ITEM 1. BUSINESS.
GENERAL
PetroCorp Incorporated is an independent energy company engaged in the exploration, development and acquisition of oil and gas properties, and in the production of oil and natural gas in North America. The Company's activities are conducted principally in the states of Oklahoma, Texas, Mississippi, Louisiana and Kansas, and in the province of Alberta, Canada.
At December 31, 1997, the Company's proved reserves totaled 5.0 MMBbls of oil and 87.3 Bcf of natural gas and had an estimated pretax present value of future net revenues (PV-10) of $112 million. On a BOE basis, approximately 75% of the Company's proved reserves were natural gas at such date. In addition, the Company has unproved interest holdings with a net book value of $9.6 million, as well as interests in natural gas processing and gathering facilities with a net book value of $3.9 million.
The Company was formed in July 1983 as a Delaware corporation and in December 1986 contributed its assets to a newly formed Texas general partnership. In October 1992, the Company changed its legal form from a Texas general partnership to a Texas corporation. PetroCorp's principal executive offices are located at 16800 Greenspoint Park Drive, Suite 300, North Atrium, Houston, Texas 77060, and its telephone number is (281) 875-2500. Unless the context otherwise requires, the terms the "Company" and "PetroCorp" refer to and include PetroCorp Incorporated, its predecessor entities (including the original Delaware corporation and the subsequent Texas general partnership) and all subsidiaries in which PetroCorp owns a 50% or greater interest.
BUSINESS STRATEGY
Historically, the Company's strategy has been to increase its reserves, cash flow and underlying net asset value through a combination of exploration and development and acquisition activities.
Exploration and Development Strategy. Exploration and development activities are an important component of PetroCorp's business strategy. In recent years, the Company has allocated greater capital and management resources to exploration and development activities, increased the personnel and technological capabilities (including the use of 3-D seismic technology) available to its exploration and development teams, and developed major exploration and development projects in Mississippi, Oklahoma, Texas and Alberta, Canada. PetroCorp has the capability to perform reprocessing, visualization and interpretation of its seismic database completely in-house.
Acquisition Strategy. PetroCorp has grown, in large part, through the acquisition of producing oil and gas properties, and it intends to continue to take advantage of opportunities to purchase properties with proved reserves that meet the Company's acquisition criteria. Prevailing market conditions significantly influence the implementation of the Company's acquisition strategy. The Company generally focuses on acquisitions of long-lived natural gas reserves located onshore in North America and prefers acquisitions that provide potential through additional development or exploitation efforts as well as exploratory drilling opportunities.
EXPLORATION AND DEVELOPMENT ACTIVITIES
In recent years, the Company has placed increasing emphasis on the exploration and development component of its business strategy.
Mississippi Salt Basin. The Mississippi Salt Basin is one of PetroCorp's most active and aggressive exploration plays. Through year-end 1997, PetroCorp had drilled five exploratory prospects in Wayne, Greene and Smith Counties, yielding two new field discoveries and seven successful wells out of 10 total
wells drilled. The most recent completion was in the Smithtown Field in Greene County, Mississippi, where the Southern Mineral Corp. #2 well was successfully completed in the Hosston formation at a depth below 14,000 feet. After fracture stimulation, the well is producing 300 BOPD. PetroCorp owns a 25% working interest in the well. Drilling is expected to begin in April 1998 on the Quito Prospect, which is a 17,000 foot test in the Cotton Valley formation. PetroCorp retains a 20% working interest in the prospect, which is supported by 3-D seismic acquired last year. In September 1996, PetroCorp entered into a joint venture agreement with a subsidiary of Shell Oil Company (Shell) which allows PetroCorp to use approximately 13,000 line-miles of Shell's 2-D seismic database covering 18 counties. Thus far, the Company has ordered approximately 2,000 miles of the data, and after in-house reprocessing has identified numerous leads. Leasing has been completed on the first two exploration projects. One is ready for drilling, while the second will require a 3-D seismic survey to further define the initial drilling location.
Hanlan-Robb Area. The Company owns interests in five proved developed producing fields and two proved developed nonproducing fields in the Hanlan- Robb area of western Alberta, Canada. It intends to connect the two nonproducing fields to the Hanlan-Robb gas gathering system as declining production from the currently producing fields makes capacity available at the gas processing plant in which the Company owns an interest. During 1997, the Company continued its strategy of drilling horizontal lateral wells from existing wells in the area in order to improve productivity and to mitigate the impact of natural production declines in the fields. To date, five horizontal wells have been completed, resulting in a three or four fold increase in production from each well.
Recent activity for the biggest field in the area, the Hanlan Swan Hills Unit, includes the 1996 installation and start-up of a $10 million field compression facility designed to extend the life of the field into the next century. In February 1997, the Company increased its share of production in the Unit following a payout to its joint venture partner. The Company currently owns a 7.6% working interest in the Unit, which is operated by Petro-Canada. In 1997, the Hanlan 6-23 well was deviated laterally almost 1,000 feet to a measured depth of 16,880 feet, resulting in an increase in the production rate from approximately 6 MMcf/D to 24 MMcf/D. The Hanlan 7-27 well was horizontally sidetracked at a measured depth of 16,904 feet, resulting in increased production from approximately 4 MMcf/D to 12.5 MMcf/D.
Located approximately seven miles east of the plant, the Erith 8-13 well was producing approximately 6 MMcf/D and now has been tested at 21 MMcf/D following horizontal sidetracking at a depth of 14,300 feet. The Company owns a 12.5% working interest in the well.
Approximately ten miles west of the plant are the Shaw/Basing and Coalbranch/Coalspur areas. After acquiring in excess of 100 line-miles of high resolution 2-D seismic data in 1995, PetroCorp is now actively involved in two separate exploration plays in the area. Two wells have been successfully re- entered and drilled horizontally in the 12,500 foot Mississippian Turner Valley formation. The Coalbranch 16-33 and the Coalspur 9-27 are now producing at 5.1 MMcf/D and 2.1 MMcf/D, respectively. The other exploration play in this area involves drilling for the shallower Cardium formation at 5,000 to 7,000 depth. The Shaw 7-8 is now producing 4 MMcf/D. The Basing 10-25 is currently testing. In 1997, the Basing 2-9 was drilled 1,600 feet laterally at approximately 12,000 feet and tested at 4.5 MMcf/D. It is currently being tied into the plant, with production expected in the second quarter of 1998.
PetroCorp has access to a substantial amount of seismic and other data covering the Hanlan-Robb properties and has continued to participate in additional seismic surveys in the area. PetroCorp's technical team is actively engaged in analyzing such data to identify further development and exploration opportunities.
Worsley Field. The largest of the producing properties acquired in the year- end 1996 Millarville Acquisition (described below) is the Worsley property in northwest Alberta, Canada. The Company has modified the pipeline system, installed compression and commenced sales of 800 Mcf/D of natural gas that had previously been flared or shut-in. Additional development activity is planned in 1998 in the field.
McLeod Field. As part of the Millarville Acquisition, the Company acquired one oil shut-in well in this field in west central Alberta, Canada. During 1997, three additional oil wells and two natural gas wells were drilled with a 100% success rate. The Company is the operator and owns working interests in these wells ranging from 50% to 100%. Completion and tie-in of these new wells is planned for 1998. Following additions to its acreage position in this area during 1997, the Company holds 6,080 gross (3,776 net) acres in the field.
Trochu Area. Also part of the Millarville Acquisition and a subsequent acquisition, the Company acquired a 100% working interest in three oil wells and two natural gas wells in this area of central Alberta, Canada. In December 1997, the Company completed a 3-D seismic survey that will be used to plan further drilling for later in 1998. The Company operates all five wells.
Oklahoma. North of Oklahoma City in Edmond, Oklahoma, the Company drilled the Marks 6B-2 well to a depth of 6,500 feet, encountering 15 feet of net pay in the Prue sand. This well is on trend with the successful Jackson 2B-4 well drilled in 1996, which is currently producing 2.1 MMcf/D. Due to its location in an urban environment, testing on the new well is awaiting a pipeline connection, which is expected by mid-year 1998. The Company owns a 75% working interest in the Marks 6B-2 and a 47% interest in the Jackson 2B-4. The Company is also active in northern Oklahoma. Exploration activities are currently focused on Cottage Grove and Tonkawa gas targets at 4,000-5,000 feet within the Misener Trend/Northern Shelf Play of the Anadarko Basin. This activity has been driven by the integration of PetroCorp's extensive seismic database, which now includes in excess of 2,000 miles of 2-D and 12 square miles of 3-D seismic data in this area.
In April 1996, following approval of the Oklahoma Corporation Commission the SW Oklahoma City Unit was formed for the purposes of water flooding and repressurizing the field to improve ultimate oil recovery. Water injection commenced in September 1996. Phase I of the program was completed during the third quarter of 1997, and oil production response is expected in 1999. The PetroCorp-operated, 56 well unit has produced 2.4 MMBbls of oil and 19.8 Bcf of gas through year-end. PetroCorp owns an 86.4% working interest in the SW Oklahoma City Unit which is currently producing 235 BOPD and 3.1 MMcf/D with an average daily injection rate of 4,400 barrels of water per day. The adjacent Will Rogers Unit, operated by another party, has already shown a positive response to waterflood operations initiated in 1993. PetroCorp is also currently involved in waterflood projects on three fields in the Northern Oklahoma Area.
Southeast Texas. In 1997, the Company participated in a 3-D seismic program covering approximately 60 square miles in Newton County, Texas and Calcasieu Parish, Louisiana. Primary objectives are the expanded and overpressured Yegua formation along with the Frio Nodosaria sands. The West New York prospect (in which the Company has a 15% interest) is currently being drilled to a targeted depth of 12,750 feet.
ACQUISITION ACTIVITIES
In July 1997, the Company completed the acquisition of producing oil and gas properties located primarily in Louisiana for $9.2 million (the Gulf Coast Acquisition). Proved reserves acquired totaled 6.0 Bcf of natural gas and 200,000 barrels of oil (1.2 MMBOE). Funding for the acquisition was provided through a new $50 million credit facility with the Toronto-Dominion Bank and the Bank of Nova Scotia. Initial borrowing availability under this new facility was $25 million.
The Company completed the purchase of Millarville Oil and Gas Ltd., a privately held Canadian corporation that owned and operated properties in Alberta, Canada, in December 1996 for a cash acquisition price of $11.8 million (the Millarville Acquisition). Proved reserves acquired were 1.1 million barrels of oil and 6.8 Bcf of natural gas (2.2 MMBOE).
The Company expects to continue to pursue acquisition opportunities. The Company's acquisition team annually screens a large number of potential prospects; however, only a comparatively smaller number of prospects have the potential to satisfy the Company's acquisition criteria and are studied in detail.
