Item 1. Business.
General
PetroCorp Incorporated is an independent energy company engaged in the acquisition, exploration and development 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, 1998, the Company's proved reserves totaled 4.0 MMBbls of oil and 79.4 Bcf of natural gas and had an estimated pretax present value of future net revenues (PV-10) of $78 million. On a Mcfe 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 $9.2 million, as well as interests in natural gas processing and gathering facilities with a net book value of $3.8 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
PetroCorp and its Canadian, wholly-owned PCC Energy subsidiaries acquire, explore and develop oil and natural gas properties in North America.
Acquisition Strategy. The Company has grown, in large part, through the acquisition of producing oil and gas properties. The Company generally focuses on acquisitions of long-lived natural gas reserves, located onshore in North America, and prefers acquisitions that provide additional potential through development or exploitation efforts, as well as exploratory drilling opportunities.
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 3D seismic technology) available to its exploration and development teams, and developed major exploration and development projects in South Texas, Mississippi, Oklahoma, and Alberta, Canada. PetroCorp has the capability to perform some reprocessing, as well as all visualization and interpretation of its seismic database completely in-house.
Recent Acquisition Activity
South Texas Acquisition. In June 1998, PetroCorp acquired a significant position in a strategic exploration and development drilling alliance in South Texas. Partners include Mobil Exploration & Producing U.S. Inc. and J.M. Huber Corporation. The acquisition included a 17.5% working interest in 25,000 acres controlled by the alliance (primarily in Duval County, Texas), as well as rights to more than 100 square miles of new 3D seismic data over the area. The program has already yielded its first significant new field discovery. At year- end 1998, the Rich Hurt Field in Duval County was producing 24 MMcf/D from four successful Wilcox completions.
Exploration and Development Activities
South Texas Wilcox Play. The Company has devoted significant manpower and technical expertise to its recent South Texas Acquisition, completed in June 1998 (see South Texas Acquisition in preceding section). Primary targets in this area are Wilcox sand intervals at depths ranging from 8,000 to 13,000 feet. Since committing to the acquisition, PetroCorp has participated in four successful wells out of seven total drilled. The four successful wells are completed in an area now defined as the Rich Hurt Field in Duval County and were producing at a combined rate of 24 MMcf/D at year-end 1998. To date, the Company had received approximately 80 square miles of the 100+ square miles of 3D seismic data currently committed to by the alliance. The three-company alliance has identified more than 80 prospects/leads in the area and currently has a leasehold position over 35 of these ideas.
Southwest Oklahoma City Unit Waterflood. Discovered in 1987, the PetroCorp operated Southwest Oklahoma City Field is located in an established production trend bounded by the Wheatland-Will Rogers Airport Field complex to the southwest and the Oklahoma City Field to the east. The Company operates 61 wells in the field and has a working interest in two additional wells in the area. Since 1996, activity has focused on implementation of waterflood activities at the SW Oklahoma City Unit, targeting a Prue sand interval at 6,500 feet. PetroCorp owns an 86.4% working interest in this unit, which is showing a positive response to injection consistent with initial expectations and offset analogs.
Mississippi Salt Basin. The Mississippi Salt Basin is one of PetroCorp's significant exploration plays. Through year-end 1998, the Company 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. Since 1997, PetroCorp has been involved in a seismic joint venture with a subsidiary of Shell Oil Company which give the Company access to Shell's extensive database, including 13,000 line miles of 2D seismic, covering 18 counties.
Hanlan-Robb Area. Located in the foothills of the Canadian Rockies in western Alberta, the Hanlan-Robb area is the largest in terms of reserves and production, in PetroCorp's property portfolio. The Company owns an interest in ten fields in this area, covering 47,000 developed acres with current combined gross production of 220 MMcf/D. PetroCorp has an interest in 73,900 undeveloped acres in this area. Recent activity in the area has focused on the sidetracking of existing vertical wells and the installation of field compression for the Hanlan Swan Hills Gas Unit #1 (a 1.4 Tcf EUR gas field). PetroCorp also participated in two horizontal re-drills in the Shaw/Basing area which have more than doubled gross production from the Company's acreage to 24 MMcf/D. 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.
PetroCorp owns a 24.5% working interest in the centrally located Hanlan-Robb gas processing plant and varying interests in a gas gathering system that connects all of the Company's currently producing Hanlan-Robb fields to the plant. The original design capacity of the plant was recently expanded to 380 MMcf/D. Two new major pipeline systems capable of transporting gas to the plant from an area of approximately 2,400 square miles have recently begun delivering third-party gas to the plant for processing. This new third-party gas, for which processing fees are received, has increased plant throughput from 220 MMcf/D to approximately 300 MMcf/D at year-end 1998. As a result of the increased plant throughput and third-party processing revenue, total operating costs for PetroCorp have been reduced from $0.15/Mcf in 1998 to an anticipated $0.06/Mcf for 1999. The Company also has adequate excess capacity (approximately 22 MMcf/D in 1999) in the plant for its exploration and development plans in the area.
