Item 1. Business
Seagull Energy Corporation (the "Company" or "Seagull") is an international oil and gas company engaged primarily in exploration and development activities in the United States, Canada, Egypt, Cote d'Ivoire, Indonesia and the Russian Republic of Tatarstan. It also transports, distributes and markets natural gas, liquids products and petrochemicals in the U.S. and Canada. 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 growth in the Company's exploration and development activities has been achieved primarily through acquisitions: HO&M in 1988, Houston Oil Trust in 1989, Wacker Oil Inc. in 1990, certain oil and gas assets from Mesa Limited Partnership in 1991, Arkla Exploration in 1992, Novalta Resources Inc. in 1994, and two Egyptian concessions purchased from units of Exxon Corporation in 1996.
On October 3, 1996, the shareholders of Seagull and Global Natural Resources Inc. ("Global") approved a merger of a wholly owned subsidiary of Seagull into Global (the "Global Merger"). Pursuant to the Global Merger, each share of Global common stock was converted into 0.88 shares of Seagull common stock with approximately 26.3 million shares issued to the shareholders of Global. The Global Merger was accounted for as a pooling of interests. Therefore all financial information and statistics have been restated. 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 13 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 1996 Annual Report to Shareholders and as part of Exhibit 13 attached hereto.
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 Seagull believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward looking statements include political developments in foreign countries, federal and state regulatory developments, the timing and extent of changes in commodity prices, the timing and extent of success in discovering, developing and producing or acquiring oil and gas reserves and conditions of the capital and equity markets during the periods covered by the forward looking statements.
OIL AND GAS OPERATIONS
Seagull's Oil and Gas Operations ("O&G") segment is the Company's primary business segment and is comprised of the following material direct and indirect wholly owned subsidiaries of the Company: Seagull Energy E&P Inc.; Global Natural Resources Inc.; Seagull Midcon Inc.; Seagull Mid-
South Inc., Seagull Energy Canada Ltd. ("Seagull Canada"), Seagull East Zeit Petroleum Ltd. and various other subsidiaries.
Natural gas is stated herein in billion cubic feet ("Bcf"), million cubic feet ("MMcf") or thousand cubic feet ("Mcf"). Oil, condensate and natural gas liquids ("NGL") are stated in barrels ("Bbl"). MMcfe and Mcfe represent the equivalent of one million and one thousand cubic feet of natural gas, respectively. Oil, condensate and NGL are converted to gas at a ratio of one barrel of liquids per six Mcf of gas, based on relative energy content. MBOE and BOE represent one thousand barrels of oil equivalent and one barrel of oil equivalent, respectively, with six Mcf of gas converted to one barrel of liquid. 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.
Revenues from the O&G segment accounted for 81%, 76% and 78% of the Company's consolidated revenues for 1996, 1995 and 1994, respectively. Production of gas and liquids for 1996 averaged 391.5 MMcf per day ("MMcf/d") and 13,409 Bbl per day ("Bbl/d"), respectively, compared to 382.6 MMcf/d and 8,753 Bbl/d, respectively, in 1995. Oil production in 1996 increased from the prior year primarily as a result of increased production in Egypt and Cote d'Ivoire. In September 1995, the Company sold substantially all of its gas gathering and processing assets. With the sale of these assets, Seagull's former Exploration and Production segment and the Pipeline and Marketing segment have been reclassified into Oil and Gas Operations.
Seagull's principal oil and gas producing properties include the following:
For additional information relating to the Company's oil and gas reserves, based substantially upon reports of DeGolyer and MacNaughton, Netherland, Sewell & Associates, Inc. and Ryder Scott Company, independent petroleum engineers (collectively the "Engineers"), see Note 15 of the Consolidated Financial Statements included in the Company's 1996 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 15. Under "Standardized Measure of Discounted Future Net Cash Flows" in Note 15, the Engineers provided all information except "discounted income taxes" and "standardized measure of discounted future net cash flows." All information in Note 15 not provided by the Engineers
was supplied by the Company. The Company's reserve estimates in Indonesia have been obtained by the Company from a public source which, although not independently verified, the Company believes to be reliable. As required, Seagull also files estimates of oil and gas 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 and the degree of internal exploration and exploitation success. 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, international and political events, none of which can be predicted with certainty.
UNITED STATES
Most of the Company's proved oil and gas reserves and annual production are contributed by properties in the United States. These properties are generally located in three geographic areas -- the Mid-South region, the Mid-Continent region and the Gulf Coast region. The Company's capital program for 1997 is designed to hold domestic reserves and deliverability to approximately year-end 1996 levels. In addition, Seagull will continue to pursue small acquisitions to increase its domestic reserves and deliverability. Capital expenditures, excluding small acquisitions, for the Company's domestic activities are expected to be approximately $114 million for 1997, including $50 million for exploration, $57 million for development and $7 million for leaseholds.
