ITEM 1. BUSINESS.
GENERAL
PetroCorp Incorporated (PetroCorp or the Company) is an independent energy company engaged in the exploration, development and acquisition of oil and gas properties, and in the production of oil and natural gas in North America. The Company's activities are conducted principally in the states of Mississippi, Oklahoma, Texas, Louisiana, Kansas and Colorado and in the province of Alberta, Canada.
At December 31, 1996, the Company's proved reserves totaled 5.2 MMbbls of oil and 80.8 Bcf of natural gas and had an estimated pretax present value of future net revenues (PV-10) of $177 million. On a BOE basis, approximately 70% 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 $5.3 million, as well as interests in natural gas processing and gathering facilities with a net book value of $5.9 million.
The Company was formed in July 1983 as a Delaware corporation and in December 1986 contributed its assets to a newly formed Texas general partnership. In October 1992, the Company changed its legal form from a Texas general partnership to a Texas corporation. PetroCorp's principal executive offices are located at 16800 Greenspoint Park Drive, Suite 300, North Atrium, Houston, Texas 77060, and its telephone number is (281) 875-2500. Unless the context otherwise requires, the terms the "Company" and "PetroCorp" refer to and include PetroCorp Incorporated, its predecessor entities (including the original Delaware corporation and the subsequent Texas general partnership) and all subsidiaries and partnerships in which PetroCorp owns a 50% or greater interest.
BUSINESS STRATEGY
Historically, the Company's strategy has been to increase its reserves, cash flow and underlying net asset value through a combination of exploration and development and acquisition activities.
Exploration and Development Strategy. Exploration and development activities are an important component of PetroCorp's business strategy. In recent years, the Company has allocated greater capital and management resources to exploration and development activities, increased the personnel and technological capabilities (including the use of 3-D seismic technology) available to its exploration and development teams, and developed major exploration and development projects in Mississippi, Oklahoma, Texas and Alberta, Canada. PetroCorp has the capability to perform re-processing, visualization and interpretation of its seismic database completely in-house.
Acquisition Strategy. PetroCorp has grown, in large part, through the acquisition of producing oil and gas properties, and it intends to continue to take advantage of opportunities to purchase properties with proved reserves that meet the Company's acquisition criteria. Prevailing market conditions significantly influence the implementation of the Company's acquisition strategy. The Company generally focuses on acquisitions of long-lived natural gas reserves located onshore in North America and prefers acquisitions that provide potential through additional development or exploitation efforts as well as exploratory drilling opportunities.
EXPLORATION AND DEVELOPMENT ACTIVITIES
In recent years, the Company has placed increasing emphasis on the exploration and development component of its business strategy.
Mississippi Salt Basin. The Mississippi Salt Basin is one of PetroCorp's most active and aggressive exploration plays. Through year-end 1996, PetroCorp had drilled four exploratory prospects in Wayne and Greene Counties, yielding two new field discoveries and six successful wells out of eight total wells drilled. In February 1995, PetroCorp announced the new Maynor Creek Field in Wayne County, Mississippi, which it
operates. The initial discovery well, the Scott Paper 1-33, was successfully tested from two separate intervals in the Cotton Valleyformation at approximately 14,000 feet. Subsequent to the discovery, the Company conducted a 16-square mile 3-D seismic survey to optimize the development of the field and has successfully drilled three consecutive development wells. Restricted by state allowable limitations, the four wells are now producing at a combined rate in excess of 1,000 BOPD. PetroCorp originally owned a 50% working interest in the field. The acquisition of the interest of one of its partners in October 1996, together with an anticipated prospect payout in the first quarter of 1997, is expected to bring its working interest ownership to 65%. To date, the Company has participated in four separate 3-D seismic surveys covering 65 square miles in the Mississippi Salt Basin. In September 1996, PetroCorp entered into a joint venture agreement with a subsidiary of Shell Oil Company (Shell) which allows PetroCorp to use approximately 13,000 line- miles of Shell's 2-D seismic database covering 18 counties.
Hanlan-Robb Area. The Company owns interests in three proved developed nonproducing fields in the Hanlan-Robb area of western Alberta, Canada. It intends to connect these fields to the Hanlan-Robb gas gathering system as declining production from the five currently producing fields makes capacity available at the gas processing plant in which the Company owns an interest.
Recent activity for the Hanlan Unit includes the successful installation and start-up of a $10 million field compression facility designed to extend the life of the field into the next century. In addition, the first of several potential horizontal laterals has been drilled from an existing well in the Unit and is awaiting final production testing. The Hanlan 6-23 well has been deviated laterally almost 1,000 feet in an attempt to increase its productivity and mitigate natural field decline. If successful, additional laterals on existing Hanlan Unit wells are planned over the next several years in an attempt to reduce the natural rate of field production declines. The Erith 8-13 development well was completed at approximately 15,000 feet in February 1995 at the Erith prospect, approximately seven miles east of the plant. After construction of a gas gathering line, production from this well commenced in December 1995, and it now produces at 6 MMcf/D. Current plans call for a horizontal lateral (in a fashion similar to the Hanlan 6-23) to be drilled from the vertical Erith 8-13 wellbore later in 1997.
Approximately ten miles west of the plant are the Shaw/Basing and Coal Branch/Coalspur areas. After acquiring in excess of 100 line-miles of high resolution 2-D seismic data in 1995, PetroCorp is now actively involved in two separate exploration plays in the area. Two wells have been successfully re- entered and drilled horizontally in the 12,500 foot Mississippi Turner Valley formation. The Coalbranch 16-33 and the Coalspur 9-27 are now producing at 10 MMcf/D and 3.5 MMcf/D, respectively. The other exploration play in this area involves drilling for the shallower Cardium formation at 5,000 to 7,000 depth. The Shaw 7-8 has been tested at 4 MMcf/D and awaits a pipeline connection which is expected to be completed in the second half of 1997. The Basing 10-25 is currently testing. 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.
Oklahoma. North of Oklahoma City, PetroCorp has successfully completed the first well on its Edmond Prospect as a Prue Sand gas well at 6,100 feet. Capable of sustained production of approximately 3 MMcf/D, the Jackson 2B-4 well is currently flowing at a pipeline constrained rate of 1.4 MMcf/D. PetroCorp owns a 47% working interest in this well and an average 70% working interest in two additional wells planned for this project. The first of these development wells is scheduled to be drilled in the second quarter of 1997. In recent years, the Company has made a number of discoveries in the Northern Oklahoma Area, and the Company will continue exploration and development of this area during 1997. Exploration activities are currently focused on Cottage Grove and Tonkawa gas targets at 4,000-5,000 feet within the Misener Trend/Northern Shelf Play of the Anadarko Basin. A number of exploration projects have been identified with 1997 drilling scheduled. This activity has been driven by the integration of PetroCorp's extensive seismic database, which now includes in excess of 2,000 miles of 2-D and 12 square miles of 3-D seismic data in this area.