Minehead Prospect. Located ten miles east of the Hanlan-Robb Gas Plant, the Minehead exploratory prospect exposes the Company to significant reserve additions. Targeting the Swan Hills formation, the
prospect is on trend with the Blackstone Field (1.0 Tcf) and the Hanlan Unit (1.4 Tcf). A well testing the concept was drilling at year-end 1998, at no cost to the Company. PetroCorp owns a 2.3% Gross Overriding Royalty in this exploratory well, convertible to a 9.4% working interest upon payout of the well, as well as a 9.4% working interest in the 12,800 surrounding leased acres. The well is expected to reach total depth by April 1999.
McLeod Field. As part of an acquisition in late 1996, the Company acquired one shut-in oil well in this field in west central Alberta, Canada. Since then, the PetroCorp has drilled six wells to develop production from three formations. The Company's working interests vary from 12% to 100% in 8.8 sections (approximately 5,600 acres).
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, 1998, 1997, and 1996. See Note 11 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. During 1998, the majority of the Company's Canadian gas was dedicated under long-term contracts to Pan-Alberta Gas Ltd. (Pan-Alberta), a major Canadian gas aggregator and marketer, which was affiliated with the pipeline authorized to gather all gas in the province of Alberta. Under these contracts, approximately 75% of the Company's Canadian gas was resold into the United States, predominantly to markets in the upper Midwest region. PetroCorp received a price, per Mcf, from Pan-Alberta equal to their resale price, less certain costs.
PetroCorp, along with other Canadian producers, reached a legal settlement with Pan-Alberta in December 1998 that has changed the fundamental ownership structure of Pan-Alberta. Effective December 31, 1998, Pan-Alberta is now owned by 435 Canadian producers (including PetroCorp). The contractual relationship between the 435 pool producers and Pan-Alberta has not changed, but all costs and benefits from Pan-Alberta's marketing efforts now pass directly to the producers. As part of the settlement, approximately 50% of PetroCorp's dedicated gas volumes have been released from the Pan-Alberta contracts. These released volumes are now sold on the spot market at prevailing prices.
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, 1998, Pan-Alberta, Conoco Inc. (the purchaser of a portion of the Company's U.S. gas) and EOTT Energy Operated Limited Partnership (one of the Company's purchasers of oil) accounted for 23%, 10% and 10% 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 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 13 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, 1998, PetroCorp had 53 full-time employees.
Item 2.
Item 2. Properties.
Principal Properties
The Company's proved oil and gas properties are relatively concentrated. Approximately 85% of the PV-10 from the Company's proved reserves at December 31, 1998 was attributable to five 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, 1998, 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 40% of the Company's 1998 net daily gas production. The Company owns an interest in ten producing fields in this area, covering 47,000 developed acres, with current combined production of 220 MMcf/D. PetroCorp has additional interests in 73,900 undeveloped acres in this area. The key field is the world-class Hanlan Swan Hills Gas Unit #1, with an estimated ultimate recovery of 1.4 Tcf and current gross production of 160 MMcf/D. PetroCorp's ownership is part of a joint venture managed by the Company with institutional investors that collectively own 21.6% of the field. PetroCorp's working interest in this field is 35% of the joint venture, or 7.6%. Petro-Canada (not an affiliate of PetroCorp) is the largest interest owner in the area and operates the Hanlan-Robb area fields and the related gathering system and processing plant.
Oklahoma City Area. Includes the Southwest Oklahoma City Field located within the metropolitan Oklahoma City area in Oklahoma and the Edmond Prospect located just north of Oklahoma City. In the Southwest Oklahoma City Field area, PetroCorp operates 61 wells and has a working interest in two additional wells. The Company also owns a 4% working interest in the adjacent Will Rogers Unit, operated by Marathon. The key property is the PetroCorp operated SW Oklahoma City Unit, a field-wide waterflood unit, approved in 1996, targeting the Prue formation at 6,500 feet. Current unit production is approximately 225 BOPD and 2,500 Mcf/D. The Company owns an 86.4% working interest in the unit.
South Louisiana Area. Includes ownership in the East Riceville Field in Vermillion Parish and the Scott Field in Lafayette Parish. East Riceville is two-well gas field producing 28 MMcf/D from a Miogyp
reservoir at approximately 17,000 feet. PetroCorp owns a 13.8% working interest in this field, which is operated by Murphy Exploration and Production Company. The Company owns a 3.6% working interest in the Scott Field, which is operated by Hallwood Petroleum, Inc. The majority of the current production and asset value in the Scott Field is attributable to two wells producing from a Bol Mex reservoir below 13,000 feet at a combined rate of approximately 50 MMcf/D.