PRODUCTION AND SALES
The following table presents certain information with respect to oil and gas production attributable to the Company's properties, average sales price received and average production costs during the three years ended December 31, 1997, 1996, and 1995. See Note 10 to the Consolidated Financial Statements of the Company and "Supplemental Information to the Consolidated Financial Statements" in the Notes thereto included elsewhere in this report for additional financial information regarding the Company's foreign and domestic operations.
MARKETING
PetroCorp's United States gas production is sold to a variety of pipelines, marketing companies and utility end users, typically under short-term contracts ranging in length from one month to one year. Currently, the majority of the Company's Canadian gas is dedicated under long-term contracts to Pan-Alberta Gas Ltd. (Pan-Alberta), a major Canadian gas marketer affiliated with the pipeline authorized to gather all gas in the province of Alberta. Approximately 60% of the Company's Canadian gas is resold into the United States, predominantly to markets in the upper midwest region. PetroCorp receives from Pan-
Alberta a price per Mcf equal to Pan-Alberta's resale price, less certain costs permitted to be recovered by Pan-Alberta under the contracts.
PetroCorp's domestic crude oil and condensate production is sold to a variety of purchasers typically on a monthly contract basis at posted field prices or NYMEX prices, as determined by major buyers. In particular areas, where production volumes are significant or the location is desirable for a particular purchaser, or both, the Company has successfully negotiated bonuses over the purchaser's general field postings for its production.
During the year ended December 31, 1997, Pan-Alberta (the purchaser of most of the Company's Canadian gas) and EOTT Energy Operated Limited Partnership (one of the Company's purchasers of oil) accounted for 21% and 26% of the Company's total sales, respectively. The Company does not believe the loss of any purchaser would have a material adverse effect on its financial position since the Company believes alternative sales arrangements could be made on relatively comparable terms.
In general, prices of oil and gas are dependent on numerous factors beyond the control of the Company, such as competition, international events and circumstances (including actions taken by the Organization of Petroleum Exporting Countries (OPEC)), and certain economic, political and regulatory developments. Since demand for natural gas is generally highest during winter months, prices received for the Company's natural gas are subject to seasonal variations.
HEDGING ACTIVITIES
Prior to 1997, the Company has utilized hedging transactions to manage its exposure to price fluctuations in crude oil and natural gas. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 11 to the Consolidated Financial Statements.
COMPETITION
The oil and gas industry is highly competitive. The Company competes in acquisitions and in the exploration, development, production and marketing of oil and gas with major oil companies, larger independent oil and gas concerns and individual producers and operators. Many of these competitors have substantially greater financial and other resources than the Company.
REGULATION
United States
General. The Company's business is affected by numerous governmental laws and regulations, including energy, environmental, conservation and tax laws. For example, state and federal agencies have issued rules and regulations that require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of reserves through proration, and regulate oilfield and pipeline environmental and safety matters. Changes in any of these laws could have a material adverse effect on the Company's business, and the Company cannot predict the overall effects of such laws and regulations on its future operations. Although these regulations have an impact on the Company and others in the oil and gas industry, the Company does not believe that it is affected in a significantly different manner by these regulations than are its competitors in the oil and gas industry.
The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing.
Regulation of Transportation and Sale of Natural Gas and Oil. Various aspects of the Company's oil and gas operations are regulated by agencies of the federal government. The transportation of natural gas in interstate commerce is generally regulated by the Federal Energy Regulatory Commission (FERC)
pursuant to the Natural Gas Act of 1938 (the NGA) and the Natural Gas Policy Act of 1978 (NGPA). The intrastate transportation and gathering of natural gas (and operational and safety matters related thereto) may be subject to regulation by state and local governments.
In the past, the federal government regulated the prices at which the Company's produced oil and gas could be sold. Currently, "first sales" of natural gas by producers and marketers, and all sales of crude oil, condensate and natural gas liquids, can be made at uncontrolled market prices, but Congress could reenact price controls at any time.
Within the past decade, the FERC has issued numerous orders and policy statements designed to create a more competitive environment in the national natural gas marketplace, including orders promoting "open-access" transportation on natural gas pipelines subject to the FERC's NGA and NGPA jurisdiction. The FERC's "Order 636" was issued in April 1992 and was designed to restructure the interstate natural gas transportation and marketing system and to promote competition within all phases of the natural gas industry. Among other things, Order 636 required interstate pipelines to separate the transportation of gas from the sale of gas, to change the manner in which pipeline rates were designed and to implement other changes intended to promote the growth of market centers. Subsequent FERC initiatives have attempted to standardize interstate pipeline business practices and to allow pipelines to implement market-based, negotiated and incentive rates. The restructured services implemented by Order 636 and successor orders have now been in effect for a number of winter heating seasons and have significantly affected the manner in which natural gas (both domestic and foreign) is transported and sold to consumers.
Although Order 636 has generally been upheld in judicial appeals to date, petitions for court review are still pending and it is not possible to predict the ultimate outcome of such appeals or the effect, if any, of future restructuring orders or policies on the Company's operations. In addition, FERC has recently announced that it will convene in the near future a public conference to consider whether FERC's current approach to regulation of the natural gas industry should be changed and whether further refinements or changes to existing policies should be made in view of developments in the natural gas industry since Order 636 was originally issued. Although FERC has indicated that it remains committed to Order 636's "fundamental goal" of "improving the competitive structure of the natural gas industry in order to maximize the benefits of wellhead decontrol," the future regulatory goals and priorities of FERC may be altered as a result of such conference and related inquiries. FERC's policies may also be impacted by the ongoing restructuring of the electric power industry pursuant to FERC Order No. 888.
While Order 636 and related orders do not directly regulate either the production or sale of gas that may be produced from the Company's properties, the increased competition and changes in business practices within the natural gas industry resulting from such orders have affected the terms and conditions under which the Company markets and transports its available gas supplies. To date, the FERC's pro-competition policies have not materially affected the Company's business or operations. On a prospective basis, however, such orders may substantially increase the burden on producers and transporters to accurately nominate and deliver on a daily basis specified volumes of natural gas, or to bear penalties or increased costs in the event scheduled deliveries are not made.
Environmental Regulation. Various federal, state and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company's operations and costs. In particular, the Company's exploration, exploitation and production operations, its activities in connection with storage and transportation of crude oil and other liquid hydrocarbons and its use of facilities for treating, processing or otherwise handling hydrocarbons and wastes therefrom are subject to stringent environmental regulation. Although compliance with these regulations increases the cost of Company operations, such compliance has not in the past had a material effect on the Company's capital expenditures, earnings or competitive position. Environmental regulations have historically been subject to frequent change by regulatory authorities. The recent trend toward stricter
standards in environmental legislation and regulation is likely to continue. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as "hazardous wastes," which would make the reclassified wastes subject to much more stringent handling, disposal and cleanup 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. Also under consideration at the federal level are laws and regulations that would require owners and operators of oil and gas facilities to meet an environmental "financial responsibility requirement" (with current proposals ranging from $35 million to $150 million) that could have a significant adverse impact on small oil and gas companies like PetroCorp. State initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these various initiatives could have a similar impact on the Company. The Company is unable to predict the ongoing cost to it of complying with these laws and regulations or the future impact of such regulations on its operation. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company. A catastrophic discharge of hydrocarbons into the environment could, to the extent such event is not insured, subject the Company to substantial expense.
Canada
In Canada, the petroleum industry operates under federal, provincial and municipal legislation and regulations governing taxes, land tenure, royalties, production rates, environmental protection, exports and other matters. Prices of oil and natural gas in Canada have been deregulated and are determined by market conditions and negotiations between buyers and sellers, although oil production volumes are regulated. Various matters relating to the transportation and distribution of natural gas are the subject of hearings before various regulatory tribunals. In addition, although the price of natural gas exported from Canada is subject to negotiation between buyers and sellers, the National Energy Board, which regulates exports of natural gas, requires that natural gas export contracts meet certain criteria as a condition of approving such contracts. These criteria, including price considerations, are designed to demonstrate that the export is in the Canadian public interest. Several provincial governments have introduced a number of programs to encourage and assist the oil and natural gas industry, including incentive payments, royalty holidays and royalty tax credits. Canadian governmental regulations may have a material effect on the economic parameters for engaging in oil and gas activities in Canada and may have a material effect on the advisability of investments in Canadian oil and gas drilling activities.
EMPLOYEES
At December 31, 1997, PetroCorp had 57 full-time employees.
ITEM 2.
ITEM 2. PROPERTIES.
PRINCIPAL PROPERTIES
The Company's proved oil and gas properties are relatively concentrated. Approximately 80% of the PV-10 from the Company's proved reserves at December 31, 1997 was attributable to eight principal areas.
The following table presents data regarding the estimated quantities of proved oil and gas reserves and the PV-10 attributable to the Company's principal properties as of December 31, 1997, all of which are taken from reports prepared by Huddleston & Co., Inc. in accordance with the rules and regulations of the Securities and Exchange Commission (SEC).
Hanlan-Robb. PetroCorp's largest single producing area is the Hanlan-Robb natural gas production complex located in the foothills region of western Alberta, Canada, which accounted for 38% of the Company's 1997 net daily gas production. The Company has ownership interests in seven area fields, but the majority of its Hanlan-Robb proved reserves and present value are currently attributable to one field, the Hanlan Swan Hills Gas Unit. PetroCorp's ownership is part of a joint venture managed by the Company with institutional investors that collectively own 21.6% of the field. After an ownership reversion in early 1997, PetroCorp's working interest in this field increased by 40%, from 5.4% to 7.6%. Petro-Canada is the largest interest owner in the area and operates the fields and the related gathering system and processing plant.
Oklahoma City Area. Includes the SW Oklahoma City field located within the metropolitan Oklahoma City area in Oklahoma and the Edmond Prospect located just north of Oklahoma City. The SW Oklahoma City field is bounded to the southeast by the Oklahoma City Prue Unit and to the southwest by the Wheatland and Will Rogers Units and produces oil with associated casinghead gas. As of December 31, 1997, PetroCorp also had an undeveloped leasehold position of 815 gross (560 net) acres in the Edmond Prospect.
Riceville Field. The largest of the producing properties acquired in the Gulf Coast Acquisition in July 1997, this field is located in Vermillion Parish, Louisiana. PetroCorp acquired a 13.5% non-operated working interest in this two well field which primarily produces natural gas with associated condensate.
Mississippi Salt Basin. This basin is one of PetroCorp's most active exploration areas. At the end of 1994, the Company made a new field discovery of oil and associated natural gas in the Maynor Creek Field
in Wayne County, Mississippi. The largest of its two producing fields in the basin, the Company has drilled three successful development wells there, two in 1995 and one in December 1996. PetroCorp operates the four wells in the field and increased its 50% average working interest to 65% when it acquired a partner's interest in October 1996. In September 1996, expanding on its successes in the basin, the Company entered into a seismic joint venture agreement with a subsidiary of Shell Oil Company to extend its exploration effort into an 18-county area. Under the terms of the agreement, PetroCorp has access to Shell's extensive 2-D seismic database in the area (approximately 13,000 line-miles of data) and other proprietary information held by Shell. As of December 31, 1997, PetroCorp also had an undeveloped leasehold position of 18,936 gross (10,773 net) acres in this area.