In April 1996, the Oklahoma Corporation Commission officially approved the formation of the Southwest Oklahoma City Unit for the purposes of water flooding and repressurizing the field to improve ultimate oil
recovery. Water injection commenced in September 1996. The PetroCorp-operated, 56 well unit has produced 2.4 MMbbls of oil and 18 Bcf of gas to date. PetroCorp owns an 86.4% working interest in the Southwest Oklahoma City Unit which is currently producing 280 BOPD and 3.9 MMcf/D. The adjacent Will Rogers Unit operated by another party has already shown a positive response to waterflood operations initiated in 1993. PetroCorp is also currently involved in waterflood projects on four fields in the Northern Oklahoma Area.
Worsley Field and Other Canadian Properties. The largest of the producing properties acquired from Millarville Oil & Gas Ltd. in December 1996 is the Worsley property in northwest Alberta, Canada. The Company has modified the pipeline system, installed compression and commenced sales of 800 Mcf/D of natural gas that had previously been flared or shut-in. Additional development activity is planned in 1997 in the Worsley property as well as in the McLeod, Trochu and Buick-Sutton areas of Alberta.
Other Projects. PetroCorp recently acquired a 15% interest in an exploration play in Southeast Texas. The Company is participating in a 3-D seismic program covering approximately 60 square miles in Newton County, Texas and Calcasieu Parish, Louisiana. Primary objectives are the expanded and overpressured Yegua formation along with the Frio Nodosaria sands down to a depth of 12,000 feet. Acquisition of the seismic data has been completed and the data is currently in processing. Assuming positive results from the survey, drilling is expected to commence during the second half of 1997.
The Company's waterflood project at the Richardson-Mueller Caddo Unit in North Texas did not show any commercial oil response in 1996 and operations have been suspended in the first quarter of 1997. As a result, the Company moved 2.6 MMBOE of proved reserves attributable to this unit into the probable/possible category. This reserve revision resulted in a 9% decrease in the Company's total proved reserves at December 31, 1996 compared with the previous year end; however, the Company more than replaced production with new reserve additions for the year. See "Supplemental Information to Consolidated Financial Statements--Oil and Gas Reserves and Related Financial Data--Reserve Quantities" in the Notes to the Consolidated Financial Statements of the Company.
ACQUISITIONS AND ASSET RATIONALIZATION ACTIVITIES
In December 1996, the Company acquired all of the capital stock of Millarville Oil & Gas Ltd., a privately held owner and operator of oil and gas properties in Alberta, Canada. The Company completed the acquisition, which added proved reserves of 2.2 MMBOE of oil and 6.8 Bcf of natural gas, in December 1996 for a purchase price of $11.8 million. The purchase price for the Millarville properties was funded by available cash and $3.6 million of long-term borrowings by a Canadian subsidiary of the Company. The Company now operates 75% of the acquired reserves.
Also in 1996, the Company purchased additional interests in the Maynor Creek Field in Mississippi from its partners and an average working interest of approximately 95% in two natural gas properties, one near its existing interests in the Southwest Oklahoma City Unit and one in south-central Texas.
During the year ended December 31, 1996, the Company completed its three- year program of rationalizing its asset base by selling both its gas gathering system in the Southwest Oklahoma City Unit and its interests in 438 wells on various locations. The wells sold represented 53% of the Company's total well count but less than 2% of proved reserves. In addition, the Company sold a portion of its reserves in the Hanlan Swan Hills Unit along with a portion of its interest in the related gas processing plant in Alberta, Canada. The proceeds from this sale contributed to the acceleration of payout of the Company's partners' investment in the Hanlan-Robb area into the first quarter of 1997, increasing the Company's current working interest ownership by 40%.
The Company expects to continue to pursue acquisition opportunities to complement its exploration and drilling activities. The Company's acquisition team annually screens a large number of potential prospects; however, only a comparatively smaller number of prospects have the potential to satisfy the Company's acquisition criteria and are studied in detail.
PRODUCTION AND SALES
The following table presents certain information with respect to oil and gas production attributable to the Company's properties, average sales price received and average production costs during the three years ended December 31, 1996, 1995 and 1994. See Note 10 to the Consolidated Financial Statements of the Company and "Supplemental Information to the Consolidated Financial Statements" in the Notes thereto included elsewhere in this report for additional financial information regarding the Company's foreign and domestic operations.
MARKETING
PetroCorp's United States gas production is sold to a variety of pipelines, marketing companies and utility end users, typically under short-term contracts ranging in length from one month to one year. Currently, the majority of the Company's Canadian gas is dedicated under long-term contracts to Pan-Alberta Gas Ltd. (Pan-Alberta), a major Canadian gas marketer affiliated with the pipeline authorized to gather all gas in the province of Alberta. Approximately 60% of the Company's Canadian gas is resold into the United States, predominantly to markets in the upper midwest region. PetroCorp receives from Pan-Alberta a price per Mcf equal to Pan-Alberta's resale price, less certain costs permitted to be recovered by Pan-Alberta under the contracts.
PetroCorp's domestic crude oil and condensate production is sold to a variety of purchasers typically on a monthly contract basis at posted field prices or NYMEX prices, as determined by major buyers. In particular areas, where production volumes are significant or the location is desirable for a particular purchaser, or both, the Company has successfully negotiated bonuses over the purchaser's general field postings for its production.
During the year ended December 31, 1996, Pan-Alberta (the purchaser of most of the Company's Canadian gas), EOTT Energy Operated Limited Partnership and Sun Refining and Marketing Company (two of the Company's purchasers of oil) accounted for 17%, 20% and 14% 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
From time to time, the Company has utilized hedging transactions to manage its exposure to price fluctuations in crude oil and natural gas. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 11 to the Consolidated Financial Statements.
COMPETITION
The oil and gas industry is highly competitive. The Company competes in acquisitions and in the exploration, development, production and marketing of oil and gas with major oil companies, larger independent oil and gas concerns and individual producers and operators. Many of these competitors have substantially greater financial and other resources than the Company.
REGULATION
United States
General. The Company's business is affected by numerous governmental laws and regulations, including energy, environmental, conservation and tax laws. For example, state and federal agencies have issued rules and regulations that require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of reserves through proration, and regulate oilfield and pipeline environmental and safety matters. Changes in any of these laws could have a material adverse effect on the Company's business, and the Company cannot predict the overall effects of such laws and regulations on its future operations. Although these regulations have an impact on the Company and others in the oil and gas industry, the Company does not believe that it is affected in a significantly different manner by these regulations than are its competitors in the oil and gas industry.
The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing.
Regulation of Transportation and Sale of Natural Gas and Oil. Various aspects of the Company's oil and gas operations are regulated by agencies of the federal government. The transportation of natural gas in interstate commerce is generally regulated by the Federal Energy Regulatory Commission (FERC) pursuant to the Natural Gas Act of 1938 (the NGA) and the Natural Gas Policy Act of 1978 (NGPA). The intrastate transportation and gathering of natural gas (and operational and safety matters related thereto) may be subject to regulation by state and local governments.
In the past, the federal government regulated the prices at which the Company's produced oil and gas could be sold. Currently, "first sales" of natural gas by producers and marketers, and all sales of crude oil, condensate and natural gas liquids, can be made at uncontrolled market prices, but Congress could reenact price controls at any time.
Within the past decade, the FERC has issued numerous orders and policy statements designed to create a more competitive environment in the national natural gas marketplace, including orders promoting "open-
access" transportation on natural gas pipelines subject to the FERC's NGA and NGPA jurisdiction. The FERC's "Order 636" was issued in April 1992 and was designed to restructure the interstate natural gas transportation and marketing system and to promote competition within all phases of the natural gas industry. Among other things, Order 636 required interstate pipelines to separate the transportation of gas from the sale of gas, to change the manner in which pipeline rates were designed and to implement other changes intended to promote the growth of market centers. Subsequent FERC initiatives have attempted to standardize interstate pipeline business practices and to allow pipelines to implement market-based, negotiated and incentive rates. The restructured services implemented by Order 636 and successor orders have now been in effect for a number of winter heating seasons and have significantly affected the manner in which natural gas (both domestic and foreign) is transported and sold to consumers.
Although Order 636 has generally been upheld in judicial appeals to date, petitions for court review are still pending and it is not possible to predict the ultimate outcome of such appeals or the effect, if any, of future restructuring orders or policies on the Company's operations. In addition, FERC has recently announced that it will convene in the near future a public conference to consider whether FERC's current approach to regulation of the natural gas industry should be changed and whether further refinements or changes to existing policies should be made in view of developments in the natural gas industry since Order 636 was originally issued. Although FERC has indicated that it remains committed to Order 636's "fundamental goal" of "improving the competitive structure of the natural gas industry in order to maximize the benefits of wellhead decontrol," the future regulatory goals and priorities of FERC may be altered as a result of such conference and related inquiries. FERC's policies may also be impacted by the ongoing restructuring of the electric power industry pursuant to FERC Order No. 888.
While Order 636 and related orders do not directly regulate either the production or sale of gas that may be produced from the Company's properties, the increased competition and changes in business practices within the natural gas industry resulting from such orders have affected the terms and conditions under which the Company markets and transports its available gas supplies. To date, the FERC's pro-competition policies have not materially affected the Company's business or operations. On a prospective basis, however, such orders may substantially increase the burden on producers and transporters to accurately nominate and deliver on a daily basis specified volumes of natural gas, or to bear penalties or increased costs in the event scheduled deliveries are not made.
Environmental Regulation. Various federal, state and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company's operations and costs. In particular, the Company's exploration, exploitation and production operations, its activities in connection with storage and transportation of crude oil and other liquid hydrocarbons and its use of facilities for treating, processing or otherwise handling hydrocarbons and wastes therefrom are subject to stringent environmental regulation. Although compliance with these regulations increases the cost of Company operations, such compliance has not in the past had a material effect on the Company's capital expenditures, earnings or competitive position. Environmental regulations have historically been subject to frequent change by regulatory authorities. The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as "hazardous wastes," which would make the reclassified wastes subject to much more stringent handling, disposal and cleanup requirements. If such legislation were to be enacted, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Also under consideration at the federal level are laws and regulations that would require owners and operators of oil and gas facilities to meet an environmental "financial responsibility requirement" (with current proposals ranging from $35 million to $150 million) that could have a significant adverse impact on small oil and gas companies like PetroCorp. State initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these various initiatives could have a similar impact on the Company. The Company is unable to predict the ongoing cost to it of complying with these laws and regulations or the future impact of such regulations on its operation. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse impact on the Company. A catastrophic discharge of hydrocarbons into the environment could, to the extent such event is not insured, subject the Company to substantial expense.
Canada
In Canada, the petroleum industry operates under federal, provincial and municipal legislation and regulations governing taxes, land tenure, royalties, production rates, environmental protection, exports and other matters. Prices of oil and natural gas in Canada have been deregulated and are determined by market conditions and negotiations between buyers and sellers, although oil production volumes are regulated. Various matters relating to the transportation and distribution of natural gas are the subject of hearings before various regulatory tribunals. In addition, although the price of natural gas exported from Canada is subject to negotiation between buyers and sellers, the National Energy Board, which regulates exports of natural gas, requires that natural gas export contracts meet certain criteria as a condition of approving such contracts. These criteria, including price considerations, are designed to demonstrate that the export is in the Canadian public interest. Several provincial governments have introduced a number of programs to encourage and assist the oil and natural gas industry, including incentive payments, royalty holidays and royalty tax credits. Canadian governmental regulations may have a material effect on the economic parameters for engaging in oil and gas activities in Canada and may have a material effect on the advisability of investments in Canadian oil and gas drilling activities.
EMPLOYEES
At December 31, 1996, PetroCorp had 55 full-time employees.
OPERATIONAL RISKS AND INSURANCE
The Company's operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which could result in severe damage to or destruction of oil and gas wells, production facilities or other property or injury to persons. The energy business is also subject to environmental hazards, such as oil spills, gas leaks and ruptures and discharges of toxic substances or gases that could expose the Company to substantial liability due to pollution and other environmental damage. Although the Company maintains insurance coverage considered to be customary in the industry, it is not fully insured against certain of these risks, either because such insurance is not available or because of high premium costs. The occurrence of a significant event that is not fully insured against could have a material adverse effect on the Company's financial position.
ITEM 2.
ITEM 2. PROPERTIES.
PRINCIPAL PROPERTIES
The Company's proved oil and gas properties are relatively concentrated. Approximately 80% of the PV-10 from the Company's proved reserves at December 31, 1996 was attributable to seven 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, 1996, all of which are taken from reports prepared by Huddleston & Co., Inc. and Paddock Lindstrom & Associates Ltd. 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 accounts for 40% of the Company's net daily gas production. The Company has ownership interests in all eight area fields, but the majority of its Hanlan-Robb proved reserves and present value are currently attributable to one field, the Hanlan Swan Hills Gas Unit #1. PetroCorp's ownership is part of a joint venture managed by the Company with institutional investors that collectively own 21.6% of the field. After an ownership reversion in early 1997, PetroCorp's working interest in this field has increased by 40%, from 5.4% to 7.5%. Petro-Canada is the largest interest owner in the area and operates the fields and the related gathering system and processing plant.
Oklahoma City Area. Includes the Southwest Oklahoma City Unit located within the metropolitan Oklahoma City area in Oklahoma and the Edmond Prospect located just north of the city. The Southwest Oklahoma City field is bounded to the southeast by the Oklahoma City Prue Unit and to the Southwest by the Wheatland and Will Rogers Units and produces oil with associated casinghead gas. As of December 31, 1996, PetroCorp had an undeveloped leasehold position of 788 gross (525 net) acres in the Edmond Prospect.
Mississippi Salt Basin. Production from the Mississippi Salt Basin accounts for 30% of PetroCorp's net domestic oil sales. This basin is one of PetroCorp's most active exploration areas. At the end of 1994, the Company made a new field discovery of oil and associated natural gas in the Maynor Creek Field in Wayne County, Mississippi. The largest of its two producing fields in the basin, the Company has drilled three successful development wells there, two in 1995 and one in December 1996. PetroCorp operates the four wells in the field and increased its 50% average working interest to 57.7% before payout and 65% after payout when it acquired a partner's interest in October 1996. In September 1996, expanding on its successes in the basin, the Company entered into a seismic joint venture agreement with a subsidiary of Shell Oil Company to extend its exploration effort into an 18-county area. Under the terms of the agreement, PetroCorp has access to Shell's extensive 2-D
seismic database in the area (approximately 13,000 line-miles of data) and other proprietary information held by Shell. As of December 31, 1996, PetroCorp had an undeveloped leasehold position of 13,709 gross (6,390 net) acres in this area.
Northern Oklahoma Area. The Northern Oklahoma Area is located in Alfalfa and Grant Counties in north central Oklahoma. Production is primarily oil with associated casinghead gas from fourteen fields. PetroCorp operates 28 of the wells in nine fields located in this trend, of which two fields are the subject of pressure maintenance waterfloods. The Company also has non-operated working interests in two additional waterfloods. PetroCorp continues to actively pursue both exploration and development in the Northern Oklahoma Area, and at December 31, 1996 had an undeveloped leasehold position of approximately 17,410 gross (11,193 net) acres.
Worsley Field. The largest of the producing properties acquired from Millarville Oil & Gas Ltd. in December 1996, this field is located in northwest Alberta, Canada and primarily produces oil and associated casinghead gas. The Company operates seven wells in the field and owns 100% of the working interests. It also owns an interest in one non-operated well. With an undeveloped leasehold position of 1,040 gross (976 net) acres at December 31, 1996, the Company plans to pursue further development of this field.
Scott Field. This prolific five-well field in south central Louisiana produces primarily natural gas with associated condensate. PetroCorp owns an interest of approximately 3% in the field.
Glick Field. The Glick field is located in Kiowa County in southern Kansas and is one of several natural gas producing fields that form an arc around the southern end of the Central Kansas Uplift. PetroCorp currently has interests in and operates a total of eight wells in the field.
Other Properties. Other significant properties include the Harris Field located in Live Oak County in south central Texas, the Paradox Basin area of southwest Colorado and the Cheyenne West Field in western Oklahoma.
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. and Paddock Lindstrom & Associates Ltd. (together, 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, 1996. 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.
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, 1996.
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, 1996.
- -------- (1) Approximately 56% of net (approximately 62% of net participating interest) undeveloped acres are covered by leases that expire during 1997. The Company has the option, which it plans to exercise for approximately 60% of the acreage, to extend the primary lease term under certain conditions for 51,072 net (as well as net participating interest) undeveloped areas in Colorado. Assuming the Company exercises its option to extend the lease term for 60% of the acreage, approximately 40% of net (approximately 30% of net participating interest) undeveloped acres would be covered by leases that expire in 1997. (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, 1996, the Company had working interests in 291 gross (120 net) producing oil wells and 197 gross (59 net) producing gas wells. Of these wells, 67 gross (25 net) oil wells and 83 gross (19 net) gas wells were in Canada, and the remainder of the oil and gas wells were in the United States. The Company had two wells with multiple completions 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, 1996, 1995 and 1994 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, 1996, the Company was participating in the drilling or completion of 3 gross (.9 net) wells in Canada.
HANLAN-ROBB NATURAL GAS PROCESSING PLANT AND GAS GATHERING SYSTEMS
PetroCorp owns interests in a centrally located gas processing plant and in a gas gathering system that connects all five of the Company's currently producing Hanlan-Robb fields to the Hanlan-Robb plant. The gas processing plant, which is operated by Petro-Canada, was commissioned in 1983 and has a processing capacity of approximately 300 MMcf of gas per day. For the 12 months ending December 31, 1996, plant throughput averaged 200 MMcf per day (67% of design capacity). Recent activity for the Hanlan Unit included installation and start-up of a $10.0 million compression project. In addition, the first of several potential horizontal laterals from existing Hanlan Unit wells has been drilled and is awaiting final production testing. The Hanlan 6- 23 well has been deviated laterally almost 1,000 feet in an attempt to increase its productivity and mitigate natural field decline. These projects along with an active exploration and development drilling program in the area, are designed, in part, to mitigate natural production declines and keep the plant operating at high utilization rates.
A wholly-owned subsidiary of the Company, Fidelity Gas Systems, Inc. ("FGS"), owns and operates the Anasazi Gas Gathering System, which gathers gas produced from the Company-operated lease in the Paradox Basin area of southwest Colorado. The Company as operator, along with the other working interest owners, has entered into contracts with FGS pursuant to which FGS purchases all of the gas produced from the area. This gas is then resold by FGS to a purchaser at a redelivery point on the national transmission pipeline system. Proceeds payable by FGS are based upon FGS's resale price less a contractually agreed-upon fee. Amounts received by the Company from FGS 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 is considered nonjurisdictional with respect to existing FERC rules and regulations.
As previously discussed as part of the asset rationalization program, FGS sold its Southwest Oklahoma City Field gas gathering system in March 1996.
In addition to the gas gathering systems, for several years FGS owned a 10% interest in a crude oil pipeline. FGS purchased the remaining 90% of this pipeline in September 1995 and sold the entire pipeline to a third party in February 1996.
OTHER FACILITIES
The Company leases approximately 31,600 square feet in Houston, Texas for its executive and divisional offices. Additionally, the Company leases approximately 18,500 square feet in Oklahoma City, Oklahoma and approximately 2,900 square feet in Calgary, Alberta for divisional offices.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
Current and prospective stockholders should carefully consider the following risk factors in evaluating an investment in PetroCorp. The information discussed herein includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included herein regarding planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled after the date hereof, the Company's financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties, and the Company can give no assurance that such expectations will prove to have been correct. The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth in the following risk factors.
All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors.
VOLATILE NATURE OF OIL AND GAS MARKETS; FLUCTUATIONS IN PRICES
The Company's future financial condition and results of operations are highly dependent on the demand and prices received for oil and gas production and on the costs of acquiring, developing and producing reserves. Oil and gas prices have historically been volatile and are expected by the Company to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the Company's control. These factors include political conditions in the Middle East and elsewhere, domestic and foreign supply of oil and gas, the level of consumer demand, weather conditions, domestic and foreign government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. A decline in oil or gas prices may adversely affect the Company's cash flow, liquidity and profitability. Lower oil or gas prices also may reduce the amount of the Company's oil and gas that can be produced economically.
DEPENDENCE ON ACQUIRING AND FINDING ADDITIONAL RESERVES
The Company's prospects for future growth and profitability will depend predominately on its ability to replace present reserves through acquisitions and development and exploratory drilling, as well as on its ability to successfully develop additional reserves. There can be no assurance that the Company's acquisition and exploration activities or planned development projects will result in significant additional reserves or that the Company will have continuing success at drilling economically productive wells.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company has made, and likely will continue to make, substantial capital expenditures in connection with the acquisition, exploration and development of oil and gas properties. Future cash flows and the availability of credit are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas and the Company's success in locating and producing new reserves. If revenues were to decrease as a result of lower oil and gas prices, decreased production or otherwise, and the Company had no available credit, the Company could be limited in its ability to replace its reserves or to maintain production at current levels, resulting in a decrease in production and revenue over time. If the Company's cash flow from operations and available credit are not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements.
RELIANCE ON ESTIMATES OF RESERVES AND FUTURE NET CASH FLOWS
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the Company's control. Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flow necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies, assumptions concerning future oil and gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary significantly. Actual production, revenues and expenditures with respect to the Company's reserves likely will vary from estimates, and such variances may be material. In addition, the Company's reserves and future cash flows may be subject to revisions based upon production history, results of future development, oil and gas prices, performance of counterparties under agreements to which the Company is a party, operating and development costs and other factors.
The PV-10 values referred to herein should not be construed as the current market value of the estimated oil and gas reserves attributable to the Company's properties. In accordance with applicable requirements of the SEC, PV-10 is generally based on prices and costs as of the date of the estimate, whereas actual future prices
and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and gas, curtailments or increases in consumption by natural gas purchasers and changes in governmental regulations or taxation. The timing of actual future net cash flows from proved reserves, and thus their actual present value, will be affected by the timing of both the production and the incurrence of expenses in connection with development and production of oil and gas properties. In addition, the 10% discount factor (which is required by the SEC to be used to calculate PV-10 for reporting purposes), is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company and its properties or the oil and gas industry in general.
EXPLORATION RISKS
Exploratory drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered, and there can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and gas may involve unprofitable efforts, not only from non- productive wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services.
MARKETING RISKS
The Company's ability to market its oil and gas production at commercially acceptable prices is dependent on, among other factors, the availability and capacity of gathering systems and pipelines, federal and state regulation of production and transportation, general economic conditions, and changes in supply and in demand.
ACQUISITION RISKS
Acquisitions of oil and gas businesses and properties and volumetric production payments have been an important element of the Company's success, and the Company will continue to seek acquisitions in the future. Even though the Company performs a review (including a limited review of title and other records) of the major properties it seeks to acquire that it believes is consistent with industry practices, such reviews are inherently incomplete and it is generally not feasible for the Company to review in-depth every property and all records. Even an in-depth review may not reveal existing or potential problems or permit the Company to become familiar enough with the properties to assess fully their deficiencies and capabilities, and the Company often assumes environmental and other liabilities in connection with acquired businesses and properties.
OPERATING RISKS
The Company's operations are subject to numerous risks inherent in the oil and gas industry, including the risks of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company's operations may be materially curtailed, delayed or canceled as a result of numerous factors, including the presence of unanticipated pressure or irregularities in formations, accidents, title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. In accordance with customary industry practice, the Company maintains insurance against some, but not all, of the risks described above. There can be no assurance that the levels of insurance maintained by the Company will be adequate to cover any losses or liabilities.
COMPETITIVE INDUSTRY
The oil and gas industry is highly competitive. The Company competes for corporate and property acquisitions and the exploration, development, production, transportation and marketing of oil and gas, as well as contracting for equipment and securing personnel, with major oil and gas companies, other independent oil and gas concerns and individual producers and operators. Many of these competitors have financial and other resources which substantially exceed those available to the Company.
GOVERNMENT REGULATION
The Company's business is subject to certain federal, state and local laws and regulations relating to the drilling for and production, transportation and marketing of oil and gas, as well as environmental and safety matters. Such laws and regulations have generally become more stringent in recent years, often imposing greater liability on an increasing number of parties. Because the requirements imposed by such laws and regulations are frequently changed, the Company is unable to predict the effect or cost of compliance with such requirements or their effects on oil and gas use or prices. In addition, legislative proposals are frequently introduced in Congress and state legislatures which, if enacted, might significantly affect the oil and gas industry. In view of the many uncertainties which exist with respect to any legislative proposals, the effect on the Company of any legislation which might be enacted cannot be predicted.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Company is a party to various lawsuits and governmental proceedings, all arising in the ordinary course of business. Although the outcome of these lawsuits cannot be predicted with certainty, the Company does not expect such matters to have a material adverse effect, either singly or in the aggregate, on the financial position of the Company.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company's Common Stock has been listed on The Nasdaq Stock Market since October 28, 1993 and trades under the symbol PETR. The following table presents the high and low closing prices for the Company's Common Stock for each quarter during 1995 and 1996, and for a portion of the Company's current quarter, as reported by The Nasdaq Stock Market.
As of March 17, 1997, the closing price for the Company's Common Stock was $9.00 per share. As of March 17, 1997, there were approximately 780 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.
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. The Company's results of operations for each year in the five-year period ended December 31, 1996 are not comparable due to the acquisition of properties from Park Avenue Exploration Company in October 1992.
- -------- (1) Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes." (2) Prior to October 1, 1992, the Company was exempt from U.S. federal and certain state income taxes as a result of its partnership status. The pro forma data reflects the income tax benefit that would have been recorded had the Company not been exempt from such income taxes.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
GENERAL
The Company's principal line of business is the production and sale of its oil and natural gas reserves located in North America. Results of operations are dependent upon the quantity of production and the price obtained for such production. Prices received by the Company for the sale of its oil and natural gas have fluctuated significantly from period to period. Such fluctuations affect the Company's ability to maintain or increase its production from existing oil and gas properties and to explore, develop or acquire new properties.
The following table reflects certain operating data for the periods presented:
RESULTS OF OPERATIONS
1996 Compared to 1995
Overview. The Company recorded $7.6 million in income from operations in 1996 compared to a loss from operations of $7.5 million in 1995. Excluding an $8.5 million oil and gas property valuation adjustment recorded in 1995, the improvement between periods is primarily the result of increases of 44% and 12%, respectively, in the Company's weighted average natural gas and oil prices coupled with a 9% decrease in operating expenses. During 1996, the Company recorded net income of $4.2 million, or $0.49 per share, which included $629,000, or $0.07 per share, related to the after-tax gain on the sale of the gas gathering system in Oklahoma. In 1995, the Company recorded a net loss of $9.5 million, or $1.10 per share.
Revenues. Total revenues increased 15% to $31.5 million in 1996 from $27.4 million in 1995. Oil production increased slightly to 667 Mbbls from 658 Mbbls. Natural gas production decreased 10% to 8,337 MMcf in 1996 from 9,283 MMcf in 1995, resulting in an overall production decrease of 7% to 2,057 MBOE from 2,205 MBOE. The decrease in natural gas production is primarily the result of U.S. and Canadian property sales and normal production declines in the Company's U.S. properties. The Company's average U.S. natural gas price increased 46% to $2.36 per Mcf in 1996 from $1.62 per Mcf in 1995 while the average Canadian natural gas price increased 49% to $1.34 from $0.90. The Company's average oil price increased 12% to $19.91 per barrel in 1996 from $17.80 per barrel in 1995. As a result of hedging transactions, the Company's 1996 average oil price was reduced by $1.15 per barrel from the average price that would have otherwise been received while the 1995 average price was increased by $0.49 per barrel. As a result of the increases in natural gas and oil prices, partially offset by a decrease in production, oil and gas revenues increased 22% to $29.7 million in 1996 from $24.4 million in 1995. Plant processing revenues declined to $1.7 million from $1.9 million primarily as a result of the Company's sale of a portion of its interest in the Canadian Hanlan-Robb gas processing plant in May 1996. Other revenues declined 84% to $170,000 in 1996 from $1.9 million in 1995 due to reduced gas gathering fees resulting from the March 1996 sale of the Company's Oklahoma gas gathering system, and lower average sulfur prices of $7.40 per long-ton compared to $31.97 per long-ton.
Production Costs. Production costs declined 9% to $6.7 million in 1996 compared to $7.3 million in 1995, while production costs per BOE decreased 2% to $3.24 per BOE from $3.31 per BOE. The decrease in production costs in absolute dollars and on a BOE basis resulted from the Company's continued focus on reducing costs.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 7% to $12.4 million in 1996 from $13.3 million in 1995, primarily as a result of the decrease in production volumes. On a BOE basis, the oil and gas DD&A rate increased slightly to $5.24 per BOE from $5.22 per BOE.
Oil and Gas Property Valuation Adjustment. At June 30, 1995, primarily as a result of the impairment of the Company's valuation of its unproved fee mineral interests and a decline in oil and gas prices, the Company recorded an $8.5 million valuation adjustment to its oil and gas property balance in accordance with the full cost method of accounting.
General and Administrative Expenses. General and administrative expenses decreased 16% to $4.7 million in 1996 from $5.5 million in 1995 primarily due to a reduction in personnel associated with the Company's asset rationalization efforts.
Investment and Other Income. Investment and other income increased 30% to $1.9 million in 1996 from $1.5 million in 1995. In 1996, the Company included a $1.0 million gain on the sale of its Oklahoma gas gathering system in investment and other income. In 1995, the Company included in investment and other income a $1.6 million settlement of a long standing gas contract claim against Columbia Gas System and a $1.0 million loss related to the Company's natural gas hedging activities. The hedging loss was recorded in the fourth
quarter of 1995 when certain New York Mercantile Exchange (NYMEX) natural gas futures contracts no longer qualified for hedge accounting as a result of the decoupling of the relationship between the pricing of natural gas futures contracts for the first quarter of 1996 and the Company's field prices for the same period. Absent these special items, investment and other income would have increased 10% to $910,000 in 1996 from $826,000 in 1995 primarily as a result of increased funds available for investment.
Interest Expense. Interest expense decreased 13% to $3.4 million in 1996 from $3.9 million in 1995, due to reductions in outstanding debt.
Income Taxes. The Company recorded a $1.8 million income tax provision on pre-tax income of $6.1 million in 1996 compared to an income tax benefit of $608,000 on a pre-tax loss of $1.6 million in 1995 (excluding the effect of the oil and gas property valuation adjustment of $8.5 million which is calculated on an after-tax basis and has no effect on the income tax benefit).
1995 Compared to 1994
Overview. The Company's oil production and weighted average price increased 17% and 11%, respectively, while the Company's natural gas production and weighted average price declined 6% and 16%, respectively, resulting in a 3% decrease in oil and gas revenues for 1995. The Company recorded an $8.5 million oil and gas property valuation adjustment in the second quarter of 1995, primarily as a result of the impairment of the Company's valuation of its unproved fee mineral interests and a decline in oil and gas prices. Absent the oil and gas property valuation adjustment, income from operations for 1995 was $1.0 million compared to $2.8 million income from operations in 1994. Total revenues decreased 2% to $27.4 million from $28.0 million, while operating expenses, excluding the oil and gas property valuation adjustment, increased 5% to $26.4 million from $25.1 million. The Company's net loss of $9.5 million, or $1.10 per share, for 1995 compares to net income of $119,000, or $0.01 per share, for 1994.
Revenues. Total revenues decreased 2% to $27.4 million in 1995 from $28.0 million in 1994. Oil production increased 17% to 658 Mbbls in 1995 from 564 Mbbls in 1994. However, natural gas production decreased 6% to 9,283 MMcf from 9,846 MMcf, resulting in production volumes remaining level at 2,205 MBOE between years. The increase in oil production primarily reflects the positive response to waterflooding operations in the Oklahoma Misener Trend and new production from two wells in the Maynor Creek Field located in the Mississippi Salt Basin. Natural gas production in the U.S. decreased primarily as a result of normal production declines, while Canadian production decreased due to normal production declines and a significant well in the Hanlan-Robb Area of western Alberta, Canada being shut-in indefinitely due to its high sulfur content. The Company's average U.S. oil price increased 11% to $17.80 per barrel for 1995 from $15.98 per barrel for 1994 . As a result of hedging transactions, the Company's 1995 average oil price was increased by $0.49 per barrel from the average price that would have otherwise been received. The Company's average U.S. natural gas price declined 11% to $1.62 per Mcf from $1.83 per Mcf while the average Canadian natural gas price decreased 31% to $0.90 per Mcf from $1.30 per Mcf. Though oil prices and volumes were up, the decrease in natural gas prices and volumes resulted in a 3% decrease in oil and gas revenues to $24.4 million in 1995 from $25.2 million in 1994. Plant processing revenues remained level at $1.9 million while other revenues were up 12% to $1.0 million from $923,000 primarily due to increased sulfur prices ($31.97 per long-ton in 1995 compared to $16.92 per long-ton in 1994).
Production Costs. Production costs increased 1% to $7.3 million in 1995 compared to $7.2 million in 1994, while production costs per BOE increased 2% to $3.31 per BOE from $3.25 per BOE.
Depreciation, Depletion & Amortization (DD&A). Total DD&A increased 4% to $13.3 million in 1995 from $12.8 million in 1994, primarily as a result of an increase in other property, plant and equipment depreciation coupled with a small increase in the oil and gas DD&A rate. On a BOE basis, the oil and gas DD&A rate increased 1% to $5.22 per BOE from $5.15 per BOE.
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 June 30, 1995, primarily as a result of the impairment of the Company's valuation of its unproved fee mineral interests and a decline in oil and gas prices, the Company's net capitalized costs for its U.S. oil and gas properties exceeded the ceiling by $8.5 million, resulting in the corresponding valuation adjustment. The ceiling was calculated using $16.00 per barrel of oil and $1.52 per Mcf of natural gas, the prices in effect as of June 30, 1995.
General and Administrative Expenses. Though general and administrative expenses increased 8% to $5.5 million in 1995 from $5.1 million in 1994, gross general and administrative expenses, before deducting capitalized amounts and cost reimbursements, decreased by 2%. The 8% increase in the reported general and administrative expenses reflects the impact of a reduction in the amount being capitalized as oil and gas property costs during 1995 as compared to 1994. Additionally, the Company received lower cost reimbursements during 1995, primarily as a result of the close out of the management of the limited partnerships in which the Company served as general partner through June 1994, at which time the limited partnerships were liquidated.
Investment and Other Income. Investment and other income increased 7% to $1.5 million in 1995 compared to $1.4 million in 1994. In 1995, the Company included in investment and other income a $1.6 million settlement of a long standing gas contract claim against Columbia Gas System and a $1.0 million loss related to the Company's natural gas hedging activities. The hedging loss was recorded in the fourth quarter of 1995 when certain NYMEX natural gas futures contracts no longer qualified for hedge accounting as a result of the decoupling of the relationship between the pricing of natural gas futures contracts for the first quarter of 1996 and the Company's field prices for the same period. Absent these two events, investment and other income would have decreased 36% to $900,000 primarily as a result of reduced funds available for investment during 1995 as compared to 1994.
Interest Expense. Interest expense increased 22% to $3.9 million in 1995 from $3.2 million in 1994, primarily as a result of the nonrecourse notes payable being outstanding for a full year in 1995. On August 9, 1994, the Company's Canadian subsidiary issued $7.0 million in nonrecourse long-term notes payable to replace its redeemable preferred stock which was redeemed on that date. That portion of interest expense related to the Company's nonrecourse notes payable was $1.0 million in 1995 compared to $397,000 in 1994.
Preferred Dividends of Subsidiary. As discussed above, on August 9, 1994, the Company's Canadian subsidiary redeemed its preferred stock and issued nonrecourse long-term notes payable. Accordingly, no preferred dividends were declared for 1995 compared to $648,000 charged to expense in 1994.
Income Taxes. The Company recorded a $608,000 income tax benefit on a pre- tax loss of $1.6 million (excluding the effect of the oil and gas property valuation adjustment of $8.5 million which is calculated on an after-tax basis and has no effect on the income tax benefit) in 1995 compared to an income tax provision of $114,000 on pre-tax net income of $233,000 in 1994.
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, 1996, the Company had working capital of $1.9 million as compared to $6.3 million at December 31, 1995. The decrease in working capital was primarily due to capital expenditures and reductions in long-term debt exceeding net cash provided by operating activities and proceeds from asset sales. Net cash provided by operating activities
was $18.4 million, $10.5 million and $9.3 million for 1996, 1995 and 1994, respectively, while net cash provided by operating activities before changes in operating assets and liabilities for the same periods was $17.5 million, $11.7 million and $12.4 million, respectively.
The Company's total capital expenditures, including capitalized internal costs, for 1996, 1995 and 1994 were $29.5 million, $16.6 million and $29.5 million, respectively. Capital expenditures in 1996 included $8.7 million in exploration and development drilling expenditures, $2.7 million in lease acquisitions, geological and geophysical costs and $17.3 million in producing property acquisitions. The largest of the Company's acquisitions in 1996 was the $11.8 million purchase 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). Capital expenditures in 1995 included $10.2 million in exploration and development drilling expenditures, $5.1 million in lease acquisitions, geological and geophysical costs and $138,000 in producing property acquisitions. Capital expenditures in 1994 included $14.4 million in exploration and development drilling expenditures, $7.3 million in lease acquisitions, geological and geophysical costs and $5.3 million in producing property acquisitions.
In 1996, the Company completed its three-year program of rationalizing its asset base by selling its Oklahoma gas gathering system and its interest in 438 wells in various locations. The wells sold represented 53% of the Company's total well count but less than 2% of proved reserves. In addition, the Company sold a portion of its reserves in the Hanlan Swan Hills Unit along with a portion of its interest in the related Hanlan-Robb gas processing plant in Alberta, Canada. Proceeds from oil and gas property sales in 1996, 1995 and 1994 were $6.3 million, $4.4 million (primarily non-performing fee mineral interests) and $4.1 million, respectively. The Company received $3.8 million from the sale of the Oklahoma gas gathering system (see discussion below) and $1.2 million from the partial sale of its interest in the Hanlan-Robb gas processing plant.
In March 1996, the Company's wholly-owned subsidiary, Fidelity Gas Systems, Inc., sold its Southwest 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 Southwest Oklahoma City Field. Through December 31, 1996, $694,000 has been recognized, leaving a balance of $1.4 million in "deferred revenue" on the consolidated balance sheet as of December 31, 1996.
In July 1993, PetroCorp refinanced its long-term debt through the issuance of $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, 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 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, 1996, the remaining principal balances for the Series A and B Notes were $4.6 million and $26.2 million, respectively, for a total of $30.9 million of which $5.0 million was classified as current.
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.
On December 30, 1996, the Company, through a wholly-owned Canadian subsidiary, entered into a long-term borrowing arrangement with the Royal Bank of Canada (RBC) whereby the Company borrowed $3.6 million to partially fund the Millarville Acquisition. The arrangement allows the Company forego principal payments during the first year. Additionally, the Company may elect to pay interest only (Interest Only Period)
in subsequent years if the Company's Canadian subsidiary meets certain borrowing base tests. Otherwise, the loan becomes payable over a three-year period as follows: $1,575,000 in the first year, $1,200,000 in the second year and $873,000 in the third year (the Term Period). The borrowings may be funded by RBC Prime loans or Bankers' Acceptances (BA) loans. During the Interest Only Period, the Company pays interest at the RBC prime rate plus 1/2% on Prime loans and pays the BA rate plus 1/2% and an acceptance fee on BA loans. During the Term Period, the Company pays interest at the RBC prime rate plus 3/4% on Prime loans and pays the BA rate plus 3/4% and an acceptance fee on BA loans. The Company initially funded the debt with a Prime loan but rolled-over the debt into a twelve-month BA loan on January 9, 1997 with an effective interest rate of 5.8%.
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, 1996, the nonrecourse long-term notes payable balance was $4.7 million, of which $763,000 was classified as current.
Product prices continue to be volatile. Since December 31, 1996, U.S. and Canadian oil and gas prices have declined significantly. Under rules promulgated by the Securities and Exchange Commission, companies that follow the full cost accounting method are required to make quarterly "ceiling test" calculations using product prices in effect at that time (see Note 1 to the Consolidated Financial Statements -- Property, Plant and Equipment). At December 31, 1996, the Company had ceiling cushions in excess of $24 million and $25 million, respectively, related to its U.S. and Canadian oil and gas properties. However, should product prices continue to decline and depending on drilling results, the Company could potentially be required to record a valuation adjustment to its oil and gas property balances, resulting in a charge against earnings.
From time to time, the Company has utilized hedging transactions to manage its exposure to price fluctuations on its sales of oil and natural gas. Realized gains and losses from the Company's hedging activities are included in oil and gas revenues in the period of the hedged production. Normally, any realized and unrealized gains and losses prior to the period when the hedged production occurs are deferred. To date, the Company has used oil and natural gas futures contracts or natural gas option contracts traded on the NYMEX to hedge its oil and gas sales. The Company had no open hedging positions as of December 31, 1996.
In connection with its oil and gas hedging program, the Company may be exposed to the risk of financial loss in certain circumstances including instances where production is less than expected, the Company's customers fail to purchase or take delivery of the contracted sales quantities, or a sudden, unexpected event materially impacts product prices, as occurred at year-end 1995. The Company has attempted to reduce these risks by limiting, at any point in time, its U.S. hedged oil and natural gas sales volumes to approximately 85% of total U.S. sales volumes and limiting its Canadian hedged natural gas sales volumes to approximately 65% of total Canadian natural gas sales volumes.
The Company's Board of Directors has approved a capital budget of $26.0 million for 1997. The approved 1997 capital budget includes $16.0 million for exploration and development projects and $10.0 million for producing property acquisitions. However, actual levels of expenditures for planned exploration and development projects and producing property acquisitions may vary significantly due to many factors, including drilling results, oil and gas prices, industry conditions and acquisition opportunities, among others.
The Company plans to finance its 1997 exploration and development expenditures with its cash flow from operations while it plans to finance the its 1997 producing property acquisitions with new borrowings. If the Company increases its exploration, development and acquisition activities in the future, capital expenditures may require additional funding obtained through borrowings from commercial banks and other institutional sources, public offerings of equity or debt securities and existing and future relationships with institutional investment partners.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required by this item appears on pages 28 through 52 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, 1996 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 October 22, 1996, relating to a press release regarding the increase by Kaiser-Francis Oil Company of its ownership of the Company's Common Stock.
Report, dated December 23, 1996, relating to the Company's acquisition of the capital stock of Millarville Oil & Gas Ltd.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of PetroCorp Incorporated
In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a)(1) on page 25 present fairly, in all material respects, the financial position of PetroCorp Incorporated and its subsidiaries at December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PRICE WATERHOUSE LLP
Houston, Texas March 7, 1997
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEET (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
The accompanying notes are an integral part of this statement.
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF OPERATIONS (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
The accompanying notes are an integral part of this statement.
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (AMOUNTS IN THOUSANDS)
The accompanying notes are an integral part of this statement.
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF CASH FLOWS (AMOUNTS IN THOUSANDS)
The accompanying notes are an integral part of this statement.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1--SUMMARY OF ACCOUNTING POLICIES:
General
PetroCorp Incorporated, a Texas corporation, is engaged in the exploration, development, acquisition and the production and sale of crude oil and natural gas in North America. The terms "PetroCorp" and "Company" refer to PetroCorp Incorporated and its subsidiaries. PetroCorp operates in Canada through its wholly-owned Canadian subsidiaries as follows: PCC Energy Inc. (PCC Inc.), PCC Energy Limited and PCC Energy Corp. PetroCorp also operates a gas gathering facility in the U.S. through its wholly-owned subsidiary, Fidelity Gas Systems, Inc. (FGS).
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 consolidated financial statements and the accompanying notes. Actual results may differ from such estimates.
Property, plant and equipment
The Company follows the full cost method of accounting for oil and gas properties whereby all productive and nonproductive exploration and development costs incurred for the purpose of finding oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, together with internal costs directly attributable to property acquisition, exploration and development activities. No gains or losses are recognized upon the sale or other disposition of oil and gas properties, except in unusually significant transactions.
The costs of the Company's oil and gas properties, including estimated future development and dismantlement costs, are depreciated on a country-by- country basis using a composite unit-of-production rate. An additional valuation adjustment is made on a country-by-country basis if net capitalized costs of the Company's oil and gas properties exceed the capitalization ceiling, which is calculated on a quarterly basis as the sum of (1) the present value (10%) of future net revenues from estimated production of proved oil and gas reserves plus (2) the lower of cost or estimated fair value of the unproved properties, less (3) the related income tax effects.
Plant and related facilities, consisting principally of a gas processing plant in Alberta, Canada, are being depreciated on a straight-line basis over a remaining estimated useful life of approximately six years. Other property and equipment are depreciated by the straight-line method at rates based on the estimated useful lives of the assets ranging from five to ten years.
At December 31, 1996 and 1995, the cumulative amount of accrued site restoration and dismantlement costs approximated $140,000 and $251,000, respectively, and is included as a component of accumulated depreciation, depletion and amortization.
Revenue recognition
Revenues from the sale of petroleum produced are recognized upon the passage of title, net of royalties and net profits royalty interests.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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, 1996 and 1995, the Company has included in accrued liabilities $32,000 and $38,000 with respect to 20,000 Mcf and 21,000 Mcf, respectively, of overproduced imbalances.
In December 1994, the Company initiated a hedging program to manage its exposure to price fluctuations on its sales of oil and natural gas. Since initiating the hedging program, the Company has used oil and natural gas futures contracts or natural gas option contracts traded on the New York Mercantile Exchange (NYMEX) to hedge its oil and gas sales. The Company combines as a unit certain purchased and written natural gas options for hedging purposes. Realized gains and losses from the Company's hedging activities are included in oil and gas revenues in the period of the hedged production. Normally, any realized and unrealized gains and losses prior to the period when the hedged production occurs are deferred (see Note 11).
Revenues from plant processing are recognized at the time associated natural gas is processed and sold at the plant tailgate. Other revenues include revenues associated with the field gathering of third-party natural gas from certain properties in which the Company has an interest and revenues from the sale of sulfur in Canada.
Accounts receivable
Accounts receivable relate primarily to sales of oil and gas and amounts due from joint interest partners for expenditures made by the Company on behalf of such partners. The Company reviews the financial condition of potential purchasers and partners prior to signing sales or joint interest agreements. At December 31, 1996 and 1995, 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 follows the asset and liability approach to accounting for income taxes. Deferred tax assets and liabilities are determined using the tax rate for the period in which those amounts are expected to be received or paid, based on a scheduling of temporary differences between the tax bases of assets and liabilities and their reported amounts. Under this method of accounting for income taxes, any future changes in income tax rates will affect deferred income tax balances and financial results.
Foreign currency translation
The "functional currency" for translating the Company's Canadian accounts is the Canadian dollar. Assets and liabilities are translated into the reporting currency at the rate of exchange in effect at the balance sheet date while revenues, expenses, gains and losses are translated at the average exchange rate for the period. The resulting translation adjustments are accumulated in the foreign currency translation adjustment component of shareholders' equity. Foreign currency transaction gains and losses are recognized currently. For the years ended December 31, 1996, 1995 and 1994, the Company recognized foreign currency gains (losses) of $(24,000), ($13,000) and $188,000, respectively. At December 31, 1996, 1995 and 1994, the exchange rates were ($1 CAN = $U.S.) $0.7297, $0.7329 and $0.7129, respectively, while the average exchange rates during such years were $0.7334, $0.7312 and $0.7297, respectively.
Earnings per common share
Earnings per common share is computed using the weighted average number of common and common equivalent shares outstanding during the periods presented. Common equivalent shares consist of the Company's common stock issuable upon exercise of stock options.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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, 1996, 1995 and 1994 were $7,407,000, $13,623,000 and $2,648,000, respectively.
Short-term investment
During 1994, the Company invested $15,000,000 in a mutual fund which invested in high-quality adjustable rate mortgage securities issued or guaranteed by the U.S. government or its agencies. This investment was classified as an "available-for-sale security" as provided by SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." During 1994, the Company realized $616,000 in dividend income from this investment. However, partially offsetting the dividend income was a $192,000 loss resulting from the sale of a portion of this investment for $8,000,000. At December 31, 1994, the remaining short-term investment had a market value and carrying value of $6,645,000, net of a $163,000 unrealized holding loss. During 1995, the Company sold the remaining portion of this investment for $6,682,000. A $126,000 loss on the sale was more than offset by $137,000 in dividend income earned on this investment prior to the sale.
NOTE 2--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 Millarville Acquisition as if such transaction had occurred at the beginning of 1996 and 1995. The historical results of the Company's operations have been adjusted to reflect (i) Millarville's revenues and operating expenses, (ii) increases in depletion, depreciation and amortization directly attributable to the Millarville Acquisition, