ITEM 1. BUSINESS
Seagull Energy Corporation (the "Company" or "Seagull") is an independent energy company primarily engaged in natural gas exploration, development and production. The Company's operations are focused offshore Texas and Louisiana in the Gulf of Mexico and onshore in three principal geographic regions: (i) western Oklahoma and the Texas Panhandle; (ii) the Arklatex area in eastern Texas and northern Louisiana and the Arkoma Basin in eastern Oklahoma and western Arkansas; and (iii) western Canada. Seagull's two other business segments are also natural gas related: (i) pipeline and marketing which includes natural gas gathering, gas processing, gas marketing and pipeline engineering, design, construction and operation; and (ii) natural gas transmission and distribution in Alaska. In September 1995, the Company disposed of substantially all of its gas gathering and processing assets. The Company was incorporated in Texas in 1973 as a wholly owned subsidiary of Houston Oil & Minerals Corporation ("HO&M"). In March 1981, the Company became an independent entity as a result of the spin-off of its shares to the stockholders of HO&M. The "Company" or "Seagull" refers to Seagull and its consolidated subsidiaries, unless otherwise indicated or the context otherwise suggests.
For financial information relating to industry segments, see Note 15 of Notes to Consolidated Financial Statements of Seagull Energy Corporation and Subsidiaries. The Consolidated Financial Statements of Seagull Energy Corporation and Subsidiaries and the Notes related thereto (the "Consolidated Financial Statements") are included in the Company's 1995 Annual Report to Shareholders and as part of Exhibit 13 attached hereto. Prior to 1994, the Company derived no revenues and had no material assets outside the United States. See discussions below regarding the Company's interests in Canada and in production licenses acquired in United Kingdom waters.
Items 1, 3 and 7 of this document include "forward looking" statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although the Company believes that the expectations reflected in such forward looking statements are based upon reasonable assumptions, it can give no assurance that its expectations will be achieved. Important factors that could cause actual results to differ materially from the Company's expectations are disclosed in conjunction with the forward looking statements included herein ("Cautionary Disclosures"). Subsequent written and oral forward looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Disclosures.
EXPLORATION AND PRODUCTION
Seagull's exploration and production ("E&P") segment is the Company's primary growth area and is comprised of the following material direct and indirect wholly owned subsidiaries of the Company: Seagull Energy E&P Inc.; HO&M; Wacker Oil Inc.; Seagull Midcon Inc.; Seagull Mid-South Inc. and Seagull Energy Canada Ltd. ("Seagull Canada").
The Company's other exploration activities outside North America consist of several production licenses, awarded to two exploration groups which include Seagull, in United Kingdom waters. While the Company currently has no producing properties in the United Kingdom waters, two exploratory wells are scheduled to be drilled in 1996.
Seagull's ongoing North American exploration program has been concentrated in the Gulf of Mexico, primarily in shallow waters off the central Texas Gulf Coast. The Company has in the past financed its gas and
oil exploration and development activities through internally generated funds and participation by industry partners on a prospect-by-prospect basis. The Company believes that its gas and oil exploration and development activities in the foreseeable future will be financed by internally generated funds. In 1996, the Company expects E&P capital expenditures to total approximately $122 million. Of this amount, about $47 million will be devoted to exploration, primarily in the Gulf of Mexico, $66 million to development and $9 million to leasehold acquisition. By comparison, 1995 capital expenditures for E&P activities totaled $76 million. Management believes that the Company's capital resources will be sufficient to finance current and forecasted operations.
Revenues from the sale of gas and liquids production accounted for 62%, 64% and 60% of the Company's consolidated revenues for 1995, 1994 and 1993, respectively. As used in this Annual Report on Form 10-K, liquids means oil, condensate and natural gas liquids, unless otherwise indicated or the context otherwise suggests. Gas production in 1995 decreased from the prior year primarily as a result of voluntary curtailments by Seagull and natural production declines of the reserves. Production of gas and liquids for 1995 averaged 333.8 million cubic feet ("MMcf") per day ("MMcf/d") and 4,268 barrels ("Bbl") per day ("Bbl/d"), respectively, compared to 355.2 MMcf/d and 5,063 Bbl/d, respectively, in 1994.
Seagull's principal gas and oil producing properties include the following:
(*) The equivalent of one billion cubic feet ("Bcfe") of natural gas. Liquids are converted to gas at a ratio of one barrel of liquids per six Mcf ("Mcf" represents one thousand cubic feet) of gas, based on relative energy content.
For additional information relating to the Company's gas and oil reserves, based substantially upon reports of DeGolyer and MacNaughton (for the years ended December 31, 1995, 1994 and 1993), Netherland, Sewell & Associates, Inc. (for the years ended December 31, 1994 and 1993) and Ryder Scott Company (for the years ended December 31, 1994 and 1993), independent petroleum engineers (collectively the "Engineers"), see Note 7 of the Consolidated Financial Statements included in the Company's 1995 Annual Report to Shareholders and as part of Exhibit 13 attached hereto. The Engineers provided the estimates of "proved developed and undeveloped reserves" and "proved developed reserves" at the beginning and end of each of the three years included in Note 7. Under "Standardized Measure of Discounted Future Net Cash Flows" in Note 7, the Engineers provided all information except "discounted income taxes" and "standardized measure of discounted future net cash flows". All information in Note 7 not provided by the Engineers was supplied by the Company. As required, Seagull also files estimates of gas and oil reserve data with various governmental regulatory authorities and agencies. The basis for reporting reserves to these authorities and agencies, in some cases, may not be comparable. However, the difference in estimates does not exceed 5%.
The future results of this segment will be affected by the market prices of natural gas and liquids. The availability of a ready market for gas and liquids products in the future will depend on numerous factors beyond the control of the Company, including weather, production of other natural gas and liquids products, imports,
marketing of competitive fuels, proximity and capacity of gas and liquids pipelines and other transportation facilities, demand for storage refills, any oversupply or undersupply of gas and liquids products, the regulatory environment and other regional and political events, none of which can be predicted with certainty. As in the past, the Company expects to continue curtailing a portion of its gas production whenever prices are deemed to be below acceptable levels.