Worsley Field. The largest of the producing properties acquired from Millarville Oil & Gas Ltd. in December 1996, this field is located in northwest Alberta, Canada and primarily produces oil and associated casinghead gas. The Company operates seven wells in the field and 100% of the working interests. It also owns an interest in one non-operated well. With an undeveloped leasehold position of 160 gross (160 net) acres at December 31, 1997, the Company plans to pursue further development of this field.
Trochu Field. The Company operates and has a 100% working interest in three oil wells and two gas wells in this area of central Alberta, Canada. A 3-D seismic survey shot in December 1997 will be used to delineate further drilling in 1998 on the 960 gross (960 net) acres of undeveloped lands.
McLeod Field. This field is located in west central Alberta, Canada and consists of one oil well acquired from Millarville and three additional oil wells and two additional gas wells drilled in 1997. The Company operates all these wells and holds a 50% to 100% working interest in each. Completion and tie-in of the new wells is planned for 1998 along with further drilling on 5,920 gross (3,616 net) acres of undeveloped lands.
Northern Oklahoma Area. The Northern Oklahoma Area is located in Alfalfa and Grant Counties in north central Oklahoma. Production is primarily oil with associated casinghead gas from five major fields. Three of these fields are the subject of pressure maintenance waterfloods, of which two are operated by PetroCorp. PetroCorp continues to actively pursue both exploration and development in the Northern Oklahoma Area, and at December 31, 1997 had an undeveloped leasehold position of approximately 13,633 gross (9,974 net) acres.
Other Properties. Other significant properties include the Glick Field located in Kiowa County in southern Kansas, the Harris Field located in Live Oak County in south central Texas, and the Paradox Basin area of southwest Colorado.
TITLE TO PROPERTIES
United States. Except for the Company-owned mineral fee, royalty and overriding royalty interests shown in the "Acreage and Wells" table below, substantially all of the Company's United States property interests are held pursuant to leases from third parties. The Company believes that it has satisfactory title to its properties in accordance with standards generally accepted in the oil and gas industry. In numerous instances the Company has acquired legal title to producing properties and has carved out of the properties so acquired net profits royalty interests in favor of institutional investors who supplied a substantial portion of the funds for the acquisition of such properties. The producing property reserves of the Company are stated after giving effect to the reduction in cash flow attributable to such net profits royalty interests. In addition, the Company's properties are subject to customary royalty interests, liens for current taxes and other burdens that the Company believes do not materially interfere with the use of or affect the value of such properties.
Canada. Canadian property interests are held primarily under leases from the Crown. A small percentage are from freehold owners. Prior to drilling on a non- Crown lease or acquiring a non-Crown producing lease, the Company generally obtains a title opinion covering the "historical" (freehold) title. The Company generally relies on a title certificate under Canada's Torrens title registration system to verify "current" (leasehold) ownership. Except for these differences, title matters in Canada are similar to those in the United States.
OIL AND GAS RESERVES
All information herein regarding estimates of the Company's proved reserves, related future net revenues and PV-10 is taken from reports prepared by Huddleston & Co., Inc. (the Independent Engineers) in accordance with the rules and regulations of the SEC. The Independent Engineers' estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data provided by the Company.
The following table sets forth summary information with respect to the estimates made by the Independent Engineers of the Company's proved oil and gas reserves as of December 31, 1997. The PV-10 values shown in the table are not intended to represent the current market value of the estimated oil and gas reserves owned by the Company.
- -------- (1) Proved and proved developed future net revenues include $1,891,000 related to the sale of sulfur. (2) Proved and proved developed present values of future net revenues include $1,080,000 related to the sale of sulphur.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and future amounts and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of proved undeveloped reserves are inherently less certain than estimates of proved developed reserves. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, geologic success and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, the Company's reserves may be subject to downward or upward revision based upon production history, purchases or sales of properties, results of future development, prevailing oil and gas prices and other factors. Therefore, the present value shown above should not be construed as the current market value of the estimated oil and gas reserves attributable to the Company's properties.
In accordance with SEC guidelines, the Independent Engineers' estimates of future net revenues from the Company's proved reserves and the present value thereof are made using oil, gas and sulfur sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. See "Marketing" under Item 1 of this report, "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 of this report and "Supplemental Information to Consolidated Financial Statements" in the Notes to the Consolidated Financial Statements of the Company. Estimates of the Company's proved oil and gas reserves were not filed with or included in reports to any other federal authority or agency other than the SEC during the fiscal year ended December 31, 1997.
ACREAGE AND WELLS
The following table sets forth certain information with respect to the Company's developed and undeveloped leased acreage as of December 31, 1997.
- -------- (1) Approximately 67% of net (approximately 47% of net participating interest) undeveloped acres are covered by leases that expire during 1998. (2) Net participating interest represents the Company's net working interest less net profits royalty interests carved out and reconveyed to institutional investors.
As of December 31, 1997, the Company had working interests in 288 gross (87 net) producing oil wells and 174 gross (46 net) producing gas wells. Of these wells, 69 gross (17 net) oil wells and 46 gross (7 net) gas wells were in Canada, and the remainder of the oil and gas wells were in the United States.
DRILLING ACTIVITIES
All of PetroCorp's drilling activities are conducted through arrangements with independent contractors, and it owns no drilling equipment. Certain information with regard to the Company's drilling activities, during the years ended December 31, 1997, 1996 and 1995 is set forth below:
- -------- (1) Net participating interest represents the Company's net working interest less net profits royalty interests carved out and reconveyed to institutional investors. (2) The Company has a net participating interest less than 0.05% in this well.
At December 31, 1997, the Company was participating in the drilling or completion of 1 gross (.3 net) well in the United States and 2 gross (.7 net) wells in Canada.
HANLAN-ROBB NATURAL GAS PROCESSING PLANT AND GAS GATHERING SYSTEMS
PetroCorp owns interests in a centrally located gas processing plant and in a gas gathering system that connects all five of the Company's currently producing Hanlan-Robb fields to the Hanlan-Robb plant. The gas processing plant, which is operated by Petro-Canada, was commissioned in 1983 and has a processing capacity of approximately 300 MMcf/D of natural gas. For the 12 months ended December 31, 1997, plant throughput averaged 216 MMcf/D (72% of design capacity). In 1996, Hanlan Unit activity included installation and start-up of a $10 million compression project. Recently, several horizontal laterals from existing Hanlan area wells have been drilled. These projects, along with an active exploration and development drilling program in the area, are designed in part to mitigate natural production declines and keep the plant operating at high utilization rates. In 1998, two additional pipelines are expected to be connected to the facility as well as an expansion of plant capacity, increasing throughput to approximately 340 MMcf/D of natural gas by year-end 1998. Much of this throughput will be from third party gas for which the plant owners will receive fees, thus reducing PetroCorp's share of plant expenses.
Previously a wholly-owned subsidiary of the Company, Fidelity Gas Systems, Inc. ("FGS"), owned and operated the Anasazi Gas Gathering System, which gathers gas produced from the Company-operated lease in the Paradox Basin area of southwest Colorado. In December 1997, FGS was merged into the Company. The working interest owners have entered into contracts with the Company pursuant to which the Company purchases all of the gas produced from the area. This gas is then resold by the Company to a purchaser at a redelivery point on the national transmission pipeline system. Proceeds payable by the Company are based upon the Company's resale price less a contractually agreed-upon fee. Amounts received by the Company are distributed to all working interest and royalty owners in the producing area in accordance with their ownership interests. Because it is a gas gathering system, the Anasazi Gas Gathering System has been deemed nonjurisdictional with respect to existing FERC rules and regulations.
OTHER FACILITIES
The Company leases approximately 31,600 square feet in Houston, Texas for its executive and divisional offices. Additionally, the Company leases approximately 8,200 square feet in Oklahoma City, Oklahoma and approximately 4,000 square feet in Calgary, Alberta for divisional offices.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
Current and prospective stockholders should carefully consider the following risk factors in evaluating an investment in PetroCorp. The information discussed herein includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included herein regarding planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled after the date hereof, the Company's financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties, and the Company can give no assurance that such expectations will prove to have been correct. The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth in the following risk factors.
All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors.
VOLATILE NATURE OF OIL AND GAS MARKETS; FLUCTUATIONS IN PRICES
The Company's future financial condition and results of operations are highly dependent on the demand and prices received for oil and gas production and on the costs of acquiring, developing and producing reserves. Oil and gas prices have historically been volatile and are expected by the Company to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the Company's control. These factors include political conditions in the Middle East and elsewhere, domestic and foreign supply of oil and gas, the level of consumer demand, weather conditions, domestic and foreign government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. A decline in oil or gas prices may adversely affect the Company's cash flow, liquidity and profitability. Lower oil or gas prices also may reduce the amount of the Company's oil and gas that can be produced economically.
DEPENDENCE ON ACQUIRING AND FINDING ADDITIONAL RESERVES
The Company's prospects for future growth and profitability will depend predominantly on its ability to replace present reserves through acquisitions and exploratory drilling, as well as on its ability to
successfully develop additional reserves. There can be no assurance that the Company's acquisition and exploration activities or planned development projects will result in significant additional reserves or that the Company will have continuing success at drilling economically productive wells.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company has made, and likely will continue to make, substantial capital expenditures in connection with the acquisition, exploration and development of oil and gas properties. Future cash flows and the availability of credit are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas and the Company's success in locating and producing new reserves. If revenues were to decrease as a result of lower oil and gas prices, decreased production or otherwise, and the Company had no available credit, the Company could be limited in its ability to replace its reserves or to maintain production at current levels, resulting in a decrease in production and revenue over time. If the Company's cash flow from operations and available credit are not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements.
RELIANCE ON ESTIMATES OF RESERVES AND FUTURE NET CASH FLOWS
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the Company's control. Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flow necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies, assumptions concerning future oil and gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary significantly. Actual production, revenues and expenditures with respect to the Company's reserves likely will vary from estimates, and such variances may be material. In addition, the Company's reserves and future cash flows may be subject to revisions based upon production history, results of future development, oil and gas prices, performance of counterparties under agreements to which the Company is a party, operating and development costs and other factors.
The PV-10 values referred to herein should not be construed as the current market value of the estimated oil and gas reserves attributable to the Company's properties. In accordance with applicable requirements of the SEC, PV-10 is generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and gas, curtailments or increases in consumption by natural gas purchasers and changes in governmental regulations or taxation. The timing of actual future net cash flows from proved reserves, and thus their actual present value, will be affected by the timing of both the production and the incurrence of expenses in connection with development and production of oil and gas properties. In addition, the 10% discount factor (which is required by the SEC to be used to calculate PV-10 for reporting purposes), is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company and its properties or the oil and gas industry in general.
