint interest parties may be required to fund the deficiency until, if ever, it can be collected from the defaulting party. As a result of the foregoing or similar oilfield circumstances, the Company could become liable for amounts significantly in excess of amounts originally anticipated to be expended in connection with such operations. In addition, financial difficulty for an operator of oil and gas properties could result in the Company's and other joint interest owners' interests in properties and the wells and equipment located thereon becoming subject to liens and claims of creditors, notwithstanding the fact that non-defaulting joint interest owners and the Company may have previously paid to the operator the amounts necessary to pay their share of such costs and expenses.
Conflicts of Interest
The Partnership Agreement grants the General Partner broad discretionary authority to make decisions on matters such as the Company's acquisition of or participation in a drilling prospect or a producing property. To limit the General Partner's management discretion might prevent it from managing the Company properly. However, because the business activities of the affiliates of the General Partner on the one hand and the Company on the other hand are the same, potential conflicts of interest are likely to exist, and it is not possible to completely mitigate such conflicts.
The Partnership Agreement contains certain restrictions designed to mitigate, to the extent practicable, these conflicts of interest. The agreement restricts, among other things, (i) the cost at which the General Partner or its affiliates may acquire properties from or sell properties to the Company; (ii) loans between the General Partner, its affiliates and the Company, and interest and other charges incurred in connection therewith; and (iii) the use and handling of the Company's funds by the General Partner.
Employees
As of March 20, 2005, the Company had fifteen full-time and three part-time employees. These employees primarily are engaged in the following areas of business operations: two in land and lease acquisition, five in field operations, five in accounting, and six in administration.
Item 2.
Item 2. Properties.
Set forth below is certain information regarding the oil and gas properties of the Company which are located in the Appalachian Basin of Ohio and Western Pennsylvania.
In the following discussion, "gross" refers to the total acres or wells in which the Company has a working interest and "net" refers to gross acres or wells multiplied by the Company's percentage of working interests therein. Because royalty interests held by the Company will not affect the Company's working interests in its properties, neither gross nor net acres or wells reflect such royalty interests.
Proved Reserves.(1) The following table reflects the estimates of the Company's Proved Reserves which are based on the Company's report as of December 31, 2004.
---------- (1) The Company has not determined proved reserves associated with its proved undeveloped acreage which are not deemed significant at December 31, 2004. A reconciliation of the Company's proved reserves is included in the Notes to the Financial Statements.
Standardized Measure of Discounted Future Net Cash Flows.(1) The following table summarizes, as of December 31, 2004, the oil and gas reserves attributable to the oil and gas properties owned by the Company. The determination of the standardized measure of discounted future net cash flows as set forth herein is based on criteria promulgated by the Securities and Exchange Commission, using calculations based solely on Proved Reserves, current unescalated cost and price factors, and discounted to present value at 10%.
---------- (1) See the Notes to the Financial Statements for additional information.
Production. The following table summarizes the net oil and gas production, average sales prices and average production (lifting) costs per equivalent unit of production for the periods indicated.
- ---------- (1) Oil production is converted to MCF equivalents at the rate of 6 MCF per BBL (barrel).
Productive Wells. The following table sets forth the gross and net oil and gas wells of the Company as of December 31, 2004.
- ---------- (1) Oil wells are those wells which generate the majority of their revenues from oil production; gas wells are those wells which generate the majority of their revenues from gas production.
Acreage. The Company had approximately 51,000 gross developed acres and 35,000 net developed acres as of December 31, 2004. Developed acreage is that acreage assignable to productive wells. The Company had approximately 360 gross and net proved undeveloped acres as of December 31, 2004.
Drilling Activity. The following table sets forth the results of drilling activities on properties owned by the Company. Such information and the results of prior drilling activities should not be considered as necessarily indicative of future performance.
- ---------- (1) All wells are located in the United States. All wells are development wells; no exploratory wells were drilled.
Present Activities. The Company has drilled 9 gross and 2.7 net development wells since December 31, 2004. As of March 20, 2005, the Company had no wells in the process of being drilled.
Delivery Commitments. The Company entered into various contracts with Dominion and IGS which, subject to certain restrictions and adjustments, obligate Dominion and IGS to purchase and the Company to sell all natural gas production from certain contract wells. The contract wells comprise approximately 75% of the Company's natural gas sales. In addition, the Company has entered into various short-term contracts which obligate the purchasers to purchase and the Company to sell and deliver certain quantities of natural gas production on a monthly basis throughout the term of the contracts.
Company Headquarters. The Company owns an approximately 5,400 square foot building located in Canfield, Ohio.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
There are no material pending legal proceedings to which the Company is a party or to which any of its property is subject.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of the fiscal year ended December 31, 2004, there were no matters submitted to a vote of security holders through the solicitation of proxies or otherwise.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Market
There is currently no established public trading market for the Units. At the present time, the Company does not intend to list any of the Units for trading on any exchange or otherwise take any action to establish any market for the Units. As of March 20, 2005, there were 5,690,874 Units held by 1,416 holders of record.
Distribution History
The Company commenced operations with the consummation of the Exchange Offer in February 1991. Management's stated intention was to make quarterly cash distributions equal to $0.125 per Unit (or $0.50 per Unit on an annualized basis) for the first eight quarters following the closing date of the Exchange Offer. The Company has paid a quarterly distribution every quarter since July 1991. The Company paid total cash distributions of $1.25 and $2.25 per Unit during 2003 and 2004, respectively. Based upon the current number of Units outstanding, each quarterly distribution of $0.125 per Unit would be approximately $720,000. The Company made a quarterly distribution of $0.50 per Unit in January 2005 and currently intends to make a quarterly distribution of $0.50 per Unit in April 2005 and quarterly distributions of at least $0.125 per Unit in July and October 2005.
Repurchase Right
The Partnership Agreement provides, that beginning in 1992 and annually thereafter, the Company offers to repurchase for cash up to 10% of the then outstanding Units, to the extent Unitholders offer Units to the Company for repurchase (the "Repurchase Right"). The Repurchase Right entitles any Unitholder, between May 1 and June 30 of each year, to notify the Company that he elects to exercise the Repurchase Right and have the Company acquire certain or all of his Units. The price to be paid for any such Units is calculated based on the method provided for in the Partnership Agreement. The Company accepted an aggregate of 22,401, 34,034 and 23,865 of its Units of limited partnership interest at a price of $5.66, $8.44 and $12.44 per Unit pursuant to the terms of the Company's Offers to Purchase dated April 30, 2002, 2003 and 2004, respectively. See Note 3 in the Company's financial statement for additional information on the Repurchase Right.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
- ---------- (1) Debt includes the Company's long-term debt and borrowings under the Company's revolving credit facility.
(2) See Note 1G to the consolidated financial statements. The cumulative effect of change in accounting principle was $471,545.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
The Company was organized in September 1990 as a limited partnership under the laws of the State of Delaware. Everflow Management Limited, LLC, an Ohio limited liability company, is the general partner of the Company. The Company was formed to engage in the business of oil and gas exploration and development through a proposed consolidation of the business and oil and gas properties of EEI, and the oil and gas properties owned by certain limited partnerships and working interest programs managed or operated by the Programs.