GAS AND OIL DRILLING ACTIVITIES
Seagull's gas and oil exploratory and developmental drilling activities are as follows for the periods indicated. Totals shown in each category include wells completed as productive wells and wells abandoned as dry holes. A well is considered productive for purposes of the following table if it justifies the installation of permanent equipment for the production of gas or oil. A well is deemed to be a dry hole if it is determined to be incapable of commercial production. The term "gross wells" means the total number of wells in which Seagull owns an interest, while the term "net wells" means the sum of the fractional working interests Seagull owns in gross wells.
From January 1, 1996 through March 25, 1996, the Company drilled 14 gross (5.97 net) successful development wells in 15 attempts (6.97 net). As of late March, the Company had seven gross (3.26 net) exploratory wells and 18 gross (9.79 net) development wells in progress or being evaluated. As of the beginning of 1996, the Company had an inventory of approximately 100 exploratory prospects.
PRODUCTION
The following table summarizes the Company's production, average sales prices and lifting costs for the periods indicated:
(1) Thousands of barrels ("Mbbl"). (2) The equivalent of one thousand cubic feet ("Mcfe") and one million cubic feet ("MMcfe") of natural gas. (3) Average sales prices are before deduction of production, severance, and other taxes. (4) Lifting costs represent costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among other things, repairs and maintenance, workover expenses, labor, materials, supplies, property taxes, insurance, severance taxes and transportation costs. (5) The Canadian properties were acquired on January 4, 1994 in connection with the purchase of Seagull Canada.
The following table sets forth information regarding the number of productive wells in which the Company held a working interest at December 31, 1995. Productive wells are either producing wells or wells capable of commercial production although currently shut-in. One or more completions in the same borehole are counted as one well.
(*) Includes 333 gross (131.19 net) and 441 gross (282.20 net) gas wells with multiple completions for the United States and Canada, respectively.
For additional information relating to gas and oil producing activities, see Note 7 of the Consolidated Financial Statements included in the Company's 1995 Annual Report to Shareholders and as part of Exhibit 13 attached hereto.
DEVELOPED AND UNDEVELOPED GAS AND OIL ACREAGE
As of December 31, 1995, the Company owned working interests in the following developed and undeveloped gas and oil acreage:
(*) When describing acreage on drilling locations, the term "net" refers to the total acres on drilling locations in which the Company has a working interest, multiplied by the percentage working interest owned by the Company.
Additionally, as of December 31, 1995, the Company owned mineral and/or royalty interests in 225,347 gross (32,129 net) developed and 327,302 gross (67,361 net) undeveloped gas and oil acres.
COMPETITION
The Company's competitors in gas and oil exploration, development, production and marketing include major oil companies, as well as numerous independent oil and gas companies, individuals and drilling programs. Some of these competitors have financial and personnel resources substantially in excess of those available to the Company and, therefore, the Company may be placed at a competitive disadvantage. The Company's success in discovering reserves will depend on its ability to select suitable prospects for future exploration in today's competitive environment.
MARKETS
The Company utilizes a variety of commodity derivative contracts to achieve more predictable cash flows and to reduce its exposure to fluctuations in gas and oil prices for portions of its gas and oil production . As of March 26, 1996, the Company had entered into commodity derivative contracts for as much as 150,000 Mcf of natural gas per day. The Company's natural gas production is equal to approximately 360,000 Mcf per day. On a Mcfe basis, the Company's production as of March 26, 1996 was approximately 40% hedged. The terms of the Company's derivative contracts range from one to seven months. Of the total volume of production that has been hedged, over 80% has been hedged in a manner which only limits the Company's exposure to price decreases while allowing it to benefit from expected price increases. Seagull expects to continue to leave the majority of its own E&P production either unhedged or protected only from price decreases so that it can benefit from expected gas price strengthening. The Company accounts for its commodity derivative contracts as hedging activities and, accordingly, gains or losses are included in revenues when the commodities are produced. See Note 11 to the Company's Consolidated Financial Statements. The Company's production is sold in the spot market, as well as to local distribution companies, other marketing firms and end users under longer term contracts, typically with six-month to one-year terms.
Most of the Company's natural gas is transported through gas gathering systems and gas pipelines which are not owned by the Company. Transportation space on such gathering systems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to such facilities or due to such space being utilized by other gas shippers with priority transportation agreements. While the Company has not experienced any inability to market its natural gas, if transportation space is restricted or is unavailable, the Company's cash flow from the affected properties could be adversely affected.
REGULATION
The availability of a ready market for natural gas and oil production depends upon numerous regulatory factors beyond the Company's control. These factors include regulation of natural gas and oil production, federal and state regulations governing environmental quality and pollution control and state limits on allowable rates of production by a well or proration unit. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and oil produced by assigning allowable rates of production and control contamination of the environment.
Regulation of Natural Gas and Oil Exploration and Production. Exploration and production operations of the Company are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate
wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilling and the plugging and abandonment of wells. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production requirements regarding the ratability of production. With respect to the establishment of maximum production rates from natural gas wells, certain producing states, in an attempt to limit production to market demand, have recently adopted (Texas and Oklahoma) or are considering adopting (Louisiana) measures that alter the methods previously used to prorate gas production from wells located in these states. For example, the new Texas rules provide for reliance on information filed monthly by well operators, in addition to historical production data for the well during comparable past periods, to arrive at an allowable. This is in contrast to historic reliance on forecasts of upcoming takes filed monthly by purchasers of natural gas in formulating allowables, a procedure which resulted in substantial excess allowables over volumes actually produced. The Company cannot predict whether other states will adopt similar or other procedures for prorating gas production. The effect of these regulations is to limit the amounts of natural gas and oil the Company's operator or the Company can produce from its wells, and to limit the number of wells or the locations at which the Company can drill. Legislation affecting the oil and gas industry also is under constant review for amendment or expansion. Generally, state-established allowables have been influenced by overall natural gas market supply and demand in the United States, as well as the specific "nominations" for natural gas from the parties who produce or purchase gas from the field and other factors deemed relevant by the agency. The Company cannot predict whether further changes will be made in how these states set allowables or what impact, if any, such further changes might have.