EXPLORATION RISKS
Exploratory drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered, and there can be no assurance that new wells drilled by the
Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and gas may involve unprofitable efforts, not only from non-productive wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services.
MARKETING RISKS
The Company's ability to market its oil and gas production at commercially acceptable prices is dependent on, among other factors, the availability and capacity of gathering systems and pipelines, federal and state regulation of production and transportation, general economic conditions, and changes in supply and in demand.
ACQUISITION RISKS
Acquisitions of oil and gas businesses and properties and volumetric production payments have been an important element of the Company's success, and the Company will continue to seek acquisitions in the future. Even though the Company performs a review (including a limited review of title and other records) of the major properties it seeks to acquire that it believes is consistent with industry practices, such reviews are inherently incomplete and it is generally not feasible for the Company to review in-depth every property and all records. Even an in-depth review may not reveal existing or potential problems or permit the Company to become familiar enough with the properties to assess fully their deficiencies and capabilities, and the Company often assumes environmental and other liabilities in connection with acquired businesses and properties.
OPERATING RISKS
The Company's operations are subject to numerous risks inherent in the oil and gas industry, including the risks of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company's operations may be materially curtailed, delayed or canceled as a result of numerous factors, including the presence of unanticipated pressure or irregularities in formations, accidents, title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. In accordance with customary industry practice, the Company maintains insurance against some, but not all, of the risks described above. There can be no assurance that the levels of insurance maintained by the Company will be adequate to cover any losses or liabilities.
COMPETITIVE INDUSTRY
The oil and gas industry is highly competitive. The Company competes for corporate and property acquisitions and the exploration, development, production, transportation and marketing of oil and gas, as well as contracting for equipment and securing personnel, with major oil and gas companies, other independent oil and gas concerns and individual producers and operators. Many of these competitors have financial and other resources which substantially exceed those available to the Company.
GOVERNMENT REGULATION
The Company's business is subject to certain federal, state and local laws and regulations relating to the drilling for and production, transportation and marketing of oil and gas, as well as environmental and
safety matters. Such laws and regulations have generally become more stringent in recent years, often imposing greater liability on an increasing number of parties. Because the requirements imposed by such laws and regulations are frequently changed, the Company is unable to predict the effect or cost of compliance with such requirements or their effects on oil and gas use or prices. In addition, legislative proposals are frequently introduced in Congress and state legislatures which, if enacted, might significantly affect the oil and gas industry. In view of the many uncertainties which exist with respect to any legislative proposals, the effect on the Company of any legislation which might be enacted cannot be predicted.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Company is a party to various lawsuits and governmental proceedings, all arising in the ordinary course of business. Although the outcome of these lawsuits cannot be predicted with certainty, the Company does not expect such matters to have a material adverse effect, either singly or in the aggregate, on the financial position of the Company.
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 EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company's Common Stock has been listed on The Nasdaq Stock Market since October 28, 1993 and trades under the symbol PETR. The following table presents the high and low closing prices for the Company's Common Stock for each quarter during 1996 and 1997, and for a portion of the Company's current quarter, as reported by The Nasdaq Stock Market.
As of March 17, 1998, the closing price for the Company's Common Stock was $8.38 per share. As of March 17, 1998, there were approximately 560 holders of record of the Common Stock.
The Company has not declared or paid any cash dividends on its Common Stock to date. The Board of Directors of the Company does not intend to declare cash dividends on its Common Stock in the foreseeable future. The Company intends instead to retain its earnings to support the growth of the Company's business. Any future cash dividends would depend on future earnings, capital requirements, the Company's financial condition and other factors deemed relevant by the Company's Board of Directors.
Certain senior notes were issued pursuant to a note purchase agreement that prohibited the declaration or payment of any cash dividends by the Company prior to July 1, 1995. In addition, other provisions of the note purchase agreement impose upon the Company certain financial covenants and other restrictive covenants that have the effect of restricting the amount of dividends on the Common Stock that may be paid by the Company after June 30, 1995. The terms of the Company's credit facility also prohibit the declaration or payment of any dividends.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The following table summarizes consolidated financial data of the Company and should be read in conjunction with the "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements of the Company, including the Notes thereto, included elsewhere in this report.
- -------- (1) Effective January 1, 1993, the Company adopted Statement of Financial Standards No. 109, "Accounting for Income Taxes."
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
GENERAL
The Company's principal line of business is the production and sale of its oil and natural gas reserves located in North America. Results of operations are dependent upon the quantity of production and the price obtained for such production. Prices received by the Company for the sale of its oil and natural gas have fluctuated significantly from period to period. Such fluctuations affect the Company's ability to maintain or increase its production from existing oil and gas properties and to explore, develop or acquire new properties.
The following table reflects certain operating data for the periods presented:
ACQUISITIONS
The Company completed the purchase of Millarville Oil and Gas Ltd., a privately held Alberta corporation that owns and operates oil and gas properties in Alberta, Canada, in December 1996 for a cash acquisition price of $11.8 million (the Millarville Acquisition). In July 1997, the Company completed the purchase of producing properties located primarily in Louisiana for $9.2 million (the Gulf Coast Acquisition). These two acquisitions had a significant impact on the Company's results of operations in 1997.
RESULTS OF OPERATIONS
1997 Compared to 1996
Overview. As a result of a 13% increase in production, cash flow before changes in operating assets and liabilities increased 9% to $19.1 million in 1997 compared to $17.5 million in 1996. Net income decreased 48% to $1.9 million, or $0.22 per share, compared to $3.6 million, or $0.42 per share (excluding a $629,000, or $.07 per share, after-tax gain on the sale of a gas gathering system) for the corresponding periods. Net income in 1997 was significantly impacted by increased DD&A largely due to the year-end 1996 reduction in proved reserves at the Company's Texas waterflood project. Assuming the reduction in reserves occurred at the beginning of 1996 rather than at the end and excluding the gain on the 1996 sale of the gas gathering system, 1997 net income would have decreased by 6% compared to 1996.
Revenues. Total revenues increased 11% to $35.1 million in 1997 compared to $31.5 million in 1996. Oil production increased 8% to 722 MBbls from 667 MBbls. Natural gas production increased 16% to 9,640 MMcf from 8,337 MMcf, resulting in overall production increasing 13% to 2,329 MBOE from 2,056 MBOE. The increase in oil production is primarily related to the Millarville Acquisition. The increase in natural gas production reflects the impact of the two acquisitions coupled with an increase in the Company's share of gas production in the Hanlan-Robb area in western Alberta as a result of an increase in ownership following a February 1997 payout to its joint venture partner.
The Company's average U.S. natural gas price increased 11% to $2.62 per Mcf in 1997 from $2.36 per Mcf in 1996, while the average Canadian natural gas price increased 9% to $1.46 from $1.34. The Company's composite average oil price decreased 4% to $19.10 per barrel in 1997 from $19.91 per barrel in 1996. As a result of hedging transactions, the Company's 1996 average oil price was reduced by $1.15 per barrel from the average price that would have otherwise been received. No hedging transactions were in place during 1997. Primarily as a result of the increases in production volumes, oil and gas revenues increased 13% to $33.5 million in 1997 from $29.7 million in 1996. Plant processing revenues decreased 14% to $1.4 million from $1.7 million primarily as a result of the Company's sale of a portion of its interest in the Canadian Hanlan-Robb gas processing plant in May 1996.
Production Costs. Production costs increased 17% to $7.8 million in 1997 compared to $6.7 million in 1996 primarily as a result of the 13% increase in production volumes and initiation of waterflood operations in the SW Oklahoma City field. Production costs per BOE slightly increased by 3% to $3.35 per BOE from $3.24 per BOE.
Depreciation, Depletion & Amortization (DD&A). Total DD&A increased 37% to $17.1 million in 1997 from $12.4 million in 1996 primarily as a result of the increase in the oil and gas DD&A rate to $6.60 per BOE from $5.24 per BOE. The increase in the DD&A rate reflects the impact of the year-end 1996 reduction in proved reserves due to the lack of commercial oil response at the Company's Richardson-Mueller Caddo Unit waterflood project in northern Texas.
General and Administrative Expenses. General and administrative expenses increased 8% to $5.1 million in 1997 from $4.7 million in 1996. This increase is primarily due to an increase in contract and temporary personnel associated with the producing property acquisitions and other ongoing projects and a decrease in the Company's drilling and operating overhead recoveries which reduce general and administrative expenses.
Investment and Other Income. Investment and other income decreased 71% to $558,000 in 1997 from $1.9 million in 1996 primarily as a result of a $1.0 million pre-tax gain on the sale of the Company's Oklahoma gas gathering system included in investment and other income in 1996. Additionally, less funds were available for investment in 1997.
Interest Expense. Interest expense increased 4% to $3.5 million in 1997 from $3.4 million in 1996, reflecting the impact of increased debt associated with the Gulf Coast Acquisition completed in July 1997.
Income Taxes. The Company recorded a $136,000 income tax provision on pre- tax income of $2.0 million with an effective tax rate of 7% in 1997 compared to an income tax provision of $1.8 million on pre-tax income of $6.1 million with an effective tax rate of 30% in 1996. During 1997 the Company recorded an income tax provision for its Canadian operations with an effective tax rate of 15% which was partially offset by an income tax benefit for its U.S. operations with an effective tax rate of 29%, resulting in an overall effective tax rate of 7%.
1996 Compared to 1995
Overview. Cash flow before changes in operating assets and liabilities increased 50% to $17.5 million in 1996 compared to $11.7 million in 1995, primarily as a result of increased product prices and decreased cash expenses. During 1996, the Company recorded net income of $4.2 million, or $0.49 per share, which included $629,000, or $0.07 per share, related to the after-tax gain on the sale of the gas gathering system in Oklahoma. In 1995, the Company recorded a net loss of $9.5 million, or $1.11 per share, which included an $8.5 million, or $0.99 per share, oil and gas property valuation adjustment.
Revenues. Total revenues increased 15% to $31.5 million in 1996 from $27.4 million in 1995. Oil production increased slightly to 667 MBbls from 658 MBbls. Natural gas production decreased 10% to 8,337 MMcf in 1996 from 9,283 MMcf in 1995, resulting in an overall production decrease of 7% to 2,056 MBOE from 2,205 MBOE. The decrease in natural gas production is primarily the result of U.S. and Canadian property sales and normal production declines in the Company's U.S. properties.