Mid-South Region
The Company's Mid-South properties are situated generally in the Arkoma Basin of eastern Oklahoma and western Arkansas and the Arklatex area of east Texas and northwest Louisiana. Combined, these two areas held proved reserves totaling 77,622 MBOE at December 31, 1996, 30% of the Company's total proved reserves. These proved reserves are contained in some 80 fields in which there are approximately 1,300 producing wells. Production from these two areas at December 31, 1996, averaged approximately 28 MBOE per day.
The Company's continuing expenditures in the Mid-South region are devoted principally to exploitation activities. Such expenditures in 1996, which totaled $34.0 million, were devoted to 81 development wells. Plans for 1997 call for 69 development wells and capital spending of about $31 million. The Company estimates that it held approximately 313 development drilling locations in the area at the end of 1996.
Mid-Continent Region
The Company's Mid-Continent properties are situated generally in the Anadarko Basin of the Texas Panhandle and western Oklahoma. This area held proved reserves totaling 41,906 MBOE at December 31, 1996, some 16% of the Company's total proved reserves. These proved reserves are
contained in 20 fields in which there are approximately 900 producing wells. Production from this area at December 31, 1996, averaged approximately 16 MBOE per day.
The Company's continuing expenditures in the Mid-Continent region are devoted principally to exploitation activities. Such expenditures in 1996, which totaled $19.3 million, were devoted primarily to 39 development wells. Plans for 1997 call for 66 development wells and capital spending of about $21 million. The Company estimates that it held 314 approximately development drilling locations in the area at the end of 1996.
Gulf Coast Region
The Company's Gulf Coast region properties are located onshore in south Texas and south Louisiana and offshore in the Gulf of Mexico off the coasts of the same two states. As of December 31, 1996, the Company's holdings in the Gulf Coast region totaled 21,854 MBOE of proved reserves, representing 8% of the Company's total such reserves.
The Company at December 31, 1996, had 68 undrilled exploratory prospects in its Gulf Coast region, some 60 of which were located offshore. Further, the Company estimates that it held approximately 20 development drilling locations at year-end 1996.
Both exploration and exploitation activities are conducted in this region. In 1996 such activity consisted of 28 exploratory and 5 development wells and cumulative capital spending of $86.4 million. The Company's capital budget but also for development drilling and the acquisition of offshore leases for 1997 anticipates spending of $62 million, primarily for 24 exploratory wells but also for development drilling and the acquisition of offshore leases in the Gulf Coast region.
CANADA
The Company's operations in Canada consist of interests in a small number of fields located in Alberta, Canada. As of December 31, 1996, the Company's holdings in Canada totaled 42,682 MBOE representing 17% of the Company's reserves. Seagull's 1997 capital program includes approximately $15 million in exploratory and development capital expenditures for Canadian operations.
EGYPT
The Company's Egyptian operations consist of working interests in two producing (Qarun and East Zeit) and three exploratory (East Beni Suef, Darag and South Hurghada) concessions. As discussed below, the East Zeit and South Hurghada concessions were purchased in 1996. The Company's interests in Qarun, East Beni Suef and Darag were owned by Global prior to the Global Merger.
Each concession is governed by a concession agreement (collectively, the "Egyptian Concession Agreements") between the working interest partners and the Egyptian national oil company ("EGPC"). Under the Egyptian Concession Agreements, the working interest partners pay 100% of capital and
operating costs and production is split between EGPC and the working interest partners. Working interest partners recover costs from a percentage, which varies by concession, of the oil and gas produced and sold from the applicable concession ("cost recovery petroleum"). See the discussions of each concession below for the applicable cost recovery percentage. Cost recovery petroleum forms a single unified pool for the entire concession from which costs of all fields, zones, products and types may be recovered without differentiation, except that operating costs are recovered prior to the recovery of any capital costs. Capital costs (which include exploration, development and other equipment and facilities costs) are amortized for recovery over four to five years while operating expenses are recoverable on a current basis. To the extent that the costs eligible for recovery in any quarter exceed the amount of cost recovery petroleum produced and sold in that quarter, such costs are recoverable from cost recovery petroleum in future quarters with no limit on the ability to carry forward such costs.
The remaining oil and gas produced and sold ("remaining oil" or "remaining gas") is divided between EGPC and the working interest partners. See the discussions of each concession below for the applicable remaining oil or gas percentage. From EGPC's share of this remaining oil or gas, all Egyptian government royalties as well as the applicable Egyptian income taxes of the working interest partners are paid.