McLeod Field. As part of an acquisition in late 1996, the Company acquired one shut-in oil well in this field in west central Alberta, Canada. Since then, the PetroCorp has drilled six wells to develop production from three formations. The Company's working interests vary from 12% to 100% in 9.8 sections (approximately 6,240 acres).
South Texas Area. Located in western Duval County, Texas, the Rich Hurt Field is a four-well gas field currently producing approximately 24 MMcf/D from an Upper Wilcox sand interval at approximately 8,700 feet. PetroCorp acquired its interest in the field in June 1998, coincident with the completion of the discovery well, the Mobil Ponciano Ruiz #1. Since then, the Company has participated in three consecutive successful development wells in the field. PetroCorp owns a 17.5% working interest in all four wells.
Other Properties. Other significant U.S. properties include the Glick field located in south-central Kansas, the Hunter Misener Unit located in Alfalfa County, Oklahoma, the Maynor Creek Field in Wayne County, Mississippi, the Harris Field in Live Oak County, Texas, and the Paradox Basin area of southwest Colorado. Other significant Canadian properties include the Trochu Prospect in south-central Alberta and the Worsley Triassic A Pool located on the north flank of the Peace River Arch in Alberta.
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, 1998. 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 $862,000 related to the sale of sulfur. (2) Proved and proved developed present values of future net revenues include $468,000 related to the sale of sulfur.
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, 1998.
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, 1998.
- -------- (1) Approximately 36% of net (approximately 23% of net participating interest) undeveloped acres are covered by leases that expire during 1999. (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, 1998, the Company had working interests in 230 gross (74 net) producing oil wells and 187 gross (36 net) producing gas wells. Of these wells, 19 gross (17 net) oil wells and 46 gross (9 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, 1998, 1997 and 1996 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, 1998, the Company was participating in the drilling of 1 gross (.2 net) well in the United States.
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 of the Company's currently producing Hanlan-Robb fields to the Hanlan-Robb plant. Commissioned in 1983, the estimated replacement value is approximately $325 ($C500) million. The original design capacity of 300 MMcf/D was recently expanded to 380 MMcf/D and two new major pipeline systems have recently begun delivering third-party gas to the plant for processing. This new third-party gas, for which processing fees are received, has increased plant throughput from 220 MMcf/D to approximately 300 MMcf/D at year-end 1998. PetroCorp owns a 24.5% working interest in the plant and varying working interests in the gathering systems, dehydration and compression facilities that deliver gas to the plant.
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 primary office. The Company also leases approximately 8,200 square feet in Oklahoma City, Oklahoma and approximately 4,000 square feet in Calgary, Alberta for divisional offices. Additionally, the Company owns an 18,400 square-foot building and surface pads covering approximately 42 acres related to its Southwest Oklahoma City Field operations.
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 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 is currently listed on the American Stock Exchange (the "AMEX") and trades under the symbol PEX. The Company's Common Stock has been listed with the AMEX since September 17, 1998. Prior to that time, the Company's Common Stock had been listed on The Nasdaq Stock Market since October 28, 1993. The following table presents the high and low closing prices for the Company's Common Stock for each quarter during 1997 and 1998, and for a portion of the Company's current quarter, as reported by the AMEX.
As of March 17, 1999, the closing price for the Company's Common Stock was $5.25 per share. As of March 17, 1999, there were approximately 500 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.
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:
Restructuring
On November 16, 1998, the Company announced that its Board of Directors has retained CIBC Oppenheimer Corp. to advise it with respect to strategic alternatives available to the Company for maximizing shareholder value, including sales of some or all of the Company's assets or a merger, reorganization or other restructuring of the Company.
As part of its goal of maximizing shareholder value, the Company also announced that its Board of Directors has adopted a Shareholder Rights Plan. The newly adopted Shareholder Rights Plan is designed
to protect the shareholder against any effort to acquire the Company for less than its full value. However, the Plan does not prevent a takeover. The intention of the Plan is to enable shareholders to realize the long-term value of their investments and to enable the Board of Directors to serve the interests of all shareholders. Under the Plan, each shareholder of record at the close of business on November 23, 1998, will receive one Series A Preferred Stock Purchase Right (Right) for each share of Common Stock held. The Rights expire on November 12, 2008.
The Company opened a data room in February, 1999 and to date has received various offers from third parties to purchase certain assets of, or merge with, the Company. The Board of Directors and management are currently assessing and evaluating the specific terms of these offers. At this time, it is not possible to determine the likelihood that one or more of these offers would be accepted, or that another course of action would ultimately be followed.
Acquisitions
In June 1998, the Company acquired a position in a South Texas exploration and development drilling alliance (the South Texas Acquisition). The acquisition includes a working interest in the new discovery well in the Rich Hurt Field in western Duval County. The alliance also controls approximately 25,000 acres in Duval and Webb counties as well as the rights to more than 100 square miles of new 3-D seismic data over the area.