The Company's average U.S. natural gas price increased 46% to $2.36 per Mcf in 1996 from $1.62 per Mcf in 1995 while the average Canadian natural gas price increased 49% to $1.34 from $0.90. The Company's composite average oil price increased 12% to $19.91 per barrel in 1996 from $17.80 per barrel in 1995. As a result of hedging transactions, the Company's 1996 average oil price was reduced by $1.15 per barrel from the average price that would have otherwise been received while the 1995 average price was increased by $0.49 per barrel. As a result of the increases in natural gas and oil prices, partially offset by a decrease in production, oil and gas revenues increased 22% to $29.7 million in 1996 from $24.4 million in 1995. Plant processing revenues declined to $1.7 million from $1.9 million primarily as a result of the Company's sale of a portion of its interest in the Canadian Hanlan-Robb gas processing plant in May 1996. Other revenues declined 84% to $170,000 in 1996 from $1.9 million in 1995 due to reduced gas gathering fees resulting from the March 1996 sale of the Company's Oklahoma gas gathering system, and lower average sulfur prices of $7.40 per long-ton compared to $31.97 per long- ton.
Production Costs. Production costs declined 9% to $6.7 million in 1996 compared to $7.3 million in 1995, while production costs per BOE decreased 2% to $3.24 per BOE from $3.31 per BOE. The decrease in production costs in absolute dollars and on a BOE basis resulted from the Company's focus on reducing costs.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 7% to $12.4 million in 1996 from $13.3 million in 1995, primarily as a result of the decrease in production volumes. On a BOE basis, the oil and gas DD&A rate increased slightly to $5.24 per BOE from $5.22 per BOE.
Oil and Gas Property Valuation Adjustment. At June 30, 1995, primarily as a result of the impairment of the Company's valuation of its unproved fee mineral interests and a decline in oil and gas prices, the Company recorded an $8.5 million valuation adjustment to its oil and gas property balance in accordance with the full cost method of accounting.
General and Administrative Expenses. General and administrative expenses decreased 16% to $4.7 million in 1996 from $5.5 million in 1995 primarily due to a reduction in personnel associated with the Company's asset rationalization efforts.
Investment and Other Income. Investment and other income increased 30% to $1.9 million in 1996 from $1.5 million in 1995. In 1996, the Company included a $1.0 million gain on the sale of its Oklahoma gas gathering system in investment and other income. In 1995, the Company included in investment and other income a $1.6 million settlement of a long standing gas contract claim against Columbia Gas System and a $1.0 million loss related to the Company's natural gas hedging activities. The hedging loss was recorded in the fourth quarter of 1995 when certain New York Mercantile Exchange (NYMEX) natural gas futures contracts no longer qualified for hedge accounting as a result of the decoupling of the relationship between the pricing of natural gas futures contracts for the first quarter of 1996 and the Company's field prices for the same period. Absent these special items, investment and other income would have increased 10% to $910,000 in 1996 from $826,000 in 1995 primarily as a result of increased funds available for investment.
Interest Expense. Interest expense decreased 13% to $3.4 million in 1996 from $3.9 million in 1995, due to reductions in outstanding debt.
Income Taxes. The Company recorded a $1.8 million income tax provision on pre-tax income of $6.1 million in 1996 with an effective tax rate 30% compared to an income tax benefit of $608,000 on a pre-tax loss of $1.6 million in 1995 (excluding the effect of the oil and gas property valuation adjustment of $8.5 million which is calculated on an after-tax basis and has no effect on the income tax benefit) with an effective tax rate of 37%.
LIQUIDITY AND CAPITAL RESOURCES
The Company has historically funded its capital expenditures and working capital requirements with its cash flow from operations, debt and equity capital and participation by institutional investors. As of December 31, 1997, the Company had working capital of $2.6 million as compared to $1.9 million at December 31, 1996. Working capital increased slightly as cash provided by operating activities before changes in operating assets and liabilities plus proceeds from new bank borrowings were mostly offset by capital expenditures and the transfer of long-term debt to current. Net cash provided by operating activities was $19.8 million, $18.4 million and $10.5 million in 1997, 1996 and 1995, respectively, while net cash provided by operating activities before changes in operating assets and liabilities for the same periods was $19.1 million, $17.5 million and $11.7 million, respectively.
The Company's total capital expenditures, including capitalized internal costs, for 1997, 1996 and 1995 were $28.0 million, $29.5 million and $16.6 million, respectively. Capital expenditures in 1997 included $12.6 million in exploration and development drilling costs, $3.8 million in lease acquisitions, geological and geophysical costs and $11.0 million in producing property acquisitions. The largest of the Company's acquisitions in 1997 was the $9.2 million Gulf Coast Acquisition. Capital expenditures in 1996 included $8.7 million in exploration and development drilling expenditures, $2.7 million in lease acquisitions, geological and geophysical costs and $17.3 million in producing property acquisitions. The largest of the Company's acquisitions in 1996 was the $11.8 million Millarville Acquisition. Capital expenditures in 1995 included $10.2 million in exploration and development costs, $5.1 million in lease acquisitions, geological and geophysical costs and $138,000 in producing property acquisitions.
Oil and gas property sales totaled $1.4 million for 1997, down significantly from the $6.3 million in 1996 and $4.4 million in 1995. In 1996, the Company completed its three-year program of rationalizing its asset base by selling its Oklahoma gas gathering system and its interest in 438 wells in various locations. The wells sold represented 53% of the Company's total well count but less than 2% of proved reserves. Additionally in 1996, the Company received an unsolicited offer and sold a portion of its reserves in the
Hanlan Swan Hills Unit along with a portion of its interest in the related Hanlan-Robb gas processing plant in Alberta, Canada. The Company received $3.8 million from the 1996 sale of the Oklahoma gas gathering system (see discussion below) and $1.2 million from the partial sale of its interest in the Hanlan- Robb gas processing plant. Oil and gas property sales in 1995 were primarily non-performing fee mineral interests.
In March 1996, the Company sold its SW Oklahoma City Field gas gathering system for $3.8 million. The Company's total gain on the sale was $3.1 million, with $1.0 million being recognized in the first quarter of 1996 in "investment and other income" on the consolidated statement of operations while the remaining $2.1 million of the gain was deferred. The $2.1 million deferred revenue will be recognized in future periods as a component of gas revenues by partially offsetting the gas gathering fees paid by the Company over the productive life of the Company's SW Oklahoma City Field. Through December 31, 1997, $1.4 million has been recognized, leaving a balance of $685,000 in "deferred revenue" on the consolidated balance sheet as of December 31, 1997.
The Company has entered into a $50.0 million revolving credit agreement dated June 26, 1997 with the Toronto-Dominion Bank, the agent, and the Bank of Nova Scotia. Initial borrowing availability under this new facility was $25.0 million. On June 30, 1997, the Company was advanced $13.0 million to fund the Gulf Coast Acquisition and to replace amortizing principal payments under the Series A and B Notes of the Company. The Company has classified $11.0 million as "long-term" and $2.0 million as "current" on the accompanying consolidated balance sheet as of December 31, 1997. The facility is for a five-year term through July 1, 2002 with quarterly borrowing base amortization beginning September 30, 2000. The borrowings can be funded by either Eurodollar loans or Prime loans. The interest rate on the borrowings is equal to an interest rate spread plus either the Eurodollar rate or the Prime rate. The interest spread is determined from a sliding scale based on the Company's borrowing base percentage utilization in effect from time to time. The spread ranges from 5/8% to 1 1/4% on Eurodollar loans and 1/8% to 1/4% on Prime loans. The Company's average interest rate on the 1997 outstanding borrowings under this facility was 6.8%.
On December 30, 1996, the Company, through a wholly-owned Canadian subsidiary, entered into a long-term borrowing agreement with the Royal Bank of Canada (RBC) whereby the Company borrowed $3.5 million to partially fund the Millarville Acquisition. Such agreement was amended on November 20, 1997. The amended agreement allows the Company to forego principal payments during the first year and a half. Additionally, the Company may elect to pay interest only (Interest Only Period) in subsequent years if the Company's Canadian subsidiary meets certain borrowing base tests. Otherwise, the loan becomes payable over a three-year period beginning as of July 1 as follows: $1,510,000 in the first year, $1,147,000 in the second year and $839,000 in the third year (the Term Period). The Company classified $2.7 million as "long-term" and $756,000 as "current" on the accompanying consolidated balance sheet as of December 31, 1997. The borrowings may be funded by RBC Prime loans or Bankers' Acceptances (BA) loans. During the Interest Only Period, the Company pays interest at the RBC prime rate plus 1/2% on Prime loans and pays the BA rate plus 1/2% and an acceptance fee on BA loans. During the Term Period, the Company pays interest at the RBC prime rate plus 3/4% on Prime loans and pays the BA rate plus 3/4% and an acceptance fee on BA loans. The Company 's average interest rate on the 1997 outstanding borrowings under this agreement was 5.8%.
In July 1993, PetroCorp issued $40.0 million in senior notes. The Note Purchase Agreement established $10.0 million of Senior Adjustable Rate Notes Series A, due June 30, 1999 (the Series A Notes), payable to a subsidiary of USF&G Corporation (a 20% shareholder of the Company), and $30.0 million of 7.55% Senior Notes Series B, due June 30, 2008 (the Series B Notes), payable to two wholly-owned subsidiaries of CIGNA Corporation (formerly an 18% shareholder of the Company) and to four unaffiliated institutional investors in amounts totaling $20.0 million and $10.0 million, respectively. Mandatory redemptions commenced on December 31, 1994 for the Series A Notes and commenced on
December 31, 1995 for the Series B Notes. As of December 31, 1997, the remaining principal balances for the Series A and B Notes were $2.5 million and $23.4 million, respectively, for a total of $25.9 million, of which $4.7 matures in 1997. Interest on the Series A Notes is adjustable, based on a spread of 115 basis points over the London Interbank Offered Rate (LIBOR). The Company may select a rate which may be applicable for a one-, three- or six- month period. Interest is payable in arrears at the end of the selected period. Interest on the Series B Notes is fixed at a rate of 7.55% and is payable semiannually in arrears.
The Company's Canadian subsidiary redeemed its redeemable preferred stock on August 9, 1994 for $7.0 million and simultaneously issued $7.0 million in nonrecourse long-term notes payable with similar financial terms. At December 31, 1997, the nonrecourse long-term notes payable balance was $4.0 million, of which $730,000 was classified as "current."
As the Company has both the ability and intent to refinance $4.0 million of its current maturities of long-term debt utilizing its new revolving credit facility, $4.0 million has been reclassified from "current" to "long-term " on the Company's accompanying consolidating balance sheet as of December 31, 1997.
Product prices continue to be volatile. Since December 1997, U.S. and Canadian oil and gas prices have declined significantly. Under rules promulgated by the Securities and Exchange Commission, companies that follow the full cost accounting method are required to make quarterly "ceiling test" calculations using product prices in effect at that time (see Note 3 to the Consolidated Financial Statements--Property, Plant and Equipment). In the future, should prices remain depressed or decline further and depending on drilling results, the Company could be required to record a valuation adjustment to its oil and gas property balances, resulting in a charge against earnings.