Qarun
The Company has a 25% non-operated working interest in the Qarun Concession Agreement ("QCA"). The concession covers approximately 1.9 million gross acres located 45 miles southwest of Cairo, Egypt. Exploratory drilling activities began in mid 1994. Initial oil production, via trucking, began in late 1995 while conventional development facilities were completed in late 1996. These development facilities are expected to be fully operational in early 1997. As required by the QCA, the Qarun Production Company was formed in 1995 to operate the Qarun block and is jointly owned by the QCA partners and EGPC. Under the QCA, cost recovery petroleum may be up to 40% of the oil and gas produced and sold. Any portion of cost recovery petroleum not used to recover costs goes to EGPC. The working interest partners receive 20%-30% of the remaining oil depending upon production levels and 22% of the remaining gas. Up to 16 exploratory wells, as well as ongoing development activities, are scheduled on the Qarun concession during 1997. Plans for 1997 include approximately $30 million in capital expenditures net to the Company's 25% working interest.
East Zeit
On September 10, 1996, Seagull purchased the East Zeit and South Hurghada concessions from units of Exxon Corporation (the "Esso Suez Acquisition") for a net purchase price of $74 million. The Company, as operator, has a 100% working interest in the East Zeit concession which is located offshore in the Gulf of Suez. Under terms of the concession agreement, cost recovery petroleum may be up to 25% of the oil produced and sold. Any portion of cost recovery petroleum not used to recover costs goes to EGPC. As the working interest partner, the Company receives 15% of remaining oil (11.25% of total oil production). However, the Company receives no allocation of gas production as all such production is taken by EGPC. Plans for 1997 include approximately $30 million in capital expenditures, primarily for development activities and one exploratory well.
East Beni Suef
Seagull, as the operator, has a 50% working interest in the East Beni Suef Concession Agreement. The concession covers approximately 6.8 million gross acres lying adjacent and to the south of the Qarun concession. The working interest partners have committed to drill one exploratory well in the initial three year exploratory period. The exploration rights may be extended for an additional six years by the assumption of additional drilling obligations. Up to 40% of the oil and gas produced and sold is available as cost recovery petroleum. The working interest partners receive 15%-30% of the remaining oil depending upon production levels and 25% of the remaining gas. Any portion of cost recovery petroleum not used to recover costs is shared among the working interest partners and EGPC in the same manner as remaining petroleum. The Company has budgeted just over $3 million for 1997 capital expenditures in the block, including its share of the first two exploratory wells.
Darag
The Company has a 50%, non-operated working interest in the Darag block which is located in the northern portion of the Gulf of Suez, and covers 460,000 gross acres. Up to 40% of the oil and gas produced and sold is available as cost recovery petroleum. Any portion of cost recovery petroleum not used to recover costs is shared among the working interest partners and EGPC in the same manner as remaining petroleum. The working interest partners receive 13%-30% of the remaining oil based on the level of production and 25% of the remaining gas. The Company's 1997 capital budget is just over $5 million, including its share of two exploratory wells.
South Hurghada
As discussed above, the South Hurghada Concession Agreement, covering over 61,000 million acres, was acquired on September 10, 1996. Seagull, as operator, has a 100% working interest in the concession located onshore on the coast of the Gulf of Suez approximately 250 miles south of Cairo. Up to 40% of the oil and gas produced and sold is available as cost recovery petroleum. Any portion of cost recovery petroleum not used to recover costs goes to EGPC. The Company receives 12%-20% of the remaining oil depending upon production levels and 20% of the remaining gas. While there are currently no producing activities at South Hurghada, there are two existing oil discoveries. Projected 1997 capital spending in the block approximates $11 million, primarily for geophysical data acquisition and evaluation, two exploratory wells and installation of production facilities.
COTE D'IVOIRE
Seagull's operations in Cote d'Ivoire, West Africa consist of working interests in three blocks- CI-11, CI-12 and CI-104. Each block is subject to a Production Sharing Contract ("PSC") with similar terms for each of the blocks. Under the terms of the PSCs, the working interest partners pay 100% of capital and operating costs, and production is split between the Ivorian government and the working interest partners. Working interest partners recover costs from a percentage, which varies by concession, of the oil and gas produced and sold from the applicable contract area ("cost recovery petroleum"). See the discussions of each concession below for the applicable cost recovery percentage. Cost recovery petroleum forms a single unified pool for the entire PSC from which costs of all fields, zones, products and types may be recovered without differentiation, except that operating and financing costs are recovered prior to the recovery of any capital costs. Capital costs include exploration, development and
other equipment and facilities costs. To the extent that the costs eligible for recovery in any calendar year exceed the amount of cost recovery petroleum produced and sold in that quarter, such costs are recoverable from cost recovery petroleum in future years with no limit on the ability to carry forward such costs. Any portion of cost recovery petroleum not used to recover costs will be split between the Ivorian government and the working interest partners in the same manner as remaining petroleum.