The acquired Rich Hurt discovery well, along with three subsequently drilled development wells, were producing at a combined rate of approximately 24 MMcf/D at year-end 1998. PetroCorp's net share of this production is approximately 3.2 MMcf/D. The alliance has identified more than 80 prospects/leads in the area and currently has a leasehold position over 35 of these ideas.
Results of Operations
1998 Compared to 1997
Overview. Primarily resulting from a 36% decrease in oil prices and a 14% decrease in gas prices, coupled with an 8% decrease in production volumes, cash flow before changes in operating assets and liabilities decreased 44% to $10.7 million during 1998. This compares to $19.1 million in 1997.
Under rules promulgated by the Securities and Exchange Commission (the SEC), companies that follow the full cost accounting method are required to make quarterly "ceiling test" calculations, by country, using product prices in effect at that time. As a result of low U.S. product prices at December 31, 1998, the Company recorded a valuation adjustment to its U.S. oil and gas property balances, resulting in a non-cash after-tax charge against earnings of $21.2 million ($33.6 million pre-tax). Excluding the valuation adjustment, the Company recorded a net loss of $3.2 million, or $0.37 per share, in 1998 compared to net income of $1.9 million, or $0.22 per share, recorded in the prior year.
Revenues. Total revenues decreased 28% to $25.2 million in 1998 compared to $35.1 million in 1997. Oil and gas revenues decreased 29% to $23.6 million in 1998 from $33.5 million in the prior year as a result of the lower oil and gas prices, coupled with the lower production volumes.
The Company's oil production decreased 22% to 565 MBbls while its natural gas production remained almost level at 9,511 MMcf for an overall decline in production of 8% to 12,901 MMcfe from 13,972 MMcfe. The decreased oil production reflects normal production declines at the Hunter Misener Unit waterflood project located in northern Oklahoma and the Maynor Creek field in Mississippi. The Company had increases in gas production from the South Texas Acquisition and new wells in the U.S. and Canada. However, these increases were offset by lower gas volumes resulting from an unexpected mechanical problem, which has since been remedied, in a significant gas well located in South Louisiana, non-strategic property sales and natural production declines.
The Company's composite average oil price decreased 36% to $12.31 per barrel in 1998 from $19.10 per barrel in 1997. The Company's average U.S. natural gas price decreased 18% to $2.15 per Mcf in 1998 from $2.62 per Mcf in the prior year, while the average Canadian natural gas price decreased 10% to $1.32 per Mcf from $1.46 per Mcf.
Plant processing revenues increased 9% to $1.6 million in 1998 from $1.4 million in 1997 as a result of new third party gas processing fees received at the Company's Hanlan-Robb gas processing plant in Canada; beginning in August 1998.
Production Costs. Production costs decreased 6% to $7.3 million in 1998 while production costs per Mcfe remained almost level at $0.57. The decrease in absolute dollars reflects a reduction in production taxes and the Company's continued effort to reduce operating costs.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 3% to $16.6 million in 1998 from $17.1 million in 1997. This decrease reflects the impact of lower production volumes partially offset by a 5% increase in the oil and Gas DD&A rate to $1.16 per Mcfe from $1.10 per Mcfe.
Oil and Gas Property Valuation Adjustment. The Company follows the full cost method of accounting for its oil and gas properties. Under this method. all productive and non-productive exploration and development costs, incurred for the purpose of finding oil and gas reserves, are capitalized and may not exceed a calculated ceiling computed on a country-by-country basis. The ceiling is calculated on a quarterly basis as the sum of (i) the present value (discounted at 10%) of future net revenues from estimated production of proved oil and gas reserves plus (ii) the lower of cost or estimated fair market value of the unproved properties, less (iii) the related income tax effects. At December 31, 1998, as a result of low oil and gas prices, the Company's net capitalized costs for its U.S. oil and gas properties exceeded the ceiling by $21.2 million resulting in a pre-tax non-cash valuation adjustment of $33.6 million. The ceiling was calculated using a Koch WTI posting price of $9.50 per barrel of oil and a Henry Hub cash price of $2.14 per mcf of natural gas as benchmark prices.
General and Administrative Expenses. General and administrative expenses decreased 8% to $4.5 million in 1998 from $4.8 million in 1997 as a result of the Company's focus on reducing costs.
Investment and Other Income. Investment and other income increased significantly to $1.2 million in 1998 from $558,000 in 1997. The Company recorded an additional $762,000 in 1998 related to gas contract settlements and other items.
Interest Expense. Interest expense increased 3% to $3.6 million in 1998 from $3.5 million in the prior year, reflecting the impact of increased debt associated with a producing property acquisition completed in July 1997.
Income Taxes. Reflecting the U.S. valuation adjustment, the Company recorded a $15.1 million income tax benefit with an effective tax rate of 38% on a pre- tax loss of $39.5 million in 1998. This compares to an income tax provision of $136,000 with an effective tax rate of 7% on pre-tax income of $2.0 million in 1997. 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%.