Natural Gas Marketing and Transportation. Federal legislation and regulatory controls in the United States have historically affected the price of the natural gas produced by the Company and the manner in which such production is marketed. The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the Federal Energy Regulatory Commission (the "FERC"). Although maximum selling prices of natural gas were formerly regulated, on July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol Act") was enacted, which terminated wellhead price controls on all domestic natural gas on January 1, 1993, amended the NGPA to remove completely by January 1, 1993 price and nonprice controls for all "first sales" of natural gas, which will include all sales by the Company of its own production; consequently, sales of the Company's natural gas currently may be made at market prices, subject to applicable contract provisions. The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act.
The FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by the Company, as well as the revenues received by the Company for sales of such natural gas. Since the latter part of 1985, the FERC has endeavored to make interstate natural gas transportation more accessible to gas buyers and sellers on an open and nondiscriminatory basis. The FERC's efforts have significantly altered the marketing and pricing of natural gas. Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B (collectively, "Order No. 636"), which, among other things, require interstate pipelines to "restructure" to provide transportation separate or "unbundled" from the pipelines' sales of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all gas supplies. Order No. 636 has been implemented through negotiated settlements in individual pipeline service restructuring proceedings. In many instances, the result of the Order No. 636 and related initiatives has been to substantially reduce or bring to an end the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. The FERC has issued final orders in virtually all
pipeline restructuring proceedings, and commenced a series of reviews to determine whether refinements are required regarding individual pipeline implementations of Order No. 636.
Although Order No. 636 does not regulate natural gas producers such as the Company, the FERC has stated that Order No. 636 is intended to foster increased competition within all phases of the natural gas industry. It is unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on the Company and its natural gas marketing efforts. In addition, numerous petitions seeking judicial review of Order No. 636 are pending. Numerous parties have also sought review of FERC orders implementing Order No. 636 on individual pipeline systems. Order No. 636 could be reversed in whole or in part as a result. Although Order No. 636, assuming it is upheld in its entirety in its current form, would provide the Company with additional market access and more fairly applied transportation service rates, terms and conditions, it could also subject the Company to more restrictive pipeline imbalance tolerances and greater penalties for violation of those tolerances. The Company does not believe, however, that it will be affected by any action taken with respect to Order No. 636 materially different than other natural gas producers and marketers with which it competes.
Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become effective, or their effect, if any, on the Company's operations. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering has received greater regulatory scrutiny at both the state and federal levels as the pipeline restructuring under Order No. 636 continues. For example, Oklahoma enacted a prohibition against discriminatory gathering rates, and certain Texas regulatory officials have expressed interest in evaluating similar rules in Texas.
Offshore Leasing. Certain operations the Company conducts are on federal oil and gas leases, which the Minerals Management Service ("MMS") administers. The MMS issues such leases through competitive bidding. These leases contain relative standardized terms and require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA") (which are subject to change by the MMS). For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the Outer Continental Shelf ("OCS") to meet stringent engineering and construction specifications, and has recently proposed additional safety-related regulations concerning the design and operating procedures for OCS production platforms and pipelines. The MMS also has issued regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met.
In addition, the MMS is conducting an inquiry into certain contract settlement agreements from which producers on MMS leases have received settlement proceeds that are royalty bearing and the extent to which producers have paid the appropriate royalties on those proceeds. The restructuring of oil and gas markets has resulted in a shifting of markets downstream from the wells. Deregulation has so altered the marketplace that lessors, including the MMS, are reevaluating the methods of valuation of gas for royalty purposes.
In Canada, exploration, production and development activities are governed by federal and provincial laws which subject operators to extensive controls and regulations. Exports of gas and oil across interprovincial borders or on pipelines which connect to United States pipelines are governed by the National Energy Board and each province has its own laws governing the operations of producers and protection of the environment.
PIPELINE AND MARKETING
Pipeline and marketing operations include the marketing of Seagull's own and third-party gas, oil and natural gas liquids, as well as gas gathering and gas processing. Seagull is also involved in pipeline engineering, design, construction and operation. Revenue from the pipeline and marketing segment accounted for 9%, 10% and 11% of the Company's consolidated revenues for 1995, 1994 and 1993, respectively.
On September 25, 1995, the Company and three other sellers completed the sale of their disparate interests in 19 natural gas gathering systems and a gas processing plant. Together with the sale of another of Seagull's gas processing plants, the assets sold represent substantially all of the Company's gas gathering and gas processing assets.
GAS MARKETING
The Company actively provides marketing services geared toward matching gas supplies available in the major producing areas with attractive markets available in the Midwest, Northeast, Mid-Atlantic, Appalachian and Texas/Louisiana Gulf Coast areas. The matching process includes arranging transportation on a network of open-access pipelines on a firm or interruptible basis. Seagull contracts to provide natural gas and oil to various customers and aggregates supplies from various sources including third-party producers, marketing companies, pipelines, financial institutions and the Company's own production. In 1995, the Company initiated an active risk management program for both its own E&P production and third party activities, utilizing such derivative financial instruments as futures contracts, options and swaps. The primary objective of the risk management program is to help ensure more stable cash flow. However, Seagull expects to leave the majority of its own E&P production either unhedged or protected only from price decreases so that it can benefit from expected gas price strengthening. The risk management program is also an important part of the Company's third party marketing efforts, allowing the Company to convert a customer's requested price to a price structure that is consistent with the Company's overall pricing stragegy.
Marketing profit margins are often small due to competition, and results can vary significantly from month to month. Large amounts of working capital are involved for relatively small net margins, which makes working capital management critical. The Company has policies and procedures in place that are designed to minimize any potential risk of loss from these transactions. These policies and procedures are reviewed and updated periodically by the Company's management.
PIPELINE OPERATIONS AND CONSTRUCTION
Seagull operates certain pipelines owned by other companies. In some cases the operating agreements provide for reimbursement of expenses incurred in connection with operations plus a profit margin. In other cases the Company receives a negotiated annual fee.