The remaining oil and gas produced and sold is divided between the Ivorian government and the working interest partners. See the discussions of each concession below for the applicable remaining oil and gas percentage. From the Ivorian government's share of remaining petroleum, all Ivorian government royalties as well as the applicable Ivorian income taxes for the working interest partners are paid.
CI-11
Pursuant to the CI-11 PSC, the Company has a 13.2% unitized working interest in the area located from onshore to approximately eight miles offshore Cote d'Ivoire. Under this PSC, 40% of the oil and gas produced and sold is available as cost recovery petroleum. The working interest partners receive 10%-50% of the remaining petroleum based on the level of production and the water depth location of the specific wellhead. The Company has budgeted approximately $16 million as its share of 1997 capital spending, primarily for development drilling and facilities.
CI-12
In April 1995, the Company signed a PSC for block CI-12 which lies adjacent to the west of block CI-11. The Company acquired a 16.67% working interest in the PSC which covers approximately 525,000 gross acres. The working interest partners have committed to drill one exploratory well in the initial two year period. The exploration rights may be extended for an additional four years by the assumption of additional drilling obligations. The terms and conditions of the CI-12 PSC are similar to those of CI-11, except that 50% of the oil and gas produced is available to recover costs. The Company's capital budget for 1997 includes just over $2 million for CI-12, primarily for its share of two exploratory wells.
CI-104
In 1996, the Company received a 100% working interest in block CI-104, which lies adjacent to the west of block CI-12 and covers approximately 250,000 gross acres. The Company has committed to drill one exploratory well in the initial two year period. The exploration rights may be extended for an additional four years by the assumption of additional drilling obligations. While the terms and conditions of the CI-104 PSC are similar to those of CI-11, 75% of the oil and gas produced is available to recover costs. The Company receives 30%-50% of the remaining petroleum depending upon production levels and the water depth location of the specific wellhead. Seismic work is scheduled to begin in 1997 with initial drilling beginning in 1998.
TATARSTAN
Through its 90% owned subsidiary, Texneft, the Company has a net 45% interest in a joint venture in Tatarstan, a republic in the Russian Federation located west of the Ural Mountains and east of the Volga River. The joint venture is with Tatneft, a Russian open joint stock company. The joint venture, Tatex, operates various oil fields in Tatarstan. Under the terms of the joint venture and various supplemental agreements, the funding for the joint venture is supplied by Texneft and Tatneft through various credit agreements.
The joint venture's activities currently include three projects: (i) vapor recovery, (ii) the development and operation of the Onbysk field and (iii) the upcoming development and operation of the Suncheleevsky and Demkinsky fields. Texneft's share of capital spending for 1997 is some $6 million, primarily for development drilling and facilities.
INDONESIA
Seagull has a 1.714% interest in the Indonesia Joint Venture ("IJV") for the exploration, development and production of oil and gas in East Kalimantan, Indonesia, under a production sharing contract with Perusahaan Pertambangan Minyak Dan Gas Bumi Negara, the state petroleum enterprise of Indonesia ("Pertamina"). The majority of the revenue derived from the IJV results from the sale of liquefied natural gas ("LNG"). Under the terms of the PSC with Pertamina, the IJV is authorized to explore for, develop and produce petroleum reserves in an approximately 1.1 million acre area in East Kalimantan. In accordance with the requirements of the PSC, which expires on August 7, 2018, the IJV must relinquish 10% of the PSC area by August 7, 1998, 10% by December 31, 2000; 15% by each December 31, 2001, 2002 and 2004. However, the IJV is not required to relinquish any of the PSC area in which oil or gas is held for production.
Under the PSC, the IJV participants are entitled to recover cumulative operating and certain capital costs out of the oil and gas produced each year, and to receive a share of the remaining oil production and a share of the remaining revenues from the sale of gas on an after Indonesian tax basis. Through August 7, 1998, the share of revenues from the sale of gas after cost recovery will remain at 35% to the IJV and 65% to Pertamina. After August 7, 1998, the split will be (i) 25 % to the IJV and 75% to Pertamina for gas sales under various LNG sales contracts specified in the PSC to the extent that production is committed from the Badak or Nilam fields and (ii) 30% to the IJV and 70% to Pertamina for all LNG revenues from other fields. Based on current and projected oil production, the revenue split from oil sales after cost recovery through August 7, 2018 will remain at 15% to the IJV and 85% to Pertamina. These revenue splits are based on Indonesian income tax rates of 56% through August 7, 1998 and 48% thereafter.