Effective February 15, 1991, pursuant to the Exchange Offer to acquire the EEI shares and the Interests in exchange for Units of the Company's limited partnership interest, the Company acquired the Interests and the EEI Shares and EEI became a wholly-owned subsidiary of the Company.
The General Partner is a limited liability company. The members of the General Partner are EMC, two individuals who are currently directors and/or officers of EEI, Thomas L. Korner and William A. Siskovic, and Sykes Associates, a limited partnership controlled by Robert F. Sykes, the Chairman of the Board of EEI.
LIQUIDITY AND CAPITAL RESOURCES
Financial Position
Working capital surplus of $12.5 million as of December 31, 2004 represented a $92,000 decrease from December 31, 2003 due primarily to a decrease in cash and equivalents of $1.6 million. The decrease was offset by an increase in accounts receivable from oil and gas production of $1.7 million during 2004. Accounts receivable from employees and joint venture
partners decreased $13,000 and $60,000, respectively, and accounts payable and accrued expenses increased $55,000 and $30,000, respectively.
The Company had a revolving credit facility with Bank One, N.A. that expired May 31, 2003. The Company had no borrowings in 2003 or 2004. The Company has no alternative financing plan, nor does it anticipate that one will be necessary. Cash flows were used to pay for the funding of the Company's investment in and the continued development of oil and gas properties and to repurchase Units pursuant to the Repurchase Right. The Company repurchased 23,865 Units at a price of $12.44 per Unit on June 30, 2004. The Company also used cash flows to make cash distributions, which totaled $13.0 million.
The following table summarizes the Company's financial position at December 31, 2004 and December 31, 2003:
Cash Flows from Operating, Investing and Financing Activities
The Company generated almost all of its cash sources from operating activities. During the years ended 2004 and 2003, cash provided by operations was used to fund the development of additional oil and gas properties, repurchase of Units pursuant to the Repurchase Right and distributions to partners.
The following table summarizes the Company's Statements of Cash Flows for the years ended December 31, 2004 and 2003:
Note: All items in the previous table are calculated as a percentage of total cash sources. Total cash sources include the following items, if positive: cash flow from operations before working capital changes, changes in working capital, net cash provided by investing activities and net cash provided by financing activities, plus any decrease in cash and equivalents.
As the above table indicates, the Company's cash flow from operations before working capital changes during the twelve months of 2004 and 2003 represented 93% and 100% of total cash sources, respectively. Changes in working capital other than cash and equivalents
decreased cash by $1.5 million during 2004 and by $422,000 during 2003. The primary reason for this decrease was the increase in accounts receivable at December 31, 2004 compared to December 31, 2003 resulted from an increase in gas and oil prices. Total production revenues receivable as of December 31, 2004 amounted to $5.7 million compared to $4.0 million at December 31, 2003.
The Company's cash flows used by investing activities increased $3.3 million, or 73%, during 2004 as compared with 2003. The Company's cash flows used by investing activities increased $510,000, or 12%, during 2003 as compared with 2002. The primary reason for the increase in cash flows used by investing activities in 2004 and 2003 was an increase in the purchase of property and equipment. The purchase of property and equipment increased $3.1 million, or 63%, during 2004 as compared with 2003. The purchase of property and equipment increased $690,000, or 16%, during 2003 as compared with 2002.
The Company's cash flows used by financing activities increased $5.7 million, or 76%, during 2004 as compared with 2003. The reasons for this increase were that distributions to Unitholders increased $5.7 million and payments on the repurchase of Units increased $10,000 during 2004. The Company's cash flows used by financing activities decreased $388,000, or 5%, during 2003 as compared with 2002. The reasons for this decrease were that distributions to Unitholders decreased $37,000, payments on the repurchase of Units increased $160,000 and payments on debt decreased $512,000 during 2003.
The Company's ending cash and equivalents balance of $8.0 million at December 31, 2004, as well as on-going monthly operating cash flows, should be adequate to meet short-term cash requirements. The Company has established a quarterly distribution and management believes the payment of such distributions will continue at least through 2005. The Company has paid a quarterly distribution every quarter since July 1991. Minimum cash distributions are estimated to be $720,000 per quarter ($.125 per Unit). The Company intends to distribute $2.9 million ($.50 per Unit) in April 2005 from existing cash and equivalents.
Capital expenditures for the development of oil and gas properties and the acquisition of undeveloped leasehold acreage have increased over recent years. The Company drilled or participated in the drilling of an additional 77 drillsites in 2004. The Company's share of these drillsites amounts to 33.90 net developed properties. The Company's share of proved gas reserves increased by 2.3 BCF, or 5%, between December 31, 2003 and December 31, 2004, while proved oil reserves increased by 79,000 barrels, or 11%, between December 31, 2003 and December 31, 2004. The Company continues to develop primarily natural gas fields, as represented by the discovery and addition of 3.2 BCF of natural gas versus 65,000 barrels of crude oil during 2004. The Standardized Measure of Discounted Future Net Cash Flows of the Company's reserves increased by $17.2 million between December 31, 2003 and December 31, 2004. The primary reasons for this increase were due to the discovery of additional reserves through the development of proved oil and gas properties and increases in natural gas and crude oil prices and related upward revisions in quantities of oil and gas reserves between December 31, 2003 and December 31, 2004. Although the Company's share of net developed properties was higher during 2004, management believes the Company should more likely be able to drill or participate in the drilling of 15 to 20 net wells each year for the next few years.
The Partnership Agreement provides that the Company annually offers to repurchase for cash up to 10% of the then outstanding Units, to the extent Unitholders offer Units to the Company for repurchase pursuant to the Repurchase Right. The Repurchase Right entitles any Unitholder, between May 1 and June 30 of each year, to notify the Company of his or her election to exercise the Repurchase Right and have the Company acquire such Units. The price to be paid for any such Units will be calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the Repurchase Right is to be effective and independently prepared reserve reports. The price per Unit will be equal to 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable Repurchase Right is to be effective less all Interim Cash Distributions received by a Unitholder. The adjusted book value is calculated by adding partner's equity, the Standardized Measure of Discounted Future Net Cash Flows and the tax effect included in the Standardized Measure and subtracting from that sum the carrying value of oil and gas properties (net of undeveloped lease costs). If more than 10% of the then outstanding Units are tendered during any period during which the Repurchase Right is to be effective, the Investor's Units so tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The Company repurchased 23,865, 34,034 and 22,401 Units during 2004, 2003 and 2002 pursuant to the Repurchase Right at a price of $12.44, $8.44 and $5.66 per Unit, respectively. The Repurchase Right to be conducted in 2005 will result in Unitholders being offered a price of $14.46 per Unit. The Company believes existing cash flows, including borrowing if necessary (although the Company currently has no credit facility), will be sufficient to fund the 2005 offering pursuant to the Repurchase Right is fully subscribed.
RESULTS OF OPERATIONS
The following table and discussion is a review of the results of operations of the Company for the years ended December 31, 2004, 2003 and 2002. All items in the table are calculated as a percentage of total revenues. This table should be read in conjunction with the discussions of each item below:
Revenues for the year ended December 31, 2004 increased $3.8 million, or 18%, compared to the same period in 2003. Revenues for the year ended December 31, 2003 increased $5.1 million, or 30%, compared to the same period in 2002. These changes were due primarily to increases in crude oil and natural gas sales between the periods involved.