The Company also builds pipelines for other companies for which it receives construction fees that are fixed, cost-plus or a combination of both. In June 1995, Seagull was engaged to build an approximately 114-mile onshore pipeline. The project began in late 1995 and Seagull will operate the new pipeline upon
completion. The Company recognized operating profit in 1994 and 1993 on another gas pipeline construction project, which was completed in the first quarter of 1994.
COMPETITION
The Company actively competes with numerous other companies for the construction and operation of short and medium length pipelines. The Company's competitors include oil companies, other pipeline companies, natural gas gatherers and petrochemical transporters, many of which have financial resources, staffs and facilities substantially larger than those of the Company. In addition, many of the Company's gas purchasers are also competitors or potential competitors in the sense that they have extensive pipeline-building capabilities and experience and generally operate large pipeline systems of their own. Seagull believes that its ability to compete will depend primarily on its ability to complete pipeline projects quickly and cost effectively, and to operate pipelines efficiently.
The Company's gas marketing activities are in competition with numerous other companies offering the same services. Some of these competitors are affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users. The Company believes its ability to compete depends upon building strong relationships with producers and end-users by consistently purchasing and supplying gas at competitive prices.
ALASKA TRANSMISSION AND DISTRIBUTION
The Company operates in Alaska through ENSTAR Natural Gas Company ("ENG"), a division of the Company, and Alaska Pipeline Company ("APC"), an Alaska corporation and a wholly owned subsidiary of the Company. ENG and APC are currently operated as a single business unit, ENSTAR Alaska ("ENSTAR Alaska"), and are regulated as a single operating unit by the Alaska Public Utilities Commission (the "APUC"). APC engages in the intrastate transmission of natural gas in South-Central Alaska. ENG engages in the distribution of natural gas in Anchorage and other nearby communities in Alaska and is APC's only customer. Revenues from the natural gas transmission and distribution segment accounted for 29%, 26% and 29% of the Company's consolidated revenues for 1995, 1994 and 1993, respectively.
ENSTAR Alaska's predecessor was formed in 1959 and began serving the Anchorage area with natural gas in 1961. Five years later, in 1966, the predecessor became one of the original entities that formed Alaska Interstate Company, a newly organized public company the shares of which were traded on the New York Stock Exchange. Alaska Interstate Company changed its name to ENSTAR Corporation in 1982.
In 1985, the Company purchased ENSTAR Alaska for $55 million in cash plus $10 million in the form of a seven-year unsecured, 10% subordinated note. At the time of the acquisition, APC had outstanding debt of approximately $65 million. The transaction received the final approval of the APUC in June 1985.
GAS TRANSMISSION SYSTEM
APC owns and operates the only natural gas transmission lines in its service area that are operated for utility purposes. The pipeline transmission system is composed of approximately 277 miles of 12- to 20-inch diameter pipeline and approximately 71 miles of smaller diameter pipeline. The system's present design delivery capacity is approximately 410 MMcf/d. The average throughput of the system in 1995, 1994 and 1993 was 122, 121 and 110 MMcf/d, respectively.
In September 1995, APC entered into a 33-year agreement to lease a 60-mile, 8-inch diameter pipeline between Anchorage, Alaska and Whittier, Alaska. Conversion of the pipeline to natural gas is expected to be completed in 1996. The new pipeline is expected to account for nearly 1,000 new customers over the next two to three years.
GAS DISTRIBUTION SYSTEM
ENG distributes natural gas through approximately 1,995 miles of gas mains to approximately 92,100 residential, commercial, industrial and electric power generation customers within the cities and environs of Anchorage, Eagle River, Palmer, Wasilla, Soldotna, Kenai and the Nikiski area of the Kenai Peninsula, Alaska. During the year ended December 31, 1995, ENG added approximately 33 miles of new gas distribution mains, installed 1,800 new service lines and added approximately 2,000 net customers. ENG anticipates relatively modest growth in its residential customer base and will install additional main and service lines to accommodate this growth.
ENG distributes gas to its customers under tariffs and contracts which provide for varying delivery priorities. ENG's business is seasonal with approximately 67% of its revenues earned in the first and fourth quarters of each year.
In 1995, purchase/resale volumes represented 60% of ENG's throughput and 85% of ENG's operating margin. The remaining volumes are transported for power, industrial and large commercial customers for a transportation fee.
ENG's five largest customers are the Municipality of Anchorage; ARCO Alaska, Inc.; Aurora Gas, Inc.; the State of Alaska; and Unocal Corporation. Together, they account for about $8.6 million in annual operating margin and about 17.6 Bcf per year in volumes, which represent approximately 17% and 40%, respectively, of ENG totals.
GAS SUPPLY
In May 1988, APC entered into a gas purchase contract (the "Marathon Contract") with Marathon Oil Company ("Marathon") providing for the delivery of approximately 450 Bcf of gas in the aggregate. The Marathon Contract is a "requirements" contract with no specified daily deliverability or annual take-or-pay quantities. APC has agreed to purchase and Marathon has agreed to deliver all of APC's gas requirements in excess of those provided for in other presently existing gas supply contracts, subject to certain exceptions, until the commitment has been exhausted and without limit as to time; however, Marathon's delivery obligations are subject to certain specified annual limitations after 2001. The contract has a base price of $1.55 per Mcf plus reimbursements for any severance taxes and other charges. The base price is subject to annual adjustment based on changes in the price of certain traded oil futures contracts. During 1995, the cost of gas purchased under the Marathon Contract averaged $1.74 per Mcf, including reimbursements for severance taxes. The Marathon Contract, as amended in 1991, has been approved by the APUC.
Effective January 1, 1992, APC amended a gas purchase contract with Shell Oil Company and ARCO Alaska, Inc. (the "Shell Contract") to extend the term of the contract through the year 2009, modify the price, delivery and the deliverability provisions and provide procedures for reducing take-or-pay volumes for the effect of APC sales volumes that are displaced by gas sales made by others. The Shell Contract provides for the delivery of up to approximately 220 Bcf of gas. The amendments revised the price to a base price of $1.97 per Mcf plus reimbursements for any severance taxes and an annual adjustment based on changes in the price of certain traded oil futures contracts from the relevant base price. Certain portions of the gas purchased
under the amendments may be priced under a pricing term similar to the Marathon Contract. The 1995 price under the Shell Contract, after application of contractual adjustments, averaged $1.71 per Mcf, including reimbursements for severance taxes. The amendments provide for varying deliverability, before displaced gas sales adjustments, up to a maximum of 110 MMcf/d through 1995, and take-or-pay quantities, before displaced gas sales adjustments, up to a maximum of 15 Bcf per year. The Shell Contract, as amended, has been approved by the APUC.
Combined, the Marathon and Shell Contracts will supply all of ENSTAR Alaska's gas supply requirements through the year 2001. After that time supplies will still be available under the contracts in accordance with their terms, but the annual limitations contained in the Marathon Contract will take effect. As a result, after 2001, at least a portion of ENSTAR Alaska's requirements are expected to be satisfied outside the terms of the contracts, as currently in effect.
Based on gas purchases during the twelve months ended December 31, 1995, which are not necessarily indicative of the volume of future purchases, gas reserves committed to APC under the Marathon and Shell Contracts would have a current reserve life index of approximately 15 years.
ENSTAR Alaska's average cost of gas sold in 1995, 1994 and 1993 was $1.75, $1.74 and $2.07 per Mcf, respectively. ENSTAR Alaska's average gas sales price in 1995, 1994 and 1993 was $3.41, $3.23 and $3.56 per Mcf, respectively.
As stated above, ENSTAR Alaska purchases all of its natural gas under long-term contracts in which the price is indexed to changes in the price of crude oil futures contracts. However, because ENSTAR Alaska's sales prices are adjusted to include the projected cost of its natural gas, there has been and is expected to be little or no impact on margins derived from ENSTAR Alaska's gas sales as a result of fluctuations in oil prices due to worldwide political events and changing market conditions.
ENSTAR Alaska has no material take-or-pay obligations and does not anticipate any such obligations in the foreseeable future.
COMPETITION
ENSTAR Alaska competes primarily with municipal and cooperative electric power distributors and with various suppliers of fuel oil and propane for the available energy market. There are also extensive coal reserves proximate to ENSTAR Alaska's operating area; however, such reserves are not presently being produced.
During the last seven years, ENSTAR Alaska's natural gas volumes delivered on a purchase/resale basis have declined. Beginning in 1989, several of its major customers began purchasing gas directly from gas producers or gas marketers. However, the APUC has approved tariffs allowing ENSTAR Alaska to transport these volumes for a transportation fee that approximates the margin that would have been earned had the customer remained a sales customer rather than becoming a transportation customer. Consequently, ENSTAR Alaska anticipates no adverse economic impact to result from these transportation arrangements.
If any other existing large customer of ENSTAR Alaska chooses to purchase gas directly from producers, ENSTAR Alaska would expect to collect a fee for transporting that gas equivalent to the margin earned on sales volumes for those customers because the large distance of remaining user facilities from producing fields would preclude the by-pass of ENSTAR Alaska's pipelines.
ENSTAR Alaska supplies natural gas to its customers at prices that at the present time economically preclude substitution of alternative fuels. Since the Shell Contract and the Marathon Contract include prices that fluctuate based on oil indices, a competitive margin favoring natural gas over oil-based energy sources is expected to continue. However, there is no assurance that the competitive advantage over other alternative fuels will not be reduced or eliminated by the development of new energy technology or by changes in the price of oil or refined products.
REGULATION
The APUC has jurisdiction as to rates and charges for gas sales, construction of new facilities, extensions and abandonments of service and certain other matters. Rates are generally designed to permit the recovery of the cost of providing service, including purchased gas costs, and a return on investment in plant. APC and ENG are regulated by the APUC on a combined basis as though they were a single entity. Because ENSTAR Alaska's operations are wholly intrastate, ENSTAR Alaska is not subject to or affected by Order 636 or any other economic regulation by the FERC.
As a result of a proceeding filed in 1984, which was concluded in May 1986, the APUC granted ENSTAR Alaska an aggregate rate increase of 20.27% and authorized a regulatory rate of return on common equity of 15.65%. ENSTAR Alaska has no significant regulatory issues pending before the APUC. Since its inception in 1961, ENSTAR Alaska has participated in only three formal rate proceedings.
CORPORATE
REGULATION
The Company is a "public utility company" within the meaning of the Public Utility Holding Company Act of 1935, as amended (the "1935 Act"). Accordingly, if any "company" (as defined for purposes of the 1935 Act and therefore including so-called "organized groups") becomes the owner of 10% or more of the Company's outstanding voting stock, that company would be required to register as a "holding company" under the 1935 Act, in the absence of an exemption of the type described below. Section 9(a)(2) also requires a person (including both individuals and "companies") to obtain prior approval from the Securities and Exchange Commission (the "SEC") in connection with the acquisition of 5% or more of the outstanding voting stock of a public utility if that person is also the owner of 5% or more of the outstanding voting stock of another public utility.
In March 1991, the Company filed in good faith with the SEC an application pursuant to Section 2(a)(8) of the 1935 Act, seeking a determination that Seagull was not subject to regulation as a "subsidiary company" of FMR Corp. (the "FMR Application"), which was then the owner of 2,805,624 shares (approximately 12.5% at such time) (shares adjusted for a 2-for-1 stock split of all the issued shares of the Company's common stock (the "Common Stock"), effected June 4, 1993) of the outstanding Common Stock. Under the 1935 Act, a company is a "subsidiary company" of a "holding company" if the "holding company" owns 10% or more of the total voting power of the "subsidiary company", unless the SEC determines otherwise. Based upon the most recent information furnished to the Company by FMR Corp., FMR Corp. was the beneficial owner (albeit within the meaning of Section 13(d) of the Securities Exchange Act of 1934) of 568,800 shares, which is less than 2% of the Common Stock as of December 31, 1995. However, although FMR Corp.'s ownership and control, within the meaning of the 1935 Act, has fallen below 10% of the outstanding voting stock of the Company, the Company does not currently intend to withdraw the FMR Application.
In December 1993, Seagull filed in good faith with the SEC an additional application pursuant to Section 2(a)(8) of the 1935 Act, seeking a determination that the Company was not subject to regulation as a "subsidiary company" of AXA Assurances I. A. R. D. Mutuelle, AXA Assurances Vie Mutuelle, Alpha Assurances I. A. R. D. Mutuelle, Alpha Assurances Vie Mutuelle, Uni Europe Assurance Mutuelle and AXA (collectively, the "Mutuelles AXA") and The Equitable Companies Incorporated ("Equitable") and their respective affiliates (collectively, the "Equitable Entities"), (the "Equitable Application"). At such time, the Equitable Entities beneficially owned 4,495,600 shares (approximately 12.5%) of Common Stock. Based upon the most recent information furnished to the Company by the Equitable Entities, the Equitable Entities were the beneficial owners (albeit within the meaning of Section 13(d) of the Securities Exchange Act of 1934) of 1,403,000 shares, which represents approximately 4% of the Common Stock as of December 31, 1995. However, although the Equitable Entities' ownership and control has fallen below 10% of the outstanding voting stock of the Company, the Company does not currently intend to withdraw the Equitable Application.
According to information provided by Wellington Management Company ("WMC"), WMC, in its capacity as investment adviser, may be deemed the beneficial owner of 3,712,200 shares (approximately 10%) of the Common Stock that are owned by numerous investment counseling clients, none of which is known to have such interest with respect to more than 5% of the class. WMC has shared voting power as to 2,405,000 shares and shared dispositive power as to 3,712,200 shares. Because WMC has shared voting power with respect to only 2,405,000 shares, and no voting power with respect to the remaining shares beneficially owned by WMC, it is deemed to own or control only these 2,405,000 shares (approximately 6.5%) for purposes of the 1935 Act.
Even if FMR Corp. or the Equitable Entities held 10% or more of the outstanding voting stock of the Company, as a result of its good faith filing of the two applications, the Company currently would not be subject to any obligation, duty or liability imposed by the 1935 Act, unless and until the SEC enters an order denying or otherwise adversely disposing of the applications. To date, no such order has been issued. The Company believes that the FMR Application and the Equitable Application ultimately should be granted.
ENVIRONMENTAL MATTERS
Seagull's operations are subject to federal, state and local laws and regulation governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments issue rules and regulations to implement and enforce such laws which are often difficult and costly to comply with and which carry substantial penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from the Company's operations. In addition, these laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist. State laws often require some form of remedial action to prevent pollution from former operations, such as pit closure and plugging abandoned wells.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.
Stricter standards in environmental legislation may be imposed on the oil and gas industry in the future. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and natural gas exploration and production wastes as "hazardous wastes" and make the reclassified wastes subject to more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Furthermore, although petroleum, including crude oil and natural gas, is exempt from CERCLA, at least two courts have recently ruled that certain wastes associated with the production of crude oil may be classified as "hazardous substances" under CERCLA and thus such wastes may become subject to liability and regulation under CERCLA, as described above. State initiatives to further regulate the disposal of oil and natural gas wastes are also pending in certain states, and these various initiatives could have a similar impact on the Company. Compliance with environmental requirements generally could have a material adverse effect upon the capital expenditures, earnings or competitive position of the Company. Although the Company has not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue in the future.
The Oil Pollution Act (the "OPA") requires persons responsible for "offshore facilities" to establish proof of financial responsibility to cover environmental cleanup and restoration costs likely to be incurred in connection with an oil spill. On August 25, 1993, the MMS published an advance notice of its intention to adopt a rule under the OPA that would define "offshore facilities" to include all oil and gas facilities that have the potential to affect "waters of the United States." The term "waters of the United States" has been broadly defined to include not only the waters of the Gulf of Mexico but also inland waterbodies, including wetlands, playa lakes and intermittent streams. Since the Company has many oil and gas facilities that could affect "waters of the United States," the Company would become subject to the financial responsibility rule if it is adopted as proposed. Under the proposed rule, financial responsibility could be established through insurance, guaranty, indemnity, surety bond, letter of credit, qualification as a self-insurer or a combination thereof. There is substantial opposition to the proposed rule throughout the oil and gas industry, and the MMS has informally indicated that it will not move forward with the adoption of the rule until Congress has had an opportunity to reconsider the financial responsibility requirements imposed under OPA. Absent Congressional action, the Company cannot predict the final form of any financial responsibility rule that may be adopted by the MMS under the OPA, but if the proposed rule were adopted no assurance can be given as to the Company's ability to comply with such rule or the costs of such compliance. On May 9, 1995, the U.S. House of Representatives passed a bill that would lower the financial responsibility requirements applicable to offshore facilities to $35 million (the current requirement under OCSLA). The bill allows the limit to be increased to $150 million if a formal risk assessment indicates the increase is warranted. It would also define "offshore facility" to include only OCS oil production, transportation and storage facilities, thus excluding inland or coastal oil and gas properties. A Senate bill that would provide the Coast Guard flexibility to establish liability limits that correspond to the facility's potential oil spill liability has been referred to the Senate Environmental and Public Works Committee. The Senate bill would reduce the scope of "offshore facilities" subject to this financial assurance requirement to those facilities seaward of the U.S. coastline that engaged in drilling for, producing or processing oil or that have the capacity to transport, store, transfer or handle more that 1,000 barrels of oil at a time. The Clinton Administration has indicated support for changes to the OPA financial responsibility requirements. Whether these legislative efforts will reduce the OPA financial responsibility requirements applicable to the Company cannot be determined at this time. In any event, the impact of any rule is not expected to be any more burdensome to the Company than it will be to other similarly situated companies involved in oil and gas exploration and production.
OPA imposes a variety of additional requirements on "responsible parties" for oil and gas facilities or vessels related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The "responsible party" includes the owner or operator of an onshore facility or vessel or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil spill removal costs and a variety of public and private damages from oil spills. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill is caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If a party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. OPA establishes a liability limit for offshore facilities of all removal costs plus $75 million. Few defenses exist to the liability for oil spills imposed by OPA. OPA also imposes other requirements on facility operators, such as the preparation of an oil spill contingency plan. Failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement actions.