OTHER INTERNATIONAL
The Company's other international operations consist of activities in the United Kingdom and Malaysia. In the United Kingdom, Seagull has several production licenses awarded to two exploration groups which include Seagull. Although the Company currently has no producing properties in the
United Kingdom, a well designed to delineate a 1994 discovery is scheduled for late 1997. While Seagull currently has several minor interests in Malaysia, exploratory efforts in 1993 and 1994 did not find commercial quantities of hydrocarbons. The Company and its joint venture partners do not currently have any additional plans for activities in Malaysia.
OIL AND GAS DRILLING ACTIVITIES
Seagull's oil and gas 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 oil or gas. 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. The number of wells drilled refers to the number of wells completed during the fiscal years, regardless of when drilling was initiated. Wells classified as "in progress" at year-end represent wells where drilling activity is ongoing, wells awaiting installation of permanent equipment and wells awaiting the drilling of additional delineation wells.
The Company had 15 gross (8.3 net) exploratory wells and 34 gross (21.3 net) development wells in progress at December 31, 1996. The exploratory wells in progress at year-end added 15.7 Bcfe to Seagull's proved reserves at December 31, 1996. The Company's capital expenditures for 1996 included $8.4 million related to these wells.
PRODUCTION
The following table summarizes the Company's production, average sales prices and direct operating costs for the periods indicated:
(1) Average sales prices are before deduction of production, severance, and other taxes. (2) Direct operating 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.
The following table sets forth information regarding the number of productive wells in which the Company held a working interest at December 31, 1996. 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.
For additional information relating to oil and gas producing activities, see Note 15 of the Consolidated Financial Statements included in the Company's 1996 Annual Report to Shareholders and as part of Exhibit 13 attached hereto.
DEVELOPED AND UNDEVELOPED OIL AND GAS ACREAGE
As of December 31, 1996, the Company owned working interests in the following developed and undeveloped oil and gas 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, 1996, the Company owned mineral and/or royalty interests in 584,430 gross (43,154 net) developed and 2,834,359 gross (105,889 net) undeveloped oil and gas acres, located primarily in the United States.
REGULATION
The availability of a ready market for oil and natural gas production depends upon numerous regulatory factors beyond the Company's control. These factors include regulation of oil and natural gas 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 oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment.
Regulation of Oil and Natural Gas 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.
Natural Gas Marketing and Transportation. Although maximum selling prices of natural gas were formerly regulated, the Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol Act") terminated wellhead price controls on all domestic natural gas on January 1, 1993, and amended the Natural Gas Policy Act of 1978 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 Federal Energy Regulatory Commission (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.
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 transportation, safety, environmental, and nondiscriminatory purchase and transport requirements, but does not generally entail rate regulation.
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 relatively 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 altered the marketplace such that lessors, including the MMS, are challenging the methods of valuation of gas for royalty purposes.
The MMS has recently issued a notice of proposed rulemaking in which it proposes to amend its regulations governing the calculation of royalties and the valuation of oil and natural gas produced from federal leases. The principal feature in the amendments, as proposed, would establish an alternative market-index based method to calculate royalties on certain natural gas production sold to affiliates or pursuant to non-arms'-length sales contracts. The MMS has proposed this rulemaking to facilitate royalty valuation in light of changes in the gas marketing environment. The Company cannot predict what action the MMS will take on these matters, nor can it predict at this stage of the rulemaking proceedings how the Company might be affected by amendments to the regulations.
In Canada, exploration, production and development activities are governed by federal and provincial laws which subject operators to extensive controls and regulations. Exports of oil and gas 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, MARKETING AND OTHER
The Company's O&G segment also includes pipeline and marketing operations involving (i) the transportation and marketing of Seagull's own and third-party gas, oil and natural gas liquids; (ii) gas gathering and processing; and (iii) pipeline engineering design, construction and operation.
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 oil and natural gas to various customers and aggregates supplies from various sources including third-party producers, marketing companies, pipelines, financial institutions and the Company's own production. 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.
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.
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 as a hedging strategy to manage commodity prices associated with oil and gas production sales and to reduce the impact of price fluctuations. The Company's policy is to leave the majority of its own E&P production either unhedged or protected only from price decreases. The Company accounts for its commodity derivative contracts as hedging activities and, accordingly, income or costs are included in revenues when the commodities are produced. 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 strategy. See Note 2 to the Company's Consolidated Financial Statements and Oil and Gas Operations in Management's Discussion and Analysis of Financial Condition and Results of Operations, both of which are included in the Company's 1996 Annual Report to Shareholders and as part of Exhibit 13 attached hereto.
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. The Company currently has one ongoing construction project and continues to pursue additional operating and construction opportunities as they arise.
COMPETITION
The Company's competitors in oil and gas 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.
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.
INTERNATIONAL OPERATIONS
Seagull's interests in countries outside the United States are subject to the various risks inherent in foreign operations. These risks may include, among other things, currency restrictions and exchange rate fluctuations, loss of revenue, property and equipment as a result of expropriation, nationalization, war, insurrection and other political risks, risks of increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies and other uncertainties arising out of foreign government sovereignty over the Company's international operations. The Company's international operations may also be adversely affected by laws and policies of the United States affecting foreign trade, taxation and investment. In addition, in the event of a dispute arising from foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the United States. The Company seeks to manage these risks by maintaining political risk insurance and concentrating its international exploration efforts in areas where the Company believes that the existing government is stable and favorably disposed towards United States exploration and production companies.
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"), 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 19%, 24% and 22% of the Company's consolidated revenues for 1996, 1995 and 1994, 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 72 miles of smaller diameter pipeline. The system's present design delivery capacity is approximately 410 MMcf/d. The average throughput of the system in 1996, 1995 and 1994 was 131, 122 and 121 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 was 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 2,051 miles of gas mains to approximately 94,100 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, 1996, ENG added approximately 56 miles of new gas distribution mains, installed 2,500 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 65-70% of its revenues earned in the first and fourth quarters of each year.
In 1996, purchase/resale volumes represented 56% of ENG's throughput and 82% 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 $10 million in annual operating margin and about 18.8 Bcf per year in volumes, which represent approximately 18% and 39%, 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 1996, the cost of gas purchased under the Marathon Contract averaged $1.64 per Mcf, including reimbursements for severance taxes. The Marathon Contract, as amended in 1991, has been approved by the APUC.
APC also has a gas purchase contract with Shell Oil Company and ARCO Alaska, Inc. (the "Shell Contract") which provides for the delivery of up to approximately 220 Bcf of gas through the year 2009. The Shell Contract provides 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. The Shell Contract also provides that certain portions of the gas purchased under the amendments may be priced under a pricing term similar to the Marathon Contract. The 1996 price under the Shell Contract, after application of contractual adjustments, averaged $1.63 per Mcf, including reimbursements for severance taxes. 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, 1996, 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 14 years.
ENSTAR Alaska's average cost of gas sold in 1996, 1995 and 1994 was $1.59, $1.75 and $1.74 per Mcf, respectively. ENSTAR Alaska's average gas sales price in 1996, 1995 and 1994 was $3.29, $3.41 and $3.23 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.
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 eight 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.'s beneficial shares owned has fallen below 5% of the outstanding voting stock of the Company.
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' beneficial shares owned has fallen below 5% of the outstanding voting stock of the Company.
On October 3, 1996, 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 The Prudential Insurance Company of America ("Prudential"), (the "Prudential Application"), which was then the owner of 5,573,061 shares (approximately 8.9% at such time of the outstanding Common Stock. According to information provided by Prudential, in its capacity as investment adviser, is beneficial owner of 6,546,741 shares (10.4%) of the Common Stock which 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. Prudential has sole voting and dispositive power as to 5,573,061 shares and shared voting and dispositive power as to 946,680 shares.
As a result of the Company's good faith filing of the Prudential Application, it 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 Prudential Application. To date, no such order has been issued. The Company believes that the Prudential 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 of 1990 ("OPA") and regulations promulgated pursuant thereto impose a variety of requirements on "responsible Parties" related to the prevention of oil spills and liability for damages resulting from such spills. Few defenses exist to the liability imposed by the OPA and such liability could be substantial. A failure to comply with ongoing requirements or inadequate cooperation in a spill event could subject a responsible party to civil or criminal enforcement action.
On October 19, 1996, legislative amendments to OPA were enacted. These amendments reduced the requirement of obtaining a certificate of financial responsibility to $35 million in the event of a spill, instead of the $150 million originally called for under OPA. In addition, the Texas Railroad Commission proposed an amendment to its regulations in line with OPA. The proposed amendment requires operators of hazardous liquid pipeline facilities inland of the Gulf coast to prepare facility response plans within 60 days of the effective date of the rule or simultaneously with the filing of the plan with federal authorities.
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 condition 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, 1997, the Company had 724 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 80% of ENSTAR Alaska's work force. Contracts have been negotiated that set wages and work relationships for the two units. The operating bargaining unit contract, effective from April 1, 1992 through April 1, 1996, is in the process of being renegotiated. The clerical bargaining unit contract is effective from April 1, 1995 through April 1, 2000. 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:
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
Royalty Litigation. Increasingly, royalty owners under oil and gas leases are challenging valuation methodology and post-production deductions used by producers. These cases have arisen because of the manner in which oil and gas producers such as Seagull have begun to provide services that had previously been provided by the interstate gas pipelines prior to the "unbundling" of gas services. For example, in 1996, Seagull has been sued in Anne K. Barnaby, et al. v. Seagull MidSouth, Inc. This case is pending in state court of Latimer County, Oklahoma. In this case, the plaintiffs seek additional royalties based upon the deduction by Seagull of post-production costs, such as those related to gathering, compression, dehydration and treating. In addition, the plaintiffs have questioned the sales price used by Seagull as a basis for calculating royalty to the extent that sales were made to Seagull's gas marketing subsidiary.
NorAm Litigation. Seagull Mid-South has been sued in NorAm Gas Transmission Co., et al. v. Seagull Mid-South Inc. The case relates to Seagull's termination of a 1956 gas contract, which provided for the sale of gas by Seagull from certain wells in the Aetna Filed in Arkansas for $0.16 per Mcf. NorAm Gas Transmission ("NorAm) has sought a declaratory judgment that the gas contract remains in effect with respect to these wells. Since the termination by Seagull of the gas contract, Seagull has been selling the gas in question on the spot market. Seagull believes that it has reasonable grounds for terminating the gas contract. The NorAm case is currently scheduled for trial in mid-1997 in District Court in Harris County, Texas. Seagull intends to vigorously defend this case and does not believe that this case will have a material adverse effect on its financial condition or results of operations.
NorAm has also sought a declaratory judgment to the effect that certain additional wells in the Aetna Field (including any new wells) would be subject to the $0.16 per Mcf price (the "Additional Well Claim"). If NorAm were successful with the Additional Well Claim, Seagull's operations in the Aetna Field would be materially affected in an adverse manner. However, Seagull believes that there is little basis for this claim by NorAm and believes that it will not be required to pay any amounts in connection with the Additional Well Claim.
Gulf Coast Vacuum Site. In 1993, the Environmental Protection Agency ("EPA") notified the Company that a subsidiary was a potentially responsible party ("PRP") at the Gulf Coast Vacuum Services Superfund Site (the "GCV Site") in Vermilion Parish, Louisiana. Based upon the Company's investigation of this claim, the Company believes that the basis for its alleged liability is a series of transactions between the Company's subsidiaries and the operator of the GCV Site that occurred during 1979 and 1980. While the EPA's cleanup cost estimate of the GCV Site is in the range of $17 million, 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 by the Company during 1979 and 1980.
Caddo Natural Gas Company Site. The Company was notified by the Louisiana Department of Environmental Quality on March 20, 1996, that one of the Company's wholly owned subsidiaries is a PRP in a state Superfund site known as the Caddo Natural Gas Company Site. This site is reported to be contaminated with low levels of PCB, an additive used in lubricating oils prior to the 1980s. Subsequent to year-end, the Company signed a settlement agreement whereby Seagull would pay a portion of the cleanup costs for the Caddo Natural Gas Company Site. Seagull's share of the cleanup costs is not expected to be material to its financial condition, results of operations or cash flows.
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 3, 1997, there were approximately 4,764 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 revolving credit agreements (the "Credit Facilities") restrict the Company's declaration or payment of dividends on and repurchases of Common Stock unless each of the following tests have been met: (i) 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, (ii) Tangible Net Worth cannot be less than $465 million plus 50% of the Company's net income, if positive, beginning with the fiscal year ended December 31, 1997, (iii) the Company's Debt/Capitalization Ratio cannot be more than 65% and (iv) no Default or Event of Default shall have occurred and be continuing. The capitalized terms used herein to describe the restrictions contained in the Credit Facilities have the meanings assigned to them in the Credit Facilities. Under the most restrictive of these tests, as of December 31, 1996, approximately $133 million was available for payment of dividends 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 6 of the Consolidated Financial Statements included in the Company's 1996 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 1996 Annual Report to Shareholders and as part of Exhibit 13 attached hereto.
SELECTED QUARTERLY FINANCIAL DATA
Summarized quarterly financial data (stated in thousands except per share amounts) is as follows:
(1) Certain adjustments were made to conform the accounting policies and presentation of Seagull and Global.
(2) Quarterly earnings (loss) per common share may not total to the full year per share amount, as the weighted average number of shares outstanding for each quarter fluctuated as a result of the assumed exercise of stock options.
(3) Includes $48.8 million non-cash charge relating to the impairment of long-lived assets.
(4) Includes one-time pre-tax charges of $8 million for expenses involved in the workforce reduction and consolidation.
(5) Includes $82 million pre-tax gain on the sale of the Pipeline Assets .
(6) Includes $10 million pre-tax merger expenses relating to the Global Merger.
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 1996 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 1996 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 13, 1997 (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 1996 Annual Report to Shareholders and as part of Exhibit 13 attached hereto, and are incorporated herein by reference:
Independent Auditors' Report
Consolidated Financial Statements
Notes to Consolidated Financial Statements
2. Schedules:
All schedules have been omitted because the required information is insignificant or not applicable.
3. Exhibits:
- -------------------- * Filed herewith. # Identifies management contracts and compensatory plans or arrangements.
(b) Reports on Form 8-K
On October 18, 1996, the Company filed a current report on Form 8-K dated October 3, 1996 with respect to Seagull's merger with Global. The items reported in such current report were Item 2 (Acquisition and Disposition of Assets) and Item 7 (Financial Statements and Exhibits). The following financial statements were included in that report:
(a) Financial statements of businesses acquired.
The consolidated financial statements of Global for the years ended December 31, 1995, 1994 and 1993 (incorporated by reference to Global's Annual Report on Form 10-K for the year ended December 31, 1995; Registration No. 1-8674).
The unaudited consolidated financial statements of Global for the six months ended June 30, 1996 and 1995 (incorporated by reference to Global's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996; Registration No. 1-8674).
(b) Pro forma financial information.
The pro forma financial information giving effect to (i) the merger of Seagull and Global using the pooling of interest method of accounting for business combinations and (ii) the Esso Suez Acquisition financed under Seagull's revolving credit facilities and using the purchase method of accounting.
On October 18, 1996, the Company filed an amendment to current report on Form 8-K dated September 10, 1996 with respect to Seagull's acquisition of all the outstanding common stock of Esso Suez Inc. and certain assets of Esso Egypt Limited. The item reported in such current report was Item 7 (Financial Statements and Exhibits). The following financial statements were included in that report:
The pro forma financial information giving effect to (i) the merger of Seagull and Global using the pooling of interest method of accounting for business combinations and (ii) the Esso Suez Acquisition financed under Seagull's revolving credit facilities and using the purchase method of accounting (incorporated by reference to Exhibit 99.1 of the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on October 18, 1996).
On November 13, 1996, the Company filed an amendment to current report on Form 8-K dated October 3, 1996 with respect to Seagull's merger with Global. The item reported in such current report was Item 7 (Financial Statements and Exhibits). The following financial statements were included in that report:
Supplemental consolidated statements of earnings and cash flows of Seagull and Global for each of the quarters in the three quarters ended September 30, 1996 and four quarters ended December 31, 1995 and the supplemental consolidated balance sheets of Seagull and Global as of September 30, June 30, and March 31, 1996 and 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.
SEAGULL ENERGY CORPORATION
Date: March 27, 1997 By: /s/ Barry J.Galt Barry J. Galt, Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
By: /s/ Barry J. Galt By: /s/ Thomas H. Cruikshank Barry J. Galt, Chairman of the Thomas H. Cruikshank, Director Board and Chief Executive Officer Date: March 27, 1997 and Director (Principal Executive Officer) By: /s/ Peter J. Fluor Date: March 27, 1997 Peter J. Fluor, Director Date: March 27, 1997 By: /s/ Robert F. Vagt Robert F. Vagt, President and By: /s/ William R. Grant Chief Operating Officer and William R. Grant, Director Director Date: March 27, 1997 Date: March 27, 1997 By: /s/ Dean P. Guerin By: /s/ John W. Elias Dean P. Guerin, Director John W. Elias, Executive Vice Date: March 27, 1997 President and Director Date: March 27, 1997 By: /s/ Richard M. Morrow Richard M. Morrow, Director By: /s/ William L. Transier Date: March 27, 1997 William L. Transier, Senior Vice President and Chief Financial By: /s/ Dee S. Osborne Officer (Principal Financial Dee S. Osborne, Director Officer) Date: March 27, 1997 Date: March 27, 1997 By: /s/ Sidney R. Petersen By: /s/ Gordon L. McConnell Sidney R. Petersen, Director Gordon L. McConnell, Vice Date: March 27, 1997 President and Controller (Principal Accounting Officer) By: /s/ Sam F. Segnar Date: March 27, 1997 Sam F. Segnar, Director Date: March 27, 1997 By: /s/ J. Evans Attwell J. Evans Attwell, Director By: /s/ R. A. Walker Date: March 27, 1997 R. A. Walker, Director Date: March 27, 1997 By: /s/ Richard J. Burgess Richard J. Burgess, Director Date: March 27, 1997
By: /s/ Milton Carroll Milton Carroll, Director Date: March 27, 1997
EXHIBIT INDEX
EXHIBITS:
- -------------------- * Filed herewith. # Identifies management contracts and compensatory plans or arrangements.