Oil and gas sales increased $3.8 million, or 18%, from 2003 to 2004. This increase was the result of higher natural gas and crude oil prices. The average price received per MCF of natural gas increased from $4.73 to $5.68 from 2003 to 2004. Oil sales were higher due primarily to an increase in the average sales price of $27.93 to $37.98 per barrel from 2003 to 2004. The Company's gas production decreased by 121,000 MCF and oil production decreased by 4,000 barrels. Gas sales accounted for 89%, 90% and 90% of total oil and gas sales in 2004, 2003 and 2002, respectively. Oil and gas sales increased $5.0 million, or 31%, from 2002 to 2003. The primary reasons for this increase in oil and gas sales between 2002 and 2003 were increased oil and gas production and prices. The Company's gas production increased by 373,000 MCF and oil production increased by 3,000 barrels. The average price received per MCF increased from $3.98 to $4.73. The average price received per barrel increased from $22.33 to $27.93.
Production costs increased $141,000, or 5%, and $237,000, or 9%, during 2004 and 2003, respectively. The primary reason for these increases was an increase in the number of producing wells. Depreciation, depletion and amortization decreased $285,000, or 6%, from 2003 to 2004. The primary reason for this decrease is the result of an increase in oil and gas reserves that resulted from higher oil and gas pricing for estimated future production. Depreciation, depletion and amortization increased $557,000, or 13%, from 2002 to 2003. The primary reason for this increase was increased production of oil and gas for both new and existing wells during 2003 compared to 2002.
Well management and operating revenues increased $16,000, or 3%, from 2003 to 2004. Well management and operating costs decreased $36,000, or 16%, from 2003 to 2004. Well management and operating revenues increased $42,000, or 8%, from 2002 to 2003. Well management and operating costs increased $33,000, or 17%, from 2002 to 2003. The reason for these increases in well management and operating revenues were due to an increase in Company operated oil and gas interests.
Abandonments of oil and gas properties decreased $60,000 from 2003 to 2004 and decreased $100,000 from 2002 to 2003. These decreases were attributable to reductions in abandonments of oil and gas properties.
General and administrative expenses increased $89,000, or 7%, from 2003 to 2004, and decreased $31,000, or 2%, from 2002 to 2003. General and administrative expenses increased in 2004 as a result of increasing ongoing expenses of administering the Company. Salaries and wages expense and audit fees have increased $52,000 and $27,000, respectively, from 2003 to 2004.
Net other income amounted to $105,000, $141,000 and $47,000 in 2004, 2003 and 2002, respectively. After paying off all debt in 2002, net other income is dependent on the Company's cash balances and related interest earnings.
The Company is not a tax paying entity, and the net taxable income or loss, other than the taxable income or loss attributable to EEI, is allocated directly to its respective partners.
Net income increased $4.5 million, or 37%, from 2003 to 2004. Net income increased $3.9 million (after reduction for cumulative effect of change in accounting principle of $471,545), or 49%, from 2002 to 2003. The increases were primarily the result of increases in oil and gas sales. Net income represented 64%, 55% and 48% of total revenues during the years ended December 31, 2004, 2003 and 2002, respectively.
APPLICATION OF CRITICAL ACCOUNTING POLICIES
Property and Equipment. The Company uses the successful efforts method of accounting for oil and gas exploration and production activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties and to drill and equip development wells are initially capitalized. Costs of development wells (on properties the Company has no further interest in) that do not find proved reserves and geological and geophysical costs are expensed. The Company has not participated in exploratory drilling and owns no interest in unproved properties.
Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation and amortization on proved properties amounted to $4.7 million, $4.9 million and $4.4 million for the years ended December 31, 2004, 2003 and 2002, respectively.
On sale or retirement of a unit of a proved property (which generally constitutes the amortization base), the cost and related accumulated depreciation, depletion, amortization and write down are eliminated from the property accounts, and the resultant gain or loss is recognized.
The Company evaluates its oil and gas properties for impairment annually. SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," requires that long-lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Everflow utilizes a field by field basis for assessing impairment of its oil and gas properties.
Management of the Company believes that the accounting estimate related to oil and gas property impairment is a "critical accounting estimate" because it is highly susceptible to change from year to year. It requires the use of oil and gas reserve estimates that are directly impacted by future oil and gas prices and future production volumes. Actual oil and gas prices have fluctuated in the past and are expected to do so in the future.
Oil and gas reserve estimates are prepared annually based on existing contractual arrangements and current market conditions. Any increases in estimated future cash flows would have no impact on the reported value of the Company's oil and gas properties. In contrast, decreases in estimated future cash flows could require the recognition of an impairment loss equal to the difference between the fair value of the oil and gas properties (determined by calculating the discounted value of the estimated future cash flows) and the carrying amount of the oil and gas properties. Any impairment loss would reduce property and equipment as well as total assets of the Company. An impairment loss would also decrease net income.
Asset Retirement Obligations. In 2003, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For the Company, these obligations include plugging and abandonment of oil and gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Historically, and consistent with industry practice, the Company determined that the cost of plugging and abandoning its oil and gas properties would be offset by proceeds received from salvage. The Company recorded a non-cash charge of approximately $500,000 as the cumulative effect of a change in accounting principle, an increase to oil and gas properties of approximately $400,000 and a non-current liability of approximately $900,000 in connection with the adoption of SFAS No. 143.
The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of plugging
and abandonment costs; changes in estimated remaining lives of the wells; changes in federal or state regulations regarding plugging and abandonment requirements; and other factors.
The Company has no assets legally restricted for purposes of settling its asset retirement obligations. The Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.
Revenue Recognition. The Company recognizes revenue from oil and gas production as it is extracted and sold from the properties. Other revenue is recognized at the time it is earned and the Company has a contractual right to such revenue.
The Company participates (and may act as drilling contractor) with unaffiliated joint venture partners in the drilling, development and operation of jointly owned oil and gas properties. Each owner, including the Company, has an undivided interest in the jointly owned property(ies). Generally, the joint venture partners participate on the same drilling/development cost basis as the Company and, therefore, no revenue, expense or income is recognized on the drilling and development of the properties. Accounts receivable from joint venture partners consist principally of drilling and development costs the Company has advanced or incurred on behalf of joint venture partners. The Company earns and receives monthly management and operating fees from certain joint venture partners after the properties are completed and placed into production.
NEW ACCOUNTING STANDARDS
In January 2003, the FASB issued Interpretation No. 46, ("FIN 46"), Consolidation of Variable Interest Entities. FIN 46, as amended by FIN 46(R) in December 2003, provides guidance on how to identify a variable interest entity ("VIE"), and determine when the assets, liabilities, and results of operations of a VIE need to be included in a company's consolidated financial statements. FIN 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders in a VIE. The provisions of FIN 46 were effective immediately for all VIE's created after January 31, 2003. For VIEs created before February 1, 2003, the provisions of FIN 46, as amended, were effective on January 1, 2004. After evaluating this accounting pronouncement, the Company determined that it did not have any interests in any VIEs. Therefore, the adoption of FIN 46 did not have any impact on the Company's consolidated financial position, results of operations or cash flows.
INFLATION AND CHANGES IN PRICES
While the cost of operations is affected by inflation, oil and gas prices have fluctuated in recent years and generally have not matched inflation. The price of oil in the Appalachian Basin has ranged from a low of $8.50 per barrel in December 1998 to a high of $53.50 in March 2005. As of March 20, 2005, the posted field price in the Appalachian Basin area, the Company's principal area of operation, was $53.50 per barrel of oil. Although the Company's sales are affected by this type of price instability, the impact on the Company is not as dramatic as might be expected since less than 10% of the Company's total future cash inflows related to oil and gas reserves as of December 31, 2004 are comprised of oil reserves.
Natural gas prices have also fluctuated more recently. The Company's average price of gas during 2002 amounted to $3.98 per MCF. The Company's average price of gas during 2003 increased $.75 to $4.73 compared to 2002. The Company's average price of gas during 2004 increased $.95 to $5.68 compared to 2003. The price of gas in the Appalachian Basin increased significantly throughout 2000 and reached a high of more than $10.00 per MCF in January 2001. More recently, the price for Henry Hub Natural Gas on the NYMEX settled for the month of February 2005 at $6.64 per MCF. The Company's gas is currently sold under short-term contracts where the price is determined using current NYMEX prices. The Company at times will lock-in a monthly price over certain time periods. Excess gas production above locked-in quantities is sold at a price tied to the then current monthly NYMEX settled price. The Company's sales are significantly impacted by pricing instability in the natural gas market. One of the consequences of these pricing fluctuations is evident in the Company's Standardized Measure of Discounted Future Net Cash Flows increasing from $45.1 million at December 31, 2001 to $67.9 million at December 31, 2002, and then increasing to $101.8 million at December 31, 2003 and $119.1 million at December 31, 2004.
The Company's Standardized Measure of Discounted Future Net Cash Flows increased by $17.2 million from December 31, 2003 to December 31, 2004 and increased by $33.9 million from December 31, 2002 to December 31, 2003. A reconciliation of the Changes in the Standardized Measures of Discounted Future Net Cash Flows is included in the Company's consolidated financial statements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.
There were no borrowings during 2004 and 2003. The Company would be exposed to market risk from changes in interest rates if it funds its future operations through long-term or short-term borrowings.
The Company is exposed to market risk from changes in commodity prices. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for gas and oil production has been volatile and unpredictable for many years. These market risks can impact the Company's results of operations, cash flows and financial position. The Company's primary commodity price risk exposure results from contractual delivery commitments with respect to the Company's gas purchase contracts. The Company periodically makes commitments to sell certain quantities of natural gas to be delivered in future months at certain contract prices. This
affords the Company the opportunity to "lock in" the sale price for those quantities of natural gas. Failure to meet these delivery commitments would result in the Company being forced to purchase any short fall at current market prices. The Company's risk management objective is to lock in a range of pricing for no more than 80% to 90% of expected production volumes. This allows the Company to forecast future cash flows and earnings within a predictable range.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See attached pages to.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, such officers concluded that, as of December 31, 2004, the Company's disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Commission's rules and forms.
There have been no changes in the Company's internal controls that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
EVERFLOW EASTERN PARTNERS, L. P.
2004 CONSOLIDATED FINANCIAL REPORT
EVERFLOW EASTERN PARTNERS, L. P.
CONTENTS
Report of Independent Registered Public Accounting Firm
To the Partners Everflow Eastern Partners, L. P. Canfield, Ohio
We have audited the accompanying consolidated balance sheets of Everflow Eastern Partners, L. P. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, partners' equity, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company has determined that it is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Everflow Eastern Partners, L. P. and subsidiaries as of December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.
HAUSSER + TAYLOR LLC
Cleveland, Ohio March 4, 2005
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
December 31, 2004 and 2003
The accompanying notes are an integral part of these financial statements.
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
December 31, 2004 and 2003
The accompanying notes are an integral part of these financial statements.
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31, 2004,2003 and 2002
The accompanying notes are an integral part of these financial statements.
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY
Years Ended December 31, 2004, 2003 and 2002
The accompanying notes are an integral part of these financial statements.
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2004, 2003 and 2002
The accompanying notes are an integral part of these financial statements.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization - Everflow Eastern Partners, L. P. ("Everflow") is a Delaware limited partnership which was organized in September 1990 to engage in the business of oil and gas exploration and development. Everflow was formed to consolidate the business and oil and gas properties of Everflow Eastern, Inc. ("EEI") and subsidiaries and the oil and gas properties owned by certain limited partnership and working interest programs managed or sponsored by EEI ("EEI Programs" or "the Programs").
Everflow Management Limited, LLC, an Ohio limited liability company, is the general partner of Everflow and, as such, is authorized to perform all acts necessary or desirable to carry out the purposes and conduct of the business of Everflow. The members of Everflow Management Limited, LLC are Everflow Management Corporation ("EMC"), two individuals who are Officers and Directors of EEI and Sykes Associates, a limited partnership controlled by Robert F. Sykes, the Chairman of the Board of EEI. EMC is an Ohio corporation formed in September 1990 and is the managing member of Everflow Management Limited, LLC.
B. Principles of Consolidation - The consolidated financial statements include the accounts of Everflow, its wholly-owned subsidiaries, including EEI and EEI's wholly-owned subsidiaries, and investments in oil and gas drilling and income partnerships (collectively, the "Company") which are accounted for under the proportional consolidation method. All significant accounts and transactions between the consolidated entities have been eliminated.
C. Use of Estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
D. Fair Value of Financial Instruments - The fair values of cash and equivalents, accounts receivable, accounts payable and other short-term obligations approximate their carrying values because of the short maturity of these financial instruments. The carrying values of the Company's long-term obligations approximate their fair value. In accordance with Statement of Financial Accounting Standards ("SFAS") No. 107, "Disclosure About Fair Value of Financial Instruments," rates available at balance sheet dates to the Company are used to estimate the fair value of existing obligations.
E. Cash and Equivalents - The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Company maintains at various financial institutions cash and equivalents which may exceed federally insured amounts and which may, at times, significantly exceed balance sheet amounts due to float.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
F. Property and Equipment - The Company uses the successful efforts method of accounting for oil and gas exploration and production activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties and to drill and equip development wells are initially capitalized. Costs of development wells (on properties the Company has no further interest in) that do not find proved reserves and geological and geophysical costs are expensed. The Company has not participated in exploratory drilling and owns no interest in unproved properties.
Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation and amortization on proved properties amounted to $4,603,114, $4,801,170 and $4,345,208 for the years ended December 31, 2004, 2003 and 2002, respectively.
On sale or retirement of a unit of a proved property (which generally constitutes the amortization base), the cost and related accumulated depreciation, depletion, amortization and write down are eliminated from the property accounts, and the resultant gain or loss is recognized.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," requires that long-lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Everflow utilizes a field by field basis for assessing impairment of its oil and gas properties. The Company wrote down oil and gas properties by approximately $40,000, $100,000 and $200,000 during 2004, 2003 and 2002, respectively, to provide for impairment on certain of its oil and gas properties.
Pipeline and support equipment and other corporate property and equipment are depreciated principally on the straight-line method over their estimated useful lives (pipeline and support equipment - 10 to 22 years, other corporate equipment - 3 to 7 years, other corporate property - building and improvements with a cost of $1,209,523 - 40 years). Depreciation on pipeline and support equipment and other corporate property and equipment amounted to $104,636, $95,901 and $75,820 for the years ended December 31, 2004, 2003 and 2002, respectively.
Maintenance and repairs of property and equipment are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
G. Asset Retirement Obligations - In 2003, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For the Company, these obligations include plugging and abandonment of oil and gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Historically, and consistent with industry practice, the Company determined that the cost of plugging and abandoning its oil and gas properties would be offset by proceeds received from salvage. The Company recorded a non-cash charge of approximately $500,000 as the cumulative effect of a change in accounting principle, an increase to oil and gas properties of approximately $400,000 and a non-current liability of approximately $900,000 in connection with the adoption of SFAS No. 143.
The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of plugging and abandonment costs; changes in estimated remaining lives of the wells; changes in federal or state regulations regarding plugging and abandonment requirements; and other factors.
The Company has no assets legally restricted for purposes of settling its asset retirement obligations. The Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.
The schedule below is a reconciliation of the Company's liability for the years ended December 31:
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
G. Asset Retirement Obligations (Continued)
For 2004 and 2003, accretion expense is included in depreciation, depletion and amortization in the Company's consolidated statements of operations and the asset retirement obligations are included in accrued expenses (current portion) and asset retirement obligations (non-current portion) in the Company's consolidated balance sheets. The pro forma effects had SFAS No. 143 been applied during prior periods would have reduced the Company's net income and net income per unit by approximately $85,000 and $.01, respectively, in 2002.
H. Revenue Recognition - The Company recognizes revenue from oil and gas production as it is extracted and sold from the properties. Other revenue is recognized at the time it is earned and the Company has a contractual right to such revenue.
The Company participates (and may act as drilling contractor) with unaffiliated joint venture partners in the drilling, development and operation of jointly owned oil and gas properties. Each owner, including the Company, has an undivided interest in the jointly owned property(ies). Generally, the joint venture partners participate on the same drilling/development cost basis as the Company and, therefore, no revenue, expense or income is recognized on the drilling and development of the properties. Accounts receivable from joint venture partners consist principally of drilling and development costs the Company has advanced or incurred on behalf of joint venture partners. The Company earns and receives monthly management and operating fees from certain joint venture partners after the properties are completed and placed into production.
I. Income Taxes - Everflow is not a tax-paying entity and the net taxable income or loss, other than the taxable income or loss allocable to EEI, which is a C corporation owned by Everflow, will be allocated directly to its respective partners. The Company is not able to determine the net difference between the tax bases and the reported amounts of Everflow's assets and liabilities due to separate tax elections that were made by owners of the working interests and limited partnership interests that comprised Programs.
EEI and its subsidiaries account for income taxes under SFAS No. 109, "Accounting for Income Taxes." Income taxes are provided for all items (as they relate to EEI and its subsidiaries) in the Consolidated Statements of Income regardless of the period when such items are reported for income tax purposes. SFAS No. 109 provides that deferred tax assets and liabilities be recognized for temporary differences between the financial reporting basis and tax basis of certain of EEI's and its subsidiaries' assets and liabilities. In addition, SFAS No. 109 requires that deferred tax assets and liabilities be measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The impact on deferred taxes of changes in tax rates and laws, if any, is reflected in the financial statements in the period of enactment. In some situations, SFAS No. 109 permits the recognition of expected benefits of utilizing net operating loss and tax credit carryforwards.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
J. Allocation of Income and Per Unit Data - Under the terms of the limited partnership agreement, initially, 99% of revenues and costs were allocated to the unitholders (the limited partners) and 1% of revenues and costs were allocated to the general partner. The allocation changes as unitholders elect to exercise the repurchase right (see Note 3).
Earnings and distributions per limited partner Unit have been computed based on the weighted average number of Units outstanding during the year for each year presented. Average outstanding Units for earnings and distributions per Unit calculations amount to 5,702,806, 5,731,756 and 5,759,974 in 2004, 2003 and 2002, respectively.
K. New Accounting Standards - In January 2003, the FASB issued Interpretation No. 46, ("FIN 46"), Consolidation of Variable Interest Entities. FIN 46, as amended by FIN 46(R) in December 2003, provides guidance on how to identify a variable interest entity ("VIE"), and determine when the assets, liabilities, and results of operations of a VIE need to be included in a company's consolidated financial statements. FIN 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders in a VIE. The provisions of FIN 46 were effective immediately for all VIE's created after January 31, 2003. For VIEs created before February 1, 2003, the provisions of FIN 46, as amended, were effective on January 1, 2004. After evaluating this accounting pronouncement, the Company determined that it did not have any interests in any VIEs. Therefore, the adoption of FIN 46 did not have any impact on the Company's consolidated financial position, results of operations or cash flows.
NOTE 2. CREDIT FACILITIES AND LONG-TERM DEBT
The Company had a revolving line of credit that expired on May 31, 2003. The Company anticipates, although there is no assurance it will be able to, entering into a new credit agreement for the purpose, if necessary, of funding the annual repurchase right (see Note 3). The new line of credit would be utilized in the event the Company receives tenders pursuant to the repurchase right in excess of cash on hand.
There were no borrowings outstanding on the revolving line of credit during 2004 and 2003. The Company would be exposed to market risk from changes in interest rates if it funds its future operations through long-term or short-term borrowings.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 3. PARTNERS' EQUITY
Units represent limited partnership interests in Everflow. The Units are transferable subject only to the approval of any transfer by Everflow Management Limited, LLC and to the laws governing the transfer of securities. The Units are not listed for trading on any securities exchange nor are they quoted in the automated quotation system of a registered securities association. However, unitholders have an opportunity to require Everflow to repurchase their Units pursuant to the repurchase right.
Under the terms of the limited partnership agreement, initially, 99% of revenues and costs are allocated to the unitholders (the limited partners) and 1% of revenues and costs are allocated to the general partner. Such allocation has changed and will change in the future due to unitholders electing to exercise the repurchase right.