Prior to 1997, the Company has utilized hedging transactions to manage its exposure to price fluctuations on its sales of oil and natural gas. Realized gains and losses from the Company's hedging activities were included in oil and gas revenues in the period of the hedged production. Normally, any realized and unrealized gains and losses prior to the period when the hedged production occurs would be deferred. Previously, the Company has used oil and natural gas futures contracts or natural gas option contracts traded on the NYMEX to hedge its oil and gas sales. The Company had no open hedging positions as of December 31, 1997, and has not hedged any of its production since October 1996.
The Company's Board of Directors has approved a capital budget of $12.0 million for 1998. The approved 1998 capital budget includes expenditures for exploration and development projects and for producing property acquisitions. However, actual levels of expenditures for planned exploration and development projects and producing property acquisitions may vary significantly due to many factors, including drilling results, oil and gas prices, industry conditions and acquisition opportunities, among others.
The Company plans to finance its 1998 capital expenditures with its cash flow from operations and working capital. If the Company increases its exploration, development and acquisition activities in the future, capital expenditures may require additional funding obtained through borrowings from commercial banks and other institutional sources, public offerings of equity or debt securities and existing and future relationships with institutional investment partners.
YEAR 2000 ISSUES
The Year 2000 presents significant issues for many computer systems. Much of the software in use today may not be able to accurately process data beyond the year 1999. The vast majority of computer systems process transactions using two digits for the year of the transaction, rather than the full four digits, making such systems unable to distinguish January 1, 2000 from January 1, 1900. Such systems may encounter significant processing inaccuracies or become inoperable when Year 2000 transactions are
processed. Such matters could not only impact the Company in its day-to-day operations but also impact the Company's financial institutions, customers and vendors. The Company's Management is in the process of identifying or remediating Year 2000 issues and does not expect any issues to arise that would materially impact the Company's financial condition or operations.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Not Applicable ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required by this item appears on pages 27 through 54 of this report.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
There is no matter required to be disclosed in response to this item.
PART III
In accordance with paragraph (3) of General Instruction G to Form 10-K, Part III of this Report is omitted because the Company will file with the Securities and Exchange Commission not later than 120 days after the end of the fiscal year ended December 31, 1997 a definitive proxy statement pursuant to Regulation 14A involving the election of directors, which proxy statement is incorporated herein by reference (with the exception of certain portions noted therein that are not so incorporated by reference).
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements
2. Financial Statement Schedules
Not Applicable.
3. Exhibits
- -------- * Incorporated by reference.
(b) Reports on Form 8-K
None.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of PetroCorp Incorporated
In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a)(1) on page 24 present fairly, in all material respects, the financial position of PetroCorp Incorporated and its subsidiaries at December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PRICE WATERHOUSE LLP
Houston, Texas March 11, 1998
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1997 AND 1996
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
The accompanying notes are an integral part of these financial statements.
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF OPERATIONS
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of these financial statements.
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(IN THOUSANDS)
The accompanying notes are an integral part of these financial statements.
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
The accompanying notes are an integral part of these financial statements.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
1. SUMMARY OF ACCOUNTING POLICIES
General
PetroCorp Incorporated, a Texas corporation, is engaged in the exploration, development, acquisition and the production and sale of crude oil and natural gas in North America. The terms "PetroCorp" and "Company" refer to PetroCorp Incorporated and its subsidiaries. PetroCorp operates in Canada through its wholly-owned Canadian subsidiaries as follows: PCC Energy Inc. (PCC Inc.), PCC Energy Limited and PCC Energy Corp. PetroCorp's wholly-owned subsidiary, Fidelity Gas Systems, Inc. (FGS), was merged into PetroCorp in 1997.
Principles of Consolidation
The accompanying financial statements include the accounts of the Company and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Certain prior-period amounts have been reclassified to conform to the current-year presentation.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires the Company to make estimates and assumptions that affect the amounts reported in the financial statements and the accompanying notes. Actual results may differ from such estimates.
Property, Plant and Equipment
The Company follows the full cost method of accounting for oil and gas properties whereby all productive and nonproductive exploration and development costs incurred for the purpose of finding oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, together with internal costs directly attributable to property acquisition, exploration and development activities. No gains or losses are recognized upon the sale or other disposition of oil and gas properties, except in unusually significant transactions.
The costs of the Company's oil and gas properties, including estimated future development and dismantlement costs, are depreciated on a country-by-country basis using a composite unit-of-production rate. An additional valuation adjustment is made on a country-by-country basis if net capitalized costs of the Company's oil and gas properties exceed the capitalization ceiling, which is calculated on a quarterly basis as the sum of (1) the present value (10%) of future net revenues from estimated production of proved oil and gas reserves plus (2) the lower of cost or estimated fair value of the unproved properties, less (3) the related income tax effects.
Plant and related facilities, consisting principally of a gas processing plant in Alberta, Canada, are being depreciated on a straight-line basis over a remaining estimated useful life of approximately five years. Other property and equipment are depreciated by the straight-line method at rates based on the estimated useful lives of the assets ranging from five to ten years.
At December 31, 1997 and 1996, the cumulative amount of accrued site restoration and dismantlement costs approximated $357,000 and $140,000, respectively.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
Revenue Recognition
Revenues from the sale of petroleum produced are recognized upon the passage of title, net of royalties and net profits royalty interests.
Revenues from natural gas production are recorded using the sales method, net of royalties and net profits royalty interests. When sales volumes exceed the Company's entitled share, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds the Company's share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. At December 31, 1997 and 1996, the Company has included in accrued liabilities $35,000 and $32,000 with respect to 22,000 Mcf and 20,000 Mcf, respectively, of overproduced imbalances.
In December 1994, the Company initiated a hedging program to manage its exposure to price fluctuations on its sales of oil and natural gas. Since initiating the hedging program, the Company has used oil and natural gas futures contracts or natural gas option contracts traded on the New York Mercantile Exchange (NYMEX) to hedge its oil and gas sales. The Company combines as a unit certain purchased and written natural gas options for hedging purposes. Realized gains and losses from the Company's hedging activities are included in oil and gas revenues in the period of the hedged production. Normally, any realized and unrealized gains and losses prior to the period when the hedged production occurs are deferred (see Note 11). No hedges were in place during 1997.
Revenues from plant processing are recognized at the time associated natural gas is processed and sold at the plant tailgate. Other revenues include revenues associated with the field gathering of third-party natural gas from certain properties in which the Company has an interest and revenues from the sale of sulfur in Canada.
Accounts Receivable
Accounts receivable relate primarily to sales of oil and gas and amounts due from joint interest partners for expenditures made by the Company on behalf of such partners. The Company reviews the financial condition of potential purchasers and partners prior to signing sales or joint interest agreements. At December 31, 1997 and 1996, the Company's allowance for doubtful accounts receivable, which is reflected in the consolidated balance sheet as a reduction in accounts receivable, totaled $50,000.
Income Taxes
The Company utilizes the liability method under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.
Foreign Currency Translation
The "functional currency" for translating the Company's Canadian accounts is the Canadian dollar. Assets and liabilities are translated into the reporting currency at the rate of exchange in effect at the balance sheet date while revenues, expenses, gains and losses are translated at the average exchange rate for the period. The resulting translation adjustments are accumulated in the foreign currency translation adjustment component of shareholders' equity. Foreign currency transaction gains and losses are recognized currently. For the years ended December 31, 1997, 1996 and 1995, the Company recognized
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
foreign currency losses of $36,000, $24,000 and $13,000, respectively. At December 31, 1997, 1996 and 1995, the exchange rates were ($1 CAN = $U.S.) $0.6992, $0.7297 and $0.7329, respectively, while the average exchange rates during such years were $0.7201, $0.7334 and $0.7312, respectively.
Earnings Per Share
During the year ended December 31, 1997, the Company adopted Statement of Financial Accounting Standard (SFAS) No. 128, "Earnings Per Share." SFAS No. 128 establishes new guidelines for computing earnings per share (EPS) and requires dual presentation of basic and diluted EPS for entities with complex capital structures. Basic EPS excludes dilution and is computed by dividing net income by the weighted average number of common shares outstanding during the period. Dilutive EPS reflects potential dilution and is computed by dividing net income by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the dilutive potential common shares had been issued. All prior period EPS data has been restated to conform with the provisions of SFAS No. 128.
Cash Equivalents
For purposes of the consolidated statement of cash flows, the Company considers all highly liquid debt instruments purchased with a maturity date of three months or less to be cash equivalents. Cash equivalents at December 31, 1997, 1996 and 1995 were $4,730,000, $7,407,000 and $13,623,000, respectively.
Other
During June 1997, the Financial Accounting Standards Board (FASB) issued SFAS No. 130, "Reporting Comprehensive Income." This statement requires disclosure of changes in equity from nonowner sources in a primary financial statement and the accumulated balance of such items as a separate caption within the shareholders' equity section of the balance sheet. SFAS No. 130 is effective for periods beginning after December 15, 1997. This pronouncement will impact the disclosure of the Company's foreign currency translation adjustment reported on the accompanying consolidated balance sheet.
During June 1997, the FASB issued SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information." SFAS No. 131 establishes standards for the method public entities report information about operating segments in both interim and annual financial statements issued to shareholders and requires related disclosures about products and services, geographic areas and major customers. This statement is effective for fiscal years beginning after December 15, 1997. Management believes the disclosure requirements of this statement will have no impact on its consolidated financial statements.
2. ACQUISITIONS
Gulf Coast Acquisition
On July 1, 1997, the Company acquired producing oil and gas properties located primarily in Louisiana for a cash purchase price of $9.2 million (the Gulf Coast Acquisition). This acquisition has been accounted for as a purchase and the results of operations of the oil and gas properties acquired are included in the Company's results of operations effective July 1, 1997.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
Millarville Acquisition
On December 23, 1996, the Company, through a wholly-owned Canadian subsidiary, acquired all of the outstanding common shares of Millarville Oil and Gas Ltd., a privately held Alberta Corporation that owns and operates oil and gas properties in Alberta, Canada (the Millarville Acquisition). The cash acquisition purchase price was $11.8 million which was allocated to oil and gas properties. This acquisition has been accounted for as a purchase and the results of operations of the oil and gas properties acquired are included in the Company's results of operations effective December 23, 1996.
Pro Forma Information
The following unaudited pro forma financial information has been prepared to give effect to the Gulf Coast Acquisition as if such transaction had occurred at the beginning of 1997 and 1996 and the Millarville Acquisition as if such transaction had occurred at the beginning of 1996. The historical results of the Company's operations have been adjusted to reflect (i) the increase in revenues and operating expenses directly attributable to the acquisitions, (ii) increases in depletion, depreciation and amortization directly attributable to the acquisitions, (iii) the increase in interest expense related to the bank debt incurred as a result of the acquisitions and (iv) the increase in income taxes resulting from future income directly attributable to the acquisitions. The pro forma amounts do not purport to be indicative of the results of operations that would have been reported had the acquisitions occurred as of the date indicated, or that may be reported in the future (in thousands, except per share amounts).