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 13,974 MMcfe from 12,336 MMcfe. The increase in oil production is primarily related to the acquisition of Canadian properties in late 1996. The increase in natural gas production reflects the impact of producing property 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 Mcfe slightly increased by 4% to $0.56 from $0.54.
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 $1.10 per Mcfe from $0.87 per Mcfe. 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 7% to $4.8 million in 1997 from $4.5 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 a producing property 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%.
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, 1998, the Company had working capital of $2.1 million as compared to $2.6 million at December 31, 1997. Cash provided by operating activities before changes in operating assets and liabilities were $10.7 million, $19.1 million and $17.5 million in 1998, 1997 and 1996, respectively.
The Company's total capital expenditures, including capitalized internal costs, were $19.4 million, $28.0 million and $29.5 million for 1998, 1997 and 1996, respectively. During 1998, the Company spent $11.6 million related to exploration and development and $4.8 million related to acquisitions. In 1997, the Company spent $16.4 million related to exploration and development and $11.0 million related to acquisitions. In 1996, the Company spent $11.4 million related to exploration and development and $17.3 million related to acquisitions.
Sales of non-strategic oil and gas properties totaled $2.8 million, $1.4 million, and $6.3 million in 1998, 1997 and 1996, respectively.
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, 1998, $1.8 million has been recognized, leaving a balance of $257,000 in "deferred revenue" on the consolidated balance sheet as of December 31, 1998.
In June 1997, the Company entered into a $50.0 million five-year revolving credit agreement with the Toronto-Dominion Bank, the agent, and the Bank of Nova Scotia. On June 30, 1997, the Company was advanced $13.0 million to fund an acquisition of producing properties completed in early July 1997 and to fund certain debt repayments. During 1998, the Company borrowed $12.0 million to fund additional acquisitions and other debt repayments. At December 31, 1998, the Company had a total of $25.0 million outstanding under the revolver. The facility was amended in June 1998 to extend the initial five-year term an additional year to July 1, 2003 with quarterly borrowing base amortization beginning September 30, 2001. 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 7/8% to 1 1/2% on Eurodollar loans and nil to 1/2% on Prime loans. The Company's average interest rate under this facility was approximately 6.6% during 1998.
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 December 1996 acquisition of Millarville Oil and Gas Ltd., a privately held Alberta corporation that owns and operates oil and gas properties in Alberta, Canada. On June 29, 1998, this loan was repaid and the agreement was terminated. The Company's average interest rate while the loan remained outstanding in 1998 was 6.6%.
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, 1998, the remaining principal balances for the Series A and B Notes were $875,000 and $20.3 million, respectively. Of the total $21.2 million, $3.8 million matures in the next twelve months. 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 Note Purchase Agreement contains provisions that limit the Company's debt levels based on undiscounted and discounted oil and gas reserves using the SEC's rules, including the use of year-end prices held constant over the life of the remaining reserves. Due to low oil and gas prices, the Company was not in compliance with certain debt covenants of the Series A and Series B Note Purchase Agreement at year-end. However, the Series A and Series B note holders have waived such provisions for one year.
As the Company has both the ability and intent to refinance $2.0 million of its current maturities of long-term debt utilizing its revolving credit facility, $2.0 million has been reclassified from "current" to "long-term" on the Company's accompanying consolidated balance sheet as of December 31, 1998.
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, 1998, the nonrecourse long-term notes payable balance was $3.9 million, of which $910,000 was classified as "current."
Product prices continue to be volatile subsequent to December 31, 1998. In the future, should prices decline further and depending on drilling results, the Company could be required to record an additional valuation adjustment to its oil and gas property balances, resulting in a future non-cash charge against earnings.
The Company plans to finance its substantially reduced 1999 capital expenditures solely from available cash flow from operations and working capital. If the Company increases its capital expenditure level 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 as well as state, provincial and federal governments with jurisdictions where the Company maintains operations.
PetroCorp has formed a Year 2000 compliance team and has been addressing Year 2000 issues since the fourth quarter of 1997. The Company's initial focus was on internal business systems and processes. Beginning in August 1998, PetroCorp expanded its focus to include its oil and gas operations systems and processes as well as assessing the readiness of its key business partners (financial institutions, customers, vendors, oil and gas operators, etc.).
It has been a PetroCorp strategy to use, wherever possible, industry prevalent products and processes with minimal customization. As a result, PetroCorp does not expect any extensive in-house hardware, software or process conversions in an effort to be Year 2000 compliant nor does PetroCorp expect its Year 2000 compliance related costs to be material to the Company's operations. PetroCorp has contacted its major information technology suppliers concerning their Year 2000 compliance status and is continuing to test (using available software tools) these systems for compliance.
The Company's goal is to be Year 2000 compliant by June 30, 1999 and have contingency plans in place, wherever possible, when compliance is not probable in a timely manner.