In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating in the OCS. Specific design and operation standards may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or private prosecution.
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions and strict controls regarding the discharge of pollutants to state and federal waters. The FWPCA provides for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous substances in reportable quantities and, along with the OPA, imposes substantial potential liability for the costs of removal, remediation and damages. State laws for the control of water pollution also provide varying civil, criminal and administrative penalties and liabilities in the case of a discharge of petroleum or its derivatives into state waters. Within the next few years, both state water discharge regulations and the federal permits are expected to prohibit the discharge of produced water and sand, and some other substances related to the oil and gas industry, to coastal waters. Although the costs to comply with zero discharge mandates under federal or state law may be significant, the entire industry will experience similar costs and the Company believes that these costs will not have a material adverse impact on the Company's financial conditions and operations. Some oil and gas exploration and production facilities are required to obtain permits for their storm water discharges. Costs may be associated with treatment of wastewater or developing storm water pollution prevention plans. Further, the Coastal Zone Management Act authorizes state implementation and development of programs of management measures for non-point source pollution to restore and protect coastal waters.
Many states in which the Company operates have recently begun to regulate naturally occurring radioactive materials ("NORM") and NORM wastes that are generated in connection with oil and gas exploration and production activities. NORM wastes typically consist of very low-level radioactive substances that become concentrated in pipe scale and in production equipment. State regulations may require the testing of pipes and production equipment for the presence of NORM, the licensing of NORM-contaminated facilities and the careful handling and disposal of NORM wastes. The Company believes that the growing regulation of NORM will have a minimal effect on the Company's operations because the Company generates only a very small quantity of NORM on an annual basis.
EMPLOYEES
As of March 1, 1996, the Company had 637 full time employees. In addition to the services of its full time employees, the Company employs, as needed, the services of consulting geologists, engineers, regulatory consultants, contract pumpers and certain other temporary employees.
ENSTAR Alaska operates under collective bargaining agreements with separate bargaining units for operating and clerical employees. These units represent approximately 70% of ENSTAR Alaska's work force. Contracts effective April 1, 1992 were negotiated that set wages and work relationships extending to April 1, 1995 for the clerical bargaining unit and until April 1, 1996 for the operating bargaining unit. ENSTAR Alaska is in the process of renegotiating a collective bargaining agreement with the clerical bargaining unit. The Company is not a party to any other collective bargaining agreements. The Company has never had a work stoppage.
The Company considers its relations with its employees to be satisfactory.
EXECUTIVE OFFICERS OF THE COMPANY
The executive officers of the Company, each of whom has been elected to serve until his or her successor is elected and qualified, are as follows:
The business experience of each of the executive officers named above who has held the position(s) set forth opposite his or her name for less than five years, is as follows:
Mr. Elias joined the Company as Executive Vice President in April 1993 and was named Executive Vice President and Chief Operating Officer in January 1995. For the previous 30 years, he served in a variety of positions for Amoco Production Company and its parent, Amoco Corporation, most recently as Group Vice President of Worldwide Natural Gas for Amoco Production Company.
Mr. Shower joined the Company as Senior Vice President and Chief Financial Officer in March 1992 and was named Executive Vice President of the Company in December 1993. He served as Senior Vice President, Corporate Development for Albert Fisher, Inc. from 1991 to February 1992. From 1990 to 1991, he was Vice President and Chief Financial Officer with AmeriServ Food Company. From 1986 to 1990, he served as a Managing Director, Corporate Finance, for Lehman Brothers Inc., formerly Shearson Lehman Hutton Inc. Mr. Shower will retire as an executive officer and employee of the Company prior to the Annual Meeting of Shareholders on May 14, 1996.
Mr. Goodpasture joined the Company and has been an executive officer since 1981 and was named President of Seagull Pipeline Company in March 1990, and Senior Vice President, Pipelines and Marketing, in December 1992.
Mr. McConn was named Vice President, Exploration and Production of the Company in January 1990 and President of Seagull Energy E&P Inc. in March 1991. In December 1992, he was named Senior Vice President, Exploration and Production.
Mr. Bridges joined the Company as Corporate Controller in August 1990, and was named Vice President and Controller in December 1992.
Ms. Hartrick joined Seagull as Staff Counsel in 1987 and became Chief Counsel in 1989. She was named Chief Counsel and Vice President, Environmental Affairs in December 1992.
ITEM 2.
ITEM 2. PROPERTIES
Incorporated herein by reference to Item 1 of this Annual Report on Form 10-K.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Gulf Coast Vacuum Site. On March 19, 1993, Franks Petroleum, Inc. ("Franks") submitted a claim to Seagull Mid-South Inc., a subsidiary of the Company ("Seagull Mid-South"), for a portion of Franks' costs incurred in connection with the Gulf Coast Vacuum Services Superfund Site (the "GCV Site") in Vermilion Parish, Louisiana. The United States Environmental Protection Agency Region 6 (the "EPA") currently is seeking the cleanup of the GCV Site under the authority of the federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA").
Franks previously has been identified as a potentially responsible party ("PRP") at the GCV Site as a result of Franks' arrangements with the former operator of the GCV Site to transport wastes from various oil and gas leases owned or operated by Franks in trucks owned by the GCV Site operator. Franks' claim against Seagull Mid-South asserts that some of the wastes hauled by the GCV Site operator on behalf of Franks came from a gas well owned by Seagull Mid-South.
On February 9, 1993, the EPA also sent a notice to HO&M, a subsidiary of the Company, indicating that HO&M may be a PRP at the GCV Site. Based upon the Company's investigation of this claim, the Company believes that the basis for HO&M's alleged liability is a series of transactions between HO&M and the operator of the GCV Site that occurred during 1979 and 1980.
The EPA's cleanup cost estimate of the GCV Site is in the range of $17 million, although other unofficial estimates indicate the cost may be higher. Under certain circumstances, liability under CERCLA is joint and several, although parties whose liability is joint and several have contribution rights against each other under CERCLA. Nevertheless, if Seagull Mid-South and/or HO&M is found to be a responsible party at the GCV Site, the Company believes that its liability is unlikely to be material to its financial condition, results of operations or cash flows because of the large number of potentially responsible parties at the GCV Site and the relative amount of contamination, if any, that may have been caused at the GCV Site by the disposal of wastes arising from the wells identified in the claims.
Marco of Iota Superfund Site. In June 1995, the EPA advised HO&M that it had been identified as a PRP at the Marco of Iota Superfund Site ("Iota Site") located in Iota, Louisiana. The EPA is currently seeking the cleanup to the Iota Site under the authority of CERCLA. The EPA's cleanup cost estimate of the Iota Site is in the range of $5 million.
Based on the information provided by the EPA, the basis for HO&M's alleged liability is a series of transactions between HO&M and the operator of the Iota Site that occurred during the early 1970s through the 1980's, long before Seagull acquired HO&M from Tenneco, Inc.
In January 1996, the Company entered into a deminimus settlement agreement with the EPA, which established a settlement payment of approximately $15,000. Pursuant to the provisions of the Stock Purchase Agreement dated as of October 24, 1988 between the Company and Tenneco, Inc., Tenneco has assumed the monetary liability for this matter.
Other. The Company is a party to ongoing litigation in the normal course of business or other litigation with respect to which the Company is indemnified pursuant to various purchase agreements or other contractual arrangements. Management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management believes that the effect on its financial condition, results of operations or cash flows, if any, will not be material.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS
A. The Company's Common Stock (the "Common Stock") is traded on the New York Stock Exchange under the ticker symbol SGO. The high and low sales prices on the New York Stock Exchange Composite Tape for each quarterly period during the last two fiscal years were as follows:
B. As of March 20, 1996, there were approximately 2,659 holders of record of Common Stock.
C. Seagull has not declared any cash dividends on its Common Stock since it became a public entity in 1981. The decision to pay Common Stock dividends in the future will depend upon the Company's earnings and financial condition and such other factors as the Company's Board of Directors deems relevant. The Company's credit agreement (the "Credit Agreement") restricts the Company's declaration or payment of dividends on and repurchases of Common Stock unless each of the following tests have been met and after making such dividend payment such tests continue to be met: (i) aggregate dividend payments attributable to ENSTAR Alaska Stock must not exceed $20 million plus 100% of the net income of ENSTAR Alaska on a cumulative basis from January 1, 1994, (ii) aggregate dividend payments, other than those permitted under (i) above or on up to $150 million in preferred stock, must not exceed $20 million plus 33 1/3% of the net income of the Company (excluding net income of ENSTAR Alaska) on a cumulative basis from January 1, 1994 plus 100% of the net income of ENSTAR Alaska on a cumulative basis for such period less any dividend payments allowed under (i) above, (iii) the aggregate amount of outstanding loans under the Credit Agreement, together with all other senior indebtedness of Seagull and its subsidiaries (excluding APC) then outstanding, must not exceed the Borrowing Base and (iv) no Default or Event of Default shall have occurred and be continuing. The foregoing restrictions do not apply to dividends payable solely in the form of additional shares of Common Stock or to dividends payable on up to $150 million of preferred stock. The capitalized terms used herein to describe the restrictions contained in the Credit Agreement have the meanings assigned to them in the Credit Agreement. Under the most restrictive of these tests, as of December 31, 1995, approximately $34.6 million was available for
payment of dividends (other than the stock dividends described above) or repurchase of Common Stock. In addition, certain debt instruments of APC restrict the ability of APC to transfer funds to the Company in the form of cash dividends, loans or advances. For a description of such restrictions, reference is made to Note 9 of the Consolidated Financial Statements included in the Company's 1995 Annual Report to Shareholders and as part of Exhibit 13 attached hereto.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Incorporated herein by reference to the Selected Financial Data included in the Company's 1995 Annual Report to Shareholders and as part of Exhibit 13 attached hereto.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Incorporated herein by reference to Management's Discussion and Analysis of Financial Condition and Results of Operations included in the Company's 1995 Annual Report to Shareholders and as part of Exhibit 13 attached hereto.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Incorporated herein by reference to the Consolidated Financial Statements and Supplementary Data included in the Company's 1995 Annual Report to Shareholders and as part of Exhibit 13 attached hereto.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Incorporated herein by reference to "Election of Directors" included in the Proxy Statement for the Company's Annual Meeting of Shareholders to be held on May 14, 1996 (the "Proxy Statement"). See also "Executive Officers of the Company" included in Part I of this Annual Report on Form 10-K, which is incorporated by reference herein.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated herein by reference to "Election of Directors --Executive Compensation--Summary Compensation Table," "--Compensation Arrangements," "--Option Exercises and Fiscal Year-End Values," "--Option Grants," "--Executive Supplemental Retirement Plan," "--ENSTAR Natural Gas Company Supplemental Executive Retirement Plan" and "--ENSTAR Natural Gas Company Retirement Plan"; and "Election of Directors-Compensation of Directors" included in the Proxy Statement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated herein by reference to "Principal Shareholders" and "Election of Directors--Security Ownership of Directors and Management" included in the Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated herein by reference to "Election of Directors--Certain Transactions" included in the Proxy Statement.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. FINANCIAL STATEMENTS:
The following Consolidated Financial Statements and Independent Auditors' Report thereon are included in the Company's 1995 Annual Report to Shareholders and as part of Exhibit 13 attached hereto, and are incorporated herein by reference:
Consolidated Financial Statements
Notes to Consolidated Financial Statements
Independent Auditors' Report
2. SCHEDULES:
All schedules have been omitted because the required information is insignificant or not applicable.
____________________________ * Filed herewith. # Identifies management contracts and compensatory plans or arrangements.
(B) REPORTS ON FORM 8-K
There were no Reports on Form 8-K filed during the three months ended December 31, 1995.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
EXHIBIT INDEX
____________________ * Filed herewith. # Identifies management contracts and compensatory plans or arrangements.