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
3. PROPERTY, PLANT AND EQUIPMENT
Investments in property, plant and equipment were as follows at December 31, 1997 and 1996 (amounts in thousands):
Depreciation, depletion and amortization for all property, plant and equipment for the years ended December 31, 1997, 1996 and 1995 was $16,880,000, $12,279,000 and $13,145,000, respectively. Oil and gas property depreciation, depletion and amortization for the years ended December 31, 1997, 1996 and 1995 was $15,383,000, $10,788,000 and $11,510,000, respectively. Depreciation, depletion and amortization per equivalent barrel (using a Mcf-to-barrel conversion factor of 6 to 1) for the years ended December 31, 1997, 1996 and 1995 was $9.06, $6.38 and $6.21, respectively, for U.S. operations and $2.97, $2.03 and $2.13, respectively, for Canadian operations. The total composite rates were $6.60, $5.24 and $5.22 for the years ended December 31, 1997, 1996 and 1995, respectively. At June 30, 1995, the Company's net capitalized costs of its U.S. oil and gas properties exceeded the capitalization ceiling by $8,500,000. This amount is reflected in the Company's results of operations for the year ended December 31, 1995.
Product prices continue to be volatile. Since December 1997, U.S. and Canadian oil and gas prices have declined significantly. In the future, should prices remain depressed or decline further and depending on drilling results, the Company could potentially be required to record a valuation adjustment to its oil and gas property balances, resulting in a charge against earnings.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
4. LONG-TERM DEBT
The Company's total long-term debt is payable as follows (amounts in thousands):
Debt maturing in each of the years during the five-year period subsequent to December 31, 1997 is as follows: $8,186,000 in 1998, $5,900,000 in 1999, $9,400,000 in 2000, $8,300,000 in 2001 and $9,400,000 in 2002.
Reclassification of current debt maturities to long term represents unused capacity under the TD Bank credit agreement at December 31, 1997. The Company has both the intent and ability to refinance this debt on a long-term basis.
Series A and Series B Senior Notes
Series A and Series B Senior Notes at December 31, 1997 and 1996 consisted of the following (amounts in thousands):
Redemption payments to affiliates and nonaffiliates were $2,025,000 and $2,975,000 in 1997 and $4,142,000 and $808,000 in 1996, respectively.
Interest paid to affiliates and nonaffiliates for the years ended December 31, 1997, 1996 and 1995 amounted to $303,000 and $1,941,000, $1,883,000 and $706,000, and $2,150,000 and $755,000, respectively.
On July 29, 1993, the Company entered into the Note Purchase Agreement with subsidiaries of CIGNA Corporation and USF&G Corporation together with certain other insurance companies to refinance existing notes totaling $36,976,000 with $40,000,000 in proceeds received under the Note Purchase Agreement. At that time, subsidiaries of CIGNA Corporation and USF&G Corporation were
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
shareholder affiliates of the Company. In October 1996, the subsidiary of CIGNA Corporation sold its shares of the Company and is, therefore, no longer a shareholder affiliate. The Note Purchase Agreement provides for $10,000,000 in aggregate principal amount of senior adjustable rate notes, Series A, due June 30, 1999, payable to a subsidiary of USF&G Corporation, and $30,000,000 in aggregate principal amount of 7.55% senior notes, Series B, due June 30, 2008, payable to two subsidiaries of CIGNA Corporation and to four unaffiliated insurance companies, in the amounts of $20,000,000 and $10,000,000, respectively.
Interest on the Series A notes is adjustable, based on a spread of 115 basis points over the London Interbank Offered Rate (LIBOR). The Company may select a rate which may be applicable for a one-, three- or six-month period. Interest is payable in arrears at the end of the period selected. Interest rates on the Series A notes ranged from 6.71% to 6.99%, 6.68% to 7.09% and 6.71% to 7.40% during 1997, 1996 and 1995, respectively. Interest on the Series B notes is fixed at a rate of 7.55% and is payable semiannually in arrears.
Mandatory redemptions commenced in 1994 and are payable semiannually based on a fixed schedule. Series A and B redemption payments are scheduled through June 30, 1999 and June 30, 2008, respectively. Series A notes are callable at par. Series B notes are callable at the greater of the outstanding principal or a formula-based make-whole amount.
The Note Purchase Agreement imposes upon the Company certain financial covenants and other restrictive covenants that have the effect of restricting the amount of dividends on the common stock that may be paid by the Company.
Bank Debt
On June 26, 1997, the Company entered into a $50 million revolving credit agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of Nova Scotia. The current borrowing availability under this new facility is $25 million. The facility is for a five-year term through July 1, 2002 with quarterly borrowing base amortization beginning September 30, 2000. The borrowings can be funded by either Eurodollar loans or Prime loans. The interest rate on the borrowings is equal to an interest rate spread plus either the Eurodollar rate or the Prime rate. The interest spread is determined from a sliding scale based on the Company's borrowing base percentage utilization in effect from time to time. The spread ranges from 5/8% to 1 1/4% on Eurodollar loans and 1/8% to 1/4% on Prime loans.
The Company was advanced $13,000,000 on June 30, 1997 primarily to fund the Gulf Coast Acquisition and to replace amortizing principal payments under the Series A and B Notes of the Company. The Company initially funded the $13,000,000 advance with a Prime loan but rolled over the debt into a six-month Eurodollar loan on July 7,1997 with an interest rate of 6.8%.
The $50 million revolving credit agreement prohibits the declaration and payment of dividends on the common stock of the Company.
On December 30, 1996, the Company, through a wholly-owned Canadian subsidiary, entered into a long-term borrowing agreement with the Royal Bank of Canada (RBC) whereby the Company borrowed $3,496,000 to partially fund the Millarville Acquisition. Such agreement was amended on November 20, 1997. The amended agreement allows the Company to forego principal payments in the first year and a half. Additionally, the Company may elect to pay interest only (Interest Only Period) during subsequent
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
years if the Company's Canadian subsidiary meets certain borrowing base tests. Otherwise, the loan becomes payable over a three-year period beginning as of July 1 as follows: $1,510,000 in the first year, $1,147,000 in the second year and $839,000 in the third year (the Term Period). The borrowings may be funded by RBC Prime loans or Banker's Acceptances (BA) loans. During the Interest Only Period, the Company pays interest at the RBC prime rate plus 1/2% on Prime loans and pays the BA rate plus 1/2% and an acceptance fee on BA loans. During the Term Period, the Company pays interest at the RBC prime rate plus 3/4% on Prime loans and pays the BA rate plus 3/4% and an acceptance fee on BA loans. The Company initially funded the debt with a Prime loan but rolled over the debt into a twelve-month BA loan on January 9, 1997 with an effective interest rate of 5.8%.
Nonrecourse Notes Payable
On December 12, 1991, the Company (through its Canadian subsidiary, PCC Inc.) acquired an interest in certain oil and gas properties and related gas processing facilities located in the Hanlan-Robb area in western Alberta, Canada. The Company used the proceeds from the issuance of redeemable preferred stock of PCC Inc. to partially fund the acquisition. The holders of the preferred stock also separately and concurrently acquired an interest in the same oil and gas properties as the Company.
On August 9, 1994, PCC Inc. entered into agreements whereby PCC Inc. redeemed the remaining shares of its redeemable preferred stock for $7,034,000. Simultaneously, PCC Inc. issued $7,034,000 in nonrecourse long-term notes payable (the Nonrecourse Notes Payable) to the previous holders of the preferred stock with financial terms similar to the redeemable preferred stock. Consistent with the redeemable preferred stock, the Nonrecourse Notes Payable are denominated in Canadian dollars.
During 1997 and 1996, interest payments were $669,000 and $896,000, respectively, while principal payments totaled $757,000 and $1,938,000, respectively. Additionally, in 1997 and 1996, the Company issued $245,000 and $261,000 of additional notes, respectively, as provided under the provisions of the agreements.
Interest accrues and is payable on a quarterly basis at a rate of 15% per annum. In addition, redemptions are required to be made quarterly, based on a fixed schedule through December 31, 2002. Interest and redemption payments are made only to the extent there are sufficient cash proceeds from production and sale of oil and gas reserves related to the interest in the Hanlan-Robb assets acquired by the holders of the Nonrecourse Notes Payable. To the extent interest and redemptions exceed such cash proceeds, the excess amount is carried forward to the next quarter.
5. DEFERRED REVENUE
In March 1996, FGS sold its SW Oklahoma City Field gas gathering system for $3,835,000. The Company's total gain on the sale was $3,088,000, with $999,000 being recognized in the first quarter of 1996 in "investment and other income" on the consolidated statement of operations while the remaining $2,089,000 of the gain was deferred. The $2,089,000 deferred revenue will be recognized in future periods as a component of gas revenues by partially offsetting the gas gathering fees paid by the Company over the productive life of the Company's SW Oklahoma City Field. Through December 31, 1997, $1,404,000 has been recognized, leaving a balance of $685,000 in "deferred revenue" on the consolidated balance sheet as of December 31, 1997.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
6. PREFERRED STOCK
The Company is authorized to issue up to 1,000,000 shares of preferred stock, par value $0.01 per share. However, no preferred shares have been issued. The Company's Board of Directors is authorized to divide the preferred stock into series and, with respect to each series, to determine the dividend rights, dividend rate, conversion rights, voting rights, redemption rights and terms, liquidation preferences, sinking fund provisions, the number of shares constituting the series and the designation of such series. The Board of Directors could, without shareholder approval, issue preferred stock with voting rights and other rights that could adversely affect the voting power of holders of common stock and could be used to prevent a third party from acquiring control of the Company.
7. INCOME TAXES
The components of income (loss) before income taxes for the years ended December 31, 1997, 1996 and 1995 consisted of the following (amounts in thousands):
The provision (benefit) for income taxes consists of the following (amounts in thousands):
A reconciliation of the Company's United States income tax provision (benefit) computed by applying the statutory United States federal income tax rate to the Company's income (loss) before income taxes for the years ended December 31, 1997, 1996 and 1995 is presented in the following table (amounts in thousands):
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
Deferred tax assets and liabilities consist of the following at December 31, 1997 and 1996 (amounts in thousands):
As of December 31, 1997, the Company has U.S. net operating loss carryforwards of $17,765,000 and $11,466,000 for regular tax and alternative minimum tax purposes, respectively, which begin to expire in 2001. The Company is subject to certain restrictions under Section 382 on the annual utilization of a portion of its net operating loss carryforwards. Certain future changes in the Company's shareholders may impose additional limitations as well.
Under SFAS No. 109, the Company was required to increase deferred income taxes and oil and gas properties by $3,736,000 for the deferred tax effect of the excess of the Company's book basis of the stock acquired in the Millarville Acquisition over the tax basis of the net assets acquired.