While it is PetroCorp's goal to be Year 2000 compliant, there can be no assurance that there will not be a material adverse effect on the Company as a result of a Year 2000 related issue. The Company believes its business partners present the area of greatest risk to the Company, in part because of the Company's limited ability to influence actions of third parties, and in part because of the Company's inability to estimate the level and impact of noncompliance of third parties. Additionally, there are many variables and uncertainties associated with judgments regarding any contingency plans developed by the Company.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosure about Market Risk
The Company's primary sources of market risk are from fluctuations in commodity prices, interest rates and exchange rates.
Commodity Price Risk
The Company produces and sells natural gas, crude oil, condensate, natural gas liquids and sulfur. As a result, the Company's financial results can be significantly affected as these commodity prices fluctuate widely in response to changing market forces. Prior to 1997, the Company utilized hedging transactions to manage its exposure to price fluctuations on its sales of oil and natural gas. As discussed in Note 13 to the Consolidated Financial Statements, no hedge transactions were in place in 1997 and 1998.
Interest Rate Risk
Total debt at December 31, 1998, included $24.1 million of fixed-rate debt attributed to Series B Senior Notes and Nonrecourse Notes Payable, and $25.9 million of floating-rate debt attributed to Series A Senior Notes and the TD Bank Credit Agreement. As a result, the Company's annual interest cost in 1999 will fluctuate based on short-term interest rates. The impact on annual cash flow of a 100 basis point change in the floating rate would be approximately $184,000.
At December 31, 1998, the Company's fixed rate Series B Senior Notes had a book value of $20.8 million and a fair market value of $26.5 million. Due to the nature of the Nonrecourse Notes Payable, the Company believes that it is not practicable to estimate the fair value. See Note 6 to the Consolidated Financial Statements for information regarding future maturities of the Company's debt.
Foreign Currency Exchange Rate Risk
The Company conducts a significant portion of its business in the Canadian dollar and is therefore subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and
investing transactions. Exposure from market rate fluctuations related to activities in Canada, where the Company's functional currency is the Canadian dollar, is not material at this time.
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, 1998 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
Report dated November 20, 1998 regarding adoption of a shareholder rights agreement.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of PetroCorp Incorporated
In our opinion, the consolidated balance sheets and the related consolidated statements of operations, shareholders' equity and of cash flows present fairly, in all material respects, the financial position of PetroCorp Incorporated (the Company) and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, 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.
As further discussed in Note 2, the Company has retained CIBC Oppenheimer Corp. to advise the Board of Directors with respect to strategic alternatives for maximizing shareholder value.
/s/ PRICEWATERHOUSECOOPERS LLP
Houston, Texas March 30, 1999
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEETS
December 31, 1998 and 1997
(in thousands, except per share amounts)
The accompanying notes are an integral part of these financial statements.
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF OPERATIONS
Years Ended December 31, 1998, 1997 and 1996
(in thousands, except per share data)
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, 1998, 1997 and 1996
(in thousands)
The accompanying notes are an integral part of these financial statements.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1998, 1997 and 1996
1. Summary of Accounting Policies
General
PetroCorp Incorporated, a Texas corporation, is engaged in the acquisition, exploration, development, 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 consolidated 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. At December 31, 1998, the Company's net capitalized costs of its U.S. oil and gas properties exceeded the capitalization ceiling by $21,168,000 resulting in a pre-tax valuation adjustment of $33,600,000. Such valuation adjustment is reflected in the Company's results of operations for the year ended December 31, 1998.
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 four 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.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
At December 31, 1998 and 1997, the cumulative amount of accrued site restoration and dismantlement costs approximated $154,000 and $357,000, respectively.
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, 1998 and 1997, the Company included $35,000 in accrued liabilities with respect to overproduced imbalances.
The Company hedged a portion of its oil and gas sales in 1996. No hedges were in place during 1997 or 1998. See Note 13--Hedging Program.
Revenues from plant processing are recognized at the time associated natural gas is processed and sold at the plant tailgate. Other revenues include fees 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, 1998 and 1997, 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 asset and 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 other comprehensive loss component of shareholders' equity. Foreign currency transaction gains and losses are recognized currently. For the years ended December 31, 1998, 1997 and 1996, the Company recognized foreign currency losses of $2,000, $36,000 and $24,000, respectively. At December 31, 1998, 1997 and 1996, the exchange rates were ($1 CAN = $U.S.) $0.6535, $0.6992 and $0.7297, respectively, while the average exchange rates during such years were $0.6721, $0.7201 and $0.7334, respectively.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
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, 1998, 1997 and 1996 were $5,875,000, $4,730,000 and $7,407,000, respectively.
Other
On June 15, 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 is effective for all fiscal quarters of all fiscal years beginning after June 15, 1999 for certain companies (January 1, 2000 for the Company). SFAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income (only certain types of hedge transactions are reported as a component of other comprehensive income). Additionally, for all hedge transactions the nature and type of hedge should be disclosed.