The partnership agreement provides that Everflow will repurchase for cash up to 10% of the then outstanding Units, to the extent unitholders offer Units to Everflow for repurchase pursuant to the repurchase right. The repurchase right entitles any unitholder, between May 1 and June 30 of each year, to notify Everflow that he elects to exercise the repurchase right and have Everflow acquire certain or all of his Units. The price to be paid for any such Units is calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the repurchase right is to be effective and independently prepared reserve reports. The price per Unit equals 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable repurchase right is to be effective less all interim cash distributions received by a unitholder. The adjusted book value is calculated by adding partners' equity, the standardized measure of discounted future net cash flows and the tax effect included in the standardized measure and subtracting from that sum the carrying value of oil and gas properties (net of undeveloped lease costs). If more than 10% of the then outstanding Units are tendered during any period during which the repurchase right is to be effective, the investors' Units tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The price associated with the repurchase right, based upon the December 31, 2004 calculation, is estimated to be $14.46 per Unit, net of the distributions ($1.00 per Unit in total) expected to be made in January and April 2005.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 3. PARTNERS' EQUITY (CONTINUED)
Units repurchased pursuant to the repurchase right, for each of the four years in the period ended December 31, 2004, are as follows:
NOTE 4. PROVISION FOR INCOME TAXES
A reconciliation between taxes computed at the Federal statutory rate and the effective tax rate in the statements of income follows:
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 4. PROVISION FOR INCOME TAXES (CONTINUED)
As referred to in Note 1, EEI and its subsidiaries account for current and deferred income taxes under the provisions of SFAS No. 109. Items giving rise to deferred taxes consist of temporary differences arising from differences in financial reporting and tax reporting methods for EEI's proved properties. At December 31, 2004 and 2003, these deferred tax items resulted in deferred tax liabilities of $506,000 and $537,000, respectively. These liabilities have been fully offset by deferred tax assets resulting from the tax benefit of EEI's percentage depletion carryovers. At December 31, 2004 and 2003, EEI had percentage depletion deduction carryforwards for tax purposes of approximately $1,311,000 and $1,450,000, respectively. These carryforwards can be carried forward indefinitely.
NOTE 5. RETIREMENT PLAN
The Company has a defined contribution plan pursuant to Section 401(k) of the Internal Revenue Code for all employees who have reached the age of 21 and completed one year of service. The Company matches employees' contributions to the 401(k) Retirement Savings Plan as annually determined by EMC's Board of Directors. Additionally, the plan has a profit sharing component which provides for contributions to the plan at the discretion of EMC's Board of Directors. Amounts contributed to the plan vest immediately. The Company's total matching and profit sharing contributions to the plan amounted to $167,220, $169,035 and $217,301 for the years ended December 31, 2004, 2003 and 2002, respectively.
NOTE 6. RELATED PARTY TRANSACTIONS
The Company's Officers, Directors, Affiliates and certain employees have frequently participated, and will likely participate in the future, as working interest owners in wells in which the Company has an interest. Frequently, the Company has loaned the funds necessary for certain employees to participate in the drilling and development of such wells. At December 31, 2004, the loans accrue interest at 4.15% and are expected to be paid from production revenues attributable to such interests or through joint interest assessments.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 7. BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS
The Company operates exclusively in the United States, almost entirely in Ohio and Pennsylvania, in the exploration, development and production of oil and gas.
The Company operates in an environment with many financial risks, including, but not limited to, the ability to acquire additional economically recoverable oil and gas reserves, the inherent risks of the search for, development of and production of oil and gas, the ability to sell oil and gas at prices which will provide attractive rates of return, the volatility and seasonality of oil and gas production and prices, and the highly competitive and, at times, seasonal nature of the industry and worldwide economic conditions. The Company's ability to expand its reserve base and diversify its operations is also dependent upon the Company's ability to obtain the necessary capital through operating cash flow, borrowings or equity offerings. Various federal, state and governmental agencies are considering, and some have adopted, laws and regulations regarding environmental protection which could adversely affect the proposed business activities of the Company. The Company cannot predict what effect, if any, current and future regulations may have on the operations of the Company.
Management of the Company continually evaluates whether the Company can develop oil and gas properties at historical levels given current industry and market conditions. If the Company is unable to do so, it could be determined that it is in the best interests of the Company and its unitholders to reorganize, liquidate or sell the Company. However, management cannot predict whether any sale transaction will be a viable alternative for the Company in the immediate future.
Gas sales accounted for 89%, 90% and 90% of total oil and gas sales in 2004, 2003 and 2002, respectively. Approximate percentages of total oil and gas sales from significant purchasers for the years ended December 31, 2004, 2003 and 2002, respectively, were as follows:
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 7. BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS (CONTINUED)
A significant portion of the Company's production accounts receivable is due from the Company's major customers. The Company does not view such concentration as an unusual credit risk. However, the Company does not require collateral from its customers and could incur losses if its customers fail to pay. Credit losses have historically been minimal and no valuation allowance was deemed necessary at December 31, 2004 and 2003. The Company expects that Dominion, Ergon Oil and IGS will be the only major customers in 2005.
The Company has numerous short-term contracts, which obligate Dominion to purchase, and the Company to sell and deliver, certain natural gas production from the Company's wells throughout the contract periods. A summary of significant gas purchase contracts, including weighted average pricing provisions, with Dominion follows:
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 7. BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS (CONTINUED)
The Company also has a short-term contract with IGS, which obligates IGS to purchase, and the Company to sell and deliver, certain quantities of natural gas production on a monthly basis throughout the contract periods. A summary of significant gas purchase contracts, including weighted average pricing provisions, with IGS follows:
As detailed above, the price paid for natural gas purchased by Dominion and IGS varies based on quantities locked in by the Company from time to time. Natural gas sold under these contracts in excess of the locked in prices are sold at the month's closing price plus basis adjustments, as per the contracts. As of December 31, 2004, natural gas purchased by Dominion covers production from approximately 490 gross wells, while natural gas purchased by IGS covers production from approximately 220 gross wells. Production from the Dominion and IGS contract wells comprises more than 75% of the Company's natural gas sales.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Everflow paid a dividend in January 2005 of $.50 per Unit. The distribution amounted to approximately $2,879,000.
As described in Note 7, the Company has significant natural gas delivery commitments to Dominion and IGS, its major customers. Management believes the Company can meet its delivery commitments based on estimated production. If, however, the Company cannot meet its delivery commitments, it will purchase gas at market prices to meet such commitments which will result in a gain or loss for the difference between the delivery commitment price and the price the Company is able to purchase the gas for redelivery (resale) to its customers.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 9. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of selected quarterly financial data (unaudited) for the years ended December 31, 2004 and 2003:
Quarterly operating results are not necessarily representative of operations for a full year for various reasons, including the volatility and seasonality of oil and gas production and prices, the highly competitive and, at times, seasonal nature of the oil and gas industry and worldwide economic conditions.
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following supplemental unaudited oil and gas information is required by SFAS No. 69, "Disclosures About Oil and Gas Producing Activities."
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
The tables on the following pages set forth pertinent data with respect to the Company's oil and gas properties, all of which are located within the continental United States.
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
In 2004, 2003 and 2002, development costs include the purchase of approximately $21,000, $-0- and $222,000, respectively, of producing oil and gas properties.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
Income tax expense was computed using statutory tax rates and reflects permanent differences that are reflected in the Company's consolidated income tax expense for the year.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
The Company has not determined proved reserves associated with its proved undeveloped acreage. At December 31, 2004 and 2003, the Company had 360 and 430 net proved undeveloped acres, respectively. The carrying cost of the proved undeveloped acreage that is included in proved properties amounted to $188,869 and $417,441 at December 31, 2004 and 2003, respectively.
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
The estimated future cash flows are determined based on year-end prices for crude oil, current allowable prices (adjusted for periods beyond the contract period to year-end market prices) applicable to expected natural gas production, estimated production of proved crude oil and natural gas reserves, estimated future production and development costs of reserves and future retirement obligations (net of salvage), based on current economic conditions, and the estimated future income tax expense, based on year-end statutory tax rates (with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less the tax basis of the properties involved. Such cash flows are then discounted using a 10% rate.
The methodology and assumptions used in calculating the standardized measure are those required by SFAS No. 69. It is not intended to be representative of the fair market value of the Company's proved reserves. The valuation of revenues and costs does not necessarily reflect the amounts to be received or expended by the Company. In addition to the valuations used, numerous other factors are considered in evaluating known and prospective oil and gas reserves.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Company, as a limited partnership, does not have any directors or executive officers. The General Partner of the Company is Everflow Management Limited, LLC, an Ohio limited liability company formed in March 1999, as the successor to the Company's original general partner. The members of the General Partner as of March 20, 2005 are Everflow Management Corporation, an Ohio corporation ("EMC"), Thomas L. Korner and William A. Siskovic, all of whom are directors and/or officers of EEI, and Sykes Associates, a limited partnership controlled by Robert F. Sykes, Chairman of the Board of EEI.
EMC is the Managing Member of the General Partner. EMC was formed in September 1990 to act as the Managing General Partner of Everflow Management Company, the predecessor of the General Partner. EMC is owned by the other members of the General Partner and EMC currently has no employees, but as Managing Member of the General Partner, makes all management and business decisions on behalf of the General Partner and thus on behalf of the Company.
EEI has continued its separate existence and provides general, administrative, management and leasehold functions for the Company. Personnel previously employed by EEI to conduct its operation, drilling and field supervisory functions have become employed directly by the Company and discharge the same functions on behalf of the Company. All of EEI's outstanding shares are owned by the Company.
Directors and Officers of EEI and EMC. The executive officers and directors of EEI and EMC as of March 20, 2005 are as follows:
All directors of EEI are elected to serve by the Company, which is EEI's sole shareholder. All officers of EEI serve at the pleasure of the Board of Directors. Directors and officers of EEI
receive no compensation or fees for their services to EEI or their services on behalf of the Company.
All directors and officers of EMC hold their positions with EMC pursuant to a shareholders' agreement among EMC and such directors and officers. The shareholders agreement controls the operation of EMC, provides for changes in share ownership of EMC, and determines the identity of the directors and officers of EMC as well as their replacements.
The directors and officers of EMC act as the Company's audit committee as specified in section 3(a)(58)(B) of the Exchange Act. William A. Siskovic, who is not independent, has been designated the Company's audit committee financial expert.
The Company has adopted a Code of Ethics that applies to the Company's principal executive officer, principal financial officer, principal accounting officer, or persons performing similar functions. The Code of Ethics is attached as Exhibit 14.1 to this 10-K.
Robert F. Sykes has been a Director of EEI since March 1987 and Chairman of the Board since May 1988. Mr. Sykes is the Chairman of the Board and a Director of EMC and has served in such capacities since its formation in September 1990. He was the Chairman of the Board of Sykes Datatronics, Inc., Rochester, New York, from its organization in 1986 until his resignation in January 1989. Sykes Datatronics, Inc. is a manufacturer of telephone switching equipment. Mr. Sykes also served as President and Chief Executive Officer of Sykes Datatronics, Inc. from 1968 until October 1983 and from January 1985 until October 1985. Mr. Sykes also has been a Director of Voplex, Inc., Rochester, New York, a manufacturer of plastic products, and a Director of ACC Corp., a long distance telephone company.
Thomas L. Korner has been President of EEI and EMC since November 1995 and the President and Treasurer of Everflow Nominee. Mr. Korner is also a Director of EMC and has served in such capacity since its formation in September 1990. He served as Vice President and Secretary of EEI from April 1985 to November 1995 and as Vice President and Secretary of EMC from September 1990 to November 1995. He served as the Treasurer of EEI from June 1982 to June 1986. Mr. Korner supervises and oversees all aspects of EEI's business, including oil and gas property acquisition, development, operation and marketing. Prior to joining EEI in June 1982, Mr. Korner was a practicing certified public accountant with Hill, Barth and King, certified public accountants, and prior to that with Arthur Andersen & Co., certified public accountants. He has a Business Administration Degree from Mt. Union College.
David A. Kidder has been the Treasurer of EEI since June 1986 and has been employed by EEI since April 1985. From 1983 to 1985, he was Treasurer of LGM Corporation, Columbus, Ohio, an oil and gas service company; from 1982 to 1983, he was Treasurer of OPEX, Inc., Columbus, Ohio, a producer of oil and gas; and from 1980 to 1981, he was Treasurer of United Petroleum, Inc., Columbus, Ohio, a producer of oil and gas. From 1973 to 1980, Mr. Kidder was involved in the oil and gas industry in various financial and accounting capacities. Prior to that time, Mr. Kidder practiced as a certified public accountant with Coopers & Lybrand, certified public accountants. Mr. Kidder has a Bachelor of Arts Degree in Accounting from the University of Cincinnati.
William A. Siskovic has been a Vice President of EEI since January 1989. Mr. Siskovic is a Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and a Director of EMC. He has served as Principal Financial Officer and Secretary of EMC since November 1995 and in all other capacities since the formation of EMC in September 1990. He is responsible for the financial operations of the Company and EEI. From August 1980 to July 1984, Mr. Siskovic served in various financial and accounting capacities including Assistant Controller of Towner Petroleum Company, a public independent oil and gas operator, producer and drilling fund sponsor company. From August 1984 to September 1985, Mr. Siskovic was a Senior Consultant for Arthur Young & Company, certified public accountants, where he was primarily responsible for the firm's oil and gas consulting practice in the Cleveland, Ohio office. From October 1985 until joining EEI in April 1988, Mr. Siskovic served as Controller and Principal Accounting Officer of Lomak Petroleum, Inc., a public independent oil and gas operator and producer. He has a Business Administration Degree in Accounting from Cleveland State University.
Compliance to Section 16(a) of the Exchange Act. Section 16(a) of the Securities Exchange Act of 1934 requires the Company's officers and directors, and persons who own more than 10% of the Units to file reports of ownership and changes in ownership with the Securities and Exchange Commission. Officers, directors and greater than 10% Unitholders are required by SEC regulation to furnish the Company with copies of all Section 16(a) forms they file.
Based solely on the Company's review of the copies of such forms furnished to the Company, the Company believes that its officers, directors and greater than 10% beneficial owners complied with all Section 16(a) filing requirements for 2004.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
As a limited partnership the Company has no executive officers or directors, but is managed by the General Partner. The executive officers of EMC and EEI are compensated either directly by the Company or indirectly through EEI. The compensation described below represents all compensation from either the Company or EEI.
The following table sets forth information concerning the annual and long-term compensation for services in all capacities to the Company for the fiscal years ended December 31, 2004, 2003 and 2002, of those persons who were, at December 31, 2004: (i) the chief executive officer; and (ii) the other highly compensated executive officer of the Company. The Chief Executive Officer and such other executive officer are hereinafter referred to collectively as the "Named Executive Officers."
SUMMARY COMPENSATION TABLE
- ---------- No Named Executive Officer received personal benefits or perquisites during 2004, 2003 and 2002 in excess of the lesser of $50,000 or 10% of his aggregate salary and bonus.
(1) Includes amounts contributed under the Company's 401(K) Retirement Savings Plan. The Company matched employees' contributions to the 401(K) Retirement Savings Plan to the extent of 100% of the first 6% of a participant's salary reduction. Also includes amounts contributed under the profit sharing component of the Company's 401(K) Retirement Savings Plan. The amounts attributable to the Company's matching and profit sharing contributions vest immediately.
(2) Includes amounts considered taxable wages with respect to the Company's Group Term Life Insurance Plan.
The General Partner, EMC and the members do not receive any separate compensation or reimbursement for their management efforts on behalf of the Company. All direct and indirect costs incurred by the Company are borne by the General Partner of the Company and the Unitholders as Limited Partners of the Company in proportion to their respective interest in the Company. The members are not entitled to any fees or other compensation as a result of the acquisition or operation of oil and gas properties by the Company. The members, in their individual capacities, are not entitled to share in distributions from or income of the Company on an ongoing basis, upon liquidation or otherwise. The members only share in the revenues, income and distributions of the Company indirectly through their ownership of the General Partner of the Company. The General Partner is entitled to share in the income and expense of the Company on the basis of its interests in the Company. The General Partner through it predecessor, Everflow Management Company, contributed Interests (as defined and described in "Item 1. Business" above) with an Exchange value of $670,980 for its interest as a general partner in the Company.
None of the officers of the Company has an employment agreement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The General Partner is a limited liability company of which EMC, an Ohio corporation is the Managing Member. The members of the General Partner are Thomas L. Korner and William A. Siskovic, both of whom are directors and officers of EEI, and Sykes Associates, a limited partnership controlled by Robert F. Sykes, Chairman of the Board of EEI and EMC. The General Partner of the Company, owns a 1.17% interest in the Company. The members and their affiliates currently hold (in addition to the General Partner's interest in the Company) 1,266,770 Units, representing approximately 22.26% of the outstanding Units.
The following table sets forth certain information with respect to the number of Units beneficially owned as of March 20, 2005 by each person known to the management of the Company to own beneficially more than 5% of the outstanding Units; by each director and officer of EMC; and by all directors and officers as a group. The table also sets forth (i) the ownership interests of the General Partner, and (ii) the ownership of EMC.
BENEFICIAL OWNERSHIP OF UNITS IN THE COMPANY, EVERFLOW MANAGEMENT LIMITED, LLC AND EMC
- ---------- (1) Does not include the interest in the Company owned indirectly by such individuals as a result of their ownership in (i) the General Partner (based on its 1.17% interest in the Company) or (ii) EMC (based on EMC's 1% managing member's interest in the General Partner).
(2) Includes the interest in the General Partner owned indirectly by such individuals as a result of their share ownership in EMC resulting from EMC's 1% managing member's interest in the General Partner.
(3) Includes 732,855 Units held by Sykes Associates, LLC, a New York limited liability company comprised of Mr. Sykes as managing member, his wife and four adult children as members, 162,462 Units of the Company held by the Robert F. Sykes Annuity Trust and 161,147 Units held by the Catherine Sykes Annuity Trust.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In the past, certain officers, directors and more than 10% Unitholders of the Company have invested, and may in the future invest, in oil and gas programs sponsored by EEI on the same terms as unrelated investors. In the past, certain officers, directors and/or more than 10% Unitholders of the Company have frequently participated and will likely participate in the future as working interest owners in wells in which the Company has an interest. The Company anticipates that any such participation by individual members of the Company's management would enable such individuals to participate in the drilling and development of undeveloped
drillsites on an equal basis with the Company or the particular drilling program acquiring such drillsites, which participation would be on a uniform basis with respect to all drilling conducted during a specified time frame, as opposed to selective participation. Frequently, such participation has been on more favorable terms than the terms which were available to unrelated investors. In the past, EEI loaned the officers of the Company the funds necessary to participate in the drilling and development of such wells. The Company has ceased making these loans in compliance with the Sarbanes-Oxley Act of 2002.
Certain officers and directors of EMC own oil and gas properties and, as such, contract with the Company to provide field operations on such properties. These ownership interests are charged per well fees for such services on the same basis as all other working interest owners. Thomas L. Korner and William A. Siskovic each had investments in oil and gas properties during 2004 and 2003 in the amount of $168,371 and $97,153, respectively.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Hausser + Taylor LLC served as the Company's independent auditor for the year ended December 31, 2004. Aggregate fees for professional services provided to the Company by Hausser + Taylor LLC for the years ended December 31, 2004 and 2003 were as follows:
Audit fees include fees associated with the annual audit and the reviews of the Company's quarterly report on Form 10-Q and for services that are normally provided by the accountants in connection with statutory and regulatory filings or engagements. Hausser + Taylor LLC did not charge the Company any audit-related, tax or other fees for these years.
Hausser + Taylor LLC (the "Firm") has a continuing relationship with American Express Tax and Business Services, Inc. ("TBS") from which it leases auditing staff who are full time, permanent employees of TBS and through which its shareholders provide non-audit services. As a result of this arrangement, the Firm has no full time employees and, therefore, none of the audit services performed were provided by permanent full time employees of the Firm. The Firm manages and supervises the audit and audit staff, and is exclusively responsible for the opinion rendered in connection with its examination.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) (1) Financial Statements
The following Consolidated Financial Statements of the Registrant and its subsidiaries are included in Part II, Item 8:
(a) (2) Financial Statements Schedules
All schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore have been omitted.
(a) (3) Exhibits
See the Exhibit Index at page E-1 of this Annual Report on Form 10-K.
(b) Reports on Form 8-K
The Company did not file any reports on Form 8-K during the last quarter of its year ended December 31, 2004.
(c) Exhibits required by Item 601 of Regulation S-K
Exhibits required to be filed by the Company pursuant to Item 601 of Regulator S-K are contained in the Exhibits listed under Item 15(a)(3).
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
EVERFLOW EASTERN PARTNERS, L.P.
By: EVERFLOW MANAGEMENT LIMITED, LLC General Partner
By: EVERFLOW MANAGEMENT CORPORATION Managing Member
Exhibit Index
E-1
Exhibit Index
- ---------- (1) Incorporated herein by reference to the appropriate exhibit to Registrant's Registration Statement on Form S-1 (Reg. No. 33-36919).
(2) Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994 (File No. 0-19279).
(3) Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the third quarter ended September 30, 1995 (File No. 0-19279).
(4) Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 0-19279).
(5) Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0-19279).
(6) Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the second quarter ended June 30, 1997 (File No. 0-19279).
(7) Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the second quarter ended June 30, 1998 (File No. 0-19279).
(8) Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the first quarter ended March 31, 1999 (File No. 0-19279).
(9) Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the second quarter ended June 30, 1999 (File No. 0-19279).
E-2
Exhibit Index
(10) Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the third quarter ended September 30, 2000 (File No. 0-19279).
(11) Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the third quarter ended September 30, 2001 (File No. 0-19279).
(12) Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 0-19279).
E-3