The provision for Canadian income taxes differs from the amount of income tax determined by applying the Canadian statutory income tax rate to pretax Canadian income as a result of the following (amounts in thousands):
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
8. STOCK OPTION AND OTHER EMPLOYEE BENEFIT PLANS
In 1992, the Company established the 1992 PetroCorp Stock Option Plan (the Option Plan). The Option Plan allows up to 957,357 option shares to be granted and outstanding. The following table summarizes these options:
The weighted average exercise prices for options under the Option Plan outstanding at December 31, 1997, 1996 and 1995 were $7.86, $7.84 and $8.43, respectively.
In October 1996, all granted stock options under the Option Plan were fully vested and exercisable as a change in control, defined in the Option Plan as the change in ownership of more than 30% of the outstanding common shares of the Company, occurred after Kaiser-Francis Oil Company purchased the common shares owned by investment funds managed by First Reserve Corporation and the common shares owned by a subsidiary of CIGNA Corporation.
In 1997, the Company established the 1997 PetroCorp Non-Employee Director Stock Option Plan (the Director Option Plan) for the benefit of the Company's Board of Directors. This plan allows up to 75,000 option shares to be granted and outstanding. The following table summarizes these options.
The Director Options were fully vested at the date of grant.
Stock options under both plans expire ten years from the date of grant.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
The Company adopted SFAS No. 123, "Accounting for Stock Based Compensation," effective July 1, 1996. While SFAS No. 123 encourages entities to adopt the fair value based method of accounting for their stock-based compensation plans, the Company has elected to continue to utilize the intrinsic value method under Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." Accordingly, no compensation expense has been recognized for these stock-based compensation plans. Had compensation cost for the Option Plan and the Director Option Plan been determined based upon the fair value at the grant date for awards under the plans consistent with the methodology prescribed under SFAS No. 123 the Company's 1997 and 1996 net income and earnings per share would have been reduced by approximately $79,000 and $450,000 or $0.01 and $0.05 per share, respectively. The fair value of the options granted during 1997 is estimated as $126,000 on the date of grant using the Black-Scholes option-pricing model with the following assumptions: dividend yield of 0%, volatility of 31.1%, risk-free interest rate of 6.74% and an expected life of ten years. The fair value of the options granted during 1996 is estimated as $720,000 on the date of grant using the Black-Scholes option- pricing model with the following assumptions: dividend yield of 0%, volatility of 34.3%, risk-free interest rate of 5.7% and an expected life of ten years.
The Company has a savings plan, which became effective January 1, 1993, available to qualified employees and is qualified as a deferred compensation plan under Section 401(k) of the Internal Revenue Code. The Company matches employee contributions for an amount up to 6% of each employee's salary. The Company's contributions to the plan, which are charged to expense, totaled $188,000, $208,000 and $243,000 in 1997, 1996 and 1995, respectively.
9. EARNINGS PER SHARE
The following is a reconciliation of the numerators and denominators of the basic and diluted per share computations for the periods presented (amounts in thousands except per share amounts).
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
Options to purchase 445,740 shares of common stock at $10.00 per share were outstanding during the year ended December 31, 1997 but were not included in the computation of diluted EPS because the options exercise price was greater than the average market price of the common shares.
10. GEOGRAPHIC AREA INFORMATION
The principal business of the Company is oil and gas, which consists of the exploration, development, acquisition, exploitation and operation of oil and gas properties and the production and sale of crude oil and natural gas in North America. Pertinent information with respect to the Company's oil and gas business is presented in the following table (amounts in thousands):
The following table reflects purchasers which accounted for more than 10% of the Company's oil and gas revenues:
The majority of the Company's Canadian gas is dedicated under long-term contracts to Pan-Alberta Gas Ltd., a major Canadian aggregator. The Company does not believe the loss of any purchaser would have a material adverse effect on its financial position since the Company believes alternative sales arrangements could be made on relatively comparable terms.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
11. HEDGING PROGRAM AND FAIR VALUE OF FINANCIAL INSTRUMENTS
Hedging Program
Prior to 1997, the Company has utilized hedging transactions to manage its exposure to price fluctuations on its sales of oil and natural gas. Realized gains and losses from the Company's hedging activities were included in oil and gas revenues in the period of the hedged production. Normally, any realized and unrealized gains and losses prior to the period when the hedged production occurs would be deferred. Previously, the Company has used oil and natural gas futures contracts or natural gas option contracts traded on the NYMEX to hedge its oil and gas sales.
The Company recorded realized hedging losses of $918,000 in 1996 and hedging gains of $338,000 in 1995. No hedges were in place in 1997.
As a result of the decoupling of the relationship between the pricing of certain NYMEX natural gas futures contracts for the first quarter of 1996 and the Company's field prices for the same period, these futures contracts no longer qualified as hedges for accounting purposes. Accordingly, the Company recorded a $996,000 reduction to "investment and other income" during the fourth quarter of 1995.
Fair Value of Financial Instruments
The following information discloses the fair value of the Company's financial instruments in accordance with SFAS No. 107, "Disclosures About Fair Value of Financial Instruments" (amounts in thousands):
The carrying amounts approximate fair value for the Company's cash and cash equivalents, accounts receivable, accounts payable, the Series A, senior adjustable rate notes and bank debt. Due to the nature and terms of the Nonrecourse Notes Payable, the Company believes that it is not practicable to estimate the fair value. The Company estimates the fair value of the Series B, 7.55% senior notes using discounted cash flow analysis based on interest rates in effect at year end for the Company's Series A, senior adjustable rate notes.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
12. COMMITMENTS AND CONTINGENCIES
The Company has entered into operating lease agreements with noncancelable terms in excess of one year for office space. Future minimum lease payments are $418,000, $393,000, $396,000, $434,000 and $434,000 for the years ended December 31, 1997, 1998, 1999, 2000 and 2001, respectively. Total rental expense for office space for the years ended December 31, 1997, 1996 and 1995 was $648,000, $646,000 and $637,000, respectively.
There are other claims and actions pending against the Company. In the opinion of management, the amounts, if any, which may be awarded in connection with any of these claims and actions would not be material to the Company's consolidated financial position or results of operations.
13. RELATED PARTY TRANSACTIONS
The Company has engaged an engineering consulting company to procure certain services and equipment pertaining to its Canadian operations. The consulting company solicits bids from various vendors in order to obtain competitive pricing. During 1997, the consulting company procured $148,000 in an arm's- length transaction from an equipment supplier partly owned by a director of the Company's Canadian subsidiaries who is also a relative of the Company's Chief Executive Officer.
The Company is a joint interest owner in a project operated by Kaiser-Francis Oil Company, a shareholder affiliate. During 1997, the Company remitted $914,000 to Kaiser-Francis as payment of the Company's share of the joint operation.
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS OIL AND GAS RESERVES AND RELATED FINANCIAL DATA
DECEMBER 31, 1997, 1996 AND 1995
(UNAUDITED)
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
Presented below are costs incurred in petroleum property acquisition, exploration and development activities (amounts in thousands):
Included in the above amounts for the years ended December 31, 1997, 1996 and 1995 were $1,897,000, $1,690,000 and $1,962,000, respectively, of capitalized internal costs related to property acquisition, exploration and development. Under SFAS No. 109, the Company was required to increase deferred income taxes and oil and gas properties by $3,736,000 for the deferred tax effect of the excess of the Company's book basis of the stock acquired in the Millarville Acquisition over the tax basis of the net assets acquired. Such increase in oil and gas properties is not included in the above amounts.
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(UNAUDITED)
CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
The following table presents total capitalized costs of proved and unproved properties and accumulated depreciation, depletion and amortization related to petroleum producing operations (amounts in thousands):
Of the unproved properties capitalized cost at December 31, 1997, approximately $5,099,000 and $2,931,000 was incurred in 1997 and 1996, respectively. The Company anticipates evaluating these properties during subsequent years.
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(UNAUDITED)
RESULTS OF OPERATIONS FROM PETROLEUM PRODUCING ACTIVITIES
The results of operations from petroleum producing activities, which do not include revenues associated with the production and sale of sulfur, are as follows (amounts in thousands):
RESERVE QUANTITIES
Estimates of proved reserves of the Company and the related standardized measure of discounted future net cash flow information are based on the reports of independent petroleum engineers. These estimates represent the Company's interest in the reserves associated with properties held directly and its proportionate share of reserves held indirectly through partnerships or joint ventures.
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(UNAUDITED)
The Company's estimates of its proved reserves and proved developed reserves of oil and gas as of December 31, 1997, 1996 and 1995 and the changes in its proved reserves are as follows:
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(UNAUDITED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The standardized measure of discounted future net cash flows was calculated by applying current prices to estimated future production, less future expenditures (based on current costs) to be incurred in developing and producing such proved reserves and the estimated effect of future income taxes based on the current tax law. The resulting future net cash flows were discounted using a rate of 10% per annum.
The standardized measure of discounted future net cash flow amounts contained in the following tabulation do not purport to represent the fair market value of oil and gas properties. No value has been given to unproven properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. Future realization of oil and gas prices over the remaining reserve lives may vary significantly from current prices. In addition, the method of valuation utilized, based on current prices and costs and the use of a 10% discount rate, is not necessarily appropriate for determining fair value.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows (amounts in thousands):
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(UNAUDITED)
The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows (amounts in thousands):
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(UNAUDITED)
The standardized measure amounts are based on current prices at each year end and reflect overall weighted average prices of:
Information relating to sulfur in Canada which has not been included in the standardized measure is summarized as follows:
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(UNAUDITED)
SUMMARIZED QUARTERLY FINANCIAL DATA
(UNAUDITED) (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- -------- (1) Revenues less operating expenses other than general and administrative. (2) In the first quarter of 1996, the Company recorded a $629,000 after-tax gain related to the sale of its Oklahoma gas gathering system.
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.
PetroCorp Incorporated (Registrant)
/s/ W. Neil McBean By:__________________________________ W. Neil McBean President and Chief Executive Officer (Principal Executive Officer)
Date: March 27, 1998
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE
/s/ W. Neil McBean President, Chief March 27, 1998 - ----------------------------------- Executive Officer W. Neil McBean (Principal Executive Officer) and Director
/s/ Craig K. Townsend Vice President-- March 24, 1998 - ----------------------------------- Finance, Secretary Craig K. Townsend and Treasurer (Principal Financial Officer and Principal Accounting Officer)
/s/ Lealon L. Sargent Chairman of the Board March 24, 1998 - ----------------------------------- of Directors Lealon L. Sargent
/s/ Thomas N. Amonett Director March 27, 1998 - ----------------------------------- Thomas N. Amonett
/s/ Gary R. Christopher Director March 23, 1998 - ----------------------------------- Gary R. Christopher
/s/ G. Jay Erbe, Jr. Director March 24, 1998 - ----------------------------------- G. Jay Erbe, Jr.
/s/ Stephen M. McGrath Director March 23, 1998 - ----------------------------------- Stephen M. McGrath
/s/ Robert C. Thomas Director March 20, 1998 - ----------------------------------- Robert C. Thomas
EXHIBIT INDEX