2. Restructuring
On November 16, 1998, the Company announced that its Board of Directors had retained CIBC Oppenheimer Corp. to advise it with respect to strategic alternatives available to the Company for maximizing shareholder value, including partial or full sale of the Company's assets or a merger, reorganization or other restructuring of the Company.
As part of its goal of maximizing shareholder value, the Company also announced that its Board of Directors had adopted a Shareholder Rights Plan. The newly adopted Shareholder Rights Plan is designed to protect the shareholder against any effort to acquire the Company for less than its full value. However, the Plan does not prevent a takeover. The intention of the Plan is to enable shareholders to realize the long-term value of their investments and to enable the Board of Directors to serve the interests of all shareholders. Under the Plan, each shareholder of record at the close of business on November 23, 1998, will receive one Series A Preferred Stock Purchase Right (Right) for each share of Common Stock held. The Rights expire on November 12, 2008.
The Company opened a data room in February 1999 and, to date, has received various offers from third parties to purchase certain assets of, or merge with, the Company. The Board of Directors and management are currently assessing and evaluating the specific terms of these offers. At this time, it is not possible to determine the likelihood that one or more of these offers would be accepted, or that another course of action would ultimately be followed.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
3. Comprehensive Income
The Company implemented SFAS No. 130, "Reporting Comprehensive Income," effective January 1, 1998. This Statement establishes new requirements for reporting comprehensive income and its components which includes the Company's foreign currency translation adjustment. Adoption of this statement has no impact on the Company's net income (loss) as presented on the accompanying consolidated statement of operations. The Company's comprehensive income (loss) for the years ended December 31, 1998, 1997 and 1996 are as follows (amounts in thousands):
4. 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.
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, 1998, 1997 and 1996
5. Property, Plant and Equipment
Investments in property, plant and equipment were as follows at December 31, 1998 and 1997 (amounts in thousands):
Depreciation, depletion and amortization for all property, plant and equipment for the years ended December 31, 1998, 1997 and 1996 was $16,406,000, $16,880,000 and $12,279,000, respectively. Oil and gas property depreciation, depletion and amortization for the years ended December 31, 1998, 1997 and 1996 was $14,961,000, $15,383,000 and $10,788,000, respectively. Depreciation, depletion and amortization per equivalent Mcf (using a Mcf-to-barrel conversion factor of 6 to 1) for the years ended December 31, 1998, 1997 and 1996 was $1.62, $1.51 and $1.06, respectively, for U.S. operations and $0.53, $0.50 and $0.34, respectively, for Canadian operations. The total composite rates were $1.16, $1.10 and $0.87 for the years ended December 31, 1998, 1997 and 1996, respectively.
Product prices continue to be volatile subsequent to December 31, 1998. In the future, should prices 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 future noncash charge against earnings.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
6. 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, 1998 is as follows: $4,710,000 in 1999, $10,285,000 in 2000, $9,085,000 in 2001, $8,160,000 in 2002 and $9,325,000 in 2003.
Reclassification of current debt maturities to long term represents unused capacity under the TD Bank credit agreement at December 31, 1997 and 1998. 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, 1998 and 1997 consisted of the following (amounts in thousands):
Redemption payments to affiliates and nonaffiliates were $1,675,000 and $3,025,000 in 1998 and $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, 1998, 1997 and 1996 amounted to $173,000 and $1,689,000; $303,000 and $1,941,000; $1,883,000 and $706,000, 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, 1998, 1997 and 1996
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 6.6% to 7.0%, 6.7% to 7.0% and 6.7% to 7.1% during 1998, 1997 and 1996, 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.
The Note Purchase Agreement contains provisions that limit the Company's debt levels based on undiscounted and discounted oil and gas reserves using SEC's rules, including the use of year-end prices held constant over the life of the remaining reserves. Due to low oil and gas prices, the Company was not in compliance with certain debt covenants of the Series A and Series B Note Purchase Agreement at year end. However, the Series A and Series B noteholders have waived such provisions for one year.
Bank Debt
On June 26, 1997, the Company entered into a $50 million, five-year revolving credit agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of Nova Scotia. The facility was amended in June 1998 to extend the initial five-year term an additional year to July 1, 2003 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 7/8% to 1 1/2% on Eurodollar loans and nil to 1/2% on Prime loans.
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 $3,500,000 to partially fund the Millarville Acquisition. On June 29, 1998, this loan was repaid and the agreement was terminated. The Company's average interest rate while the loan remained outstanding in 1998 and 1997 was 6.6% and 5.8%, respectively.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
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 1998, 1997 and 1996, interest payments were $1,126,000, $669,000 and $896,000, respectively, while principal payments totaled $2,017,000, $757,000 and $1,938,000, respectively. Additionally, in 1998, 1997 and 1996, the Company issued $846,000, $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.
7. Deferred Revenue
In March 1996, FGS sold its Southwest 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 Southwest Oklahoma City Field. To date, $1,832,000 has been recognized, leaving a balance of $257,000 in "deferred revenue" on the consolidated balance sheet as of December 31, 1998.
8. 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 (see Note 2).
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
9. Income Taxes
The components of income (loss) before income taxes for the years ended December 31, 1998, 1997 and 1996 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, 1998, 1997 and 1996 is presented in the following table (amounts in thousands):
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
Deferred tax assets and liabilities consist of the following at December 31, 1998 and 1997 (amounts in thousands):
As of December 31, 1998, the Company has U.S. net operating loss (NOL) carryforwards of $40,228,000 and $33,499,000 for regular tax and alternative minimum tax purposes, respectively. Alternative minimum tax NOL carryforwards begin to expire in 2008 and regular tax NOL carryforwards expire as follows:
Certain future changes in the Company's shareholders may impose restrictions under Section 382 on the annual utilization of a portion of its net operating loss carryforwards.
Prior to 1998, under SFAS 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, 1998, 1997 and 1996
10. 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, 1998, 1997 and 1996 were $7.86, $7.86 and $7.84, 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.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
Stock options under both plans expire ten years from the date of grant.
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 1998 and 1997 net income and earnings per share would have been reduced by approximately $16,000 and $79,000, or nil and $0.01 per share, respectively. The fair value of the options granted during 1998 is estimated as $26,000 on the date of grant using the Black-Scholes option-pricing model with the following assumptions: dividend yield of 0%, volatility of 26%, risk-free interest rate of 5.8% and an expected life of ten years.
Effective January 1, 1993, the Company established a savings plan, which is available to eligible employees and qualifies 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 $192,000, $188,000 and $208,000 in 1998, 1997 and 1996, respectively.
11. 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.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
The 1998 $2.82 loss per share does not include the effect of dilutive securities as their impact would be antidilutive given the Company's loss position.
Options to purchase 415,000, 445,740 and 445,740 shares of common stock at $8.25-10.00, $10.00 and $10.00 per share were outstanding during the years ended December 31, 1998, 1997 and 1996 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.
12. 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:
During 1998 and prior, the majority of the Company's Canadian gas was dedicated under long-term contracts to Pan-Alberta Gas Ltd., a major Canadian aggregator. However, as part of a legal settlement effective December 31, 1998, approximately 50% of PetroCorp's dedicated gas volumes have been released
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996 from Pan-Alberta contracts. These released volumes are now sold on the spot market at prevailing prices. 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.
13. Hedging Program and Fair Value of Financial Instruments
Hedging Program
During 1996, the Company utilized hedging transactions to manage its exposure to price fluctuations on its sales of oil and natural gas. The Company used oil and natural gas futures contracts traded on the NYMEX to hedge its oil and gas sales. Realized gains and losses from the Company's hedging activities were included in oil and gas revenues in the period of the hedged production.
The Company recorded realized hedging losses of $918,000 in 1996. No hedges were in place in 1997 or 1998.
Fair Value of Financial Instruments
The following information discloses the fair value of the Company's financial instruments in accordance with SFAS 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.
14. 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 $506,000, $528,000, $447,000, $419,000 and nil for the years ended December 31, 1999, 2000, 2001, 2002 and 2003, respectively. Total rental expense for office space for the years ended December 31, 1998, 1997 and 1996 was $560,000, $648,000 and $646,000, respectively.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
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.
15. 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 1998 and 1997, the consulting company procured $236,000 and $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 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 1998, 1997 and 1996, the Company remitted $181,000, $914,000 and $133,000, respectively, to Kaiser Francis as payment of the Company's share of the joint operation. Amounts payable to Kaiser Francis at December 31, 1998 and 1997 were $5,000 and $97,000, respectively.
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS OIL AND GAS RESERVES AND RELATED FINANCIAL DATA
December 31, 1998, 1997 and 1996
(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, 1998, 1997 and 1996 were $1,811,000, $1,897,000 and $1,690,000, respectively, of capitalized internal costs related to property acquisition, exploration and development. Under SFAS 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, 1998, 1997 and 1996
(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, 1998, approximately $1,627,000 and $4,174,000 was incurred in 1998 and 1997, 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, 1998, 1997 and 1996
(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, 1998, 1997 and 1996
(unaudited)
The Company's estimates of its proved reserves and proved developed reserves of oil and gas as of December 31, 1998, 1997 and 1996 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, 1998, 1997 and 1996
(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 unproved 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, 1998, 1997 and 1996
(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, 1998, 1997 and 1996
(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, 1998, 1997 and 1996
(unaudited)
Summarized Quarterly Financial Data
(unaudited) (amounts in thousands, except per share data)
- -------- (1) Revenues less operating expenses other than general and administrative.
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 29, 1999
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.
EXHIBIT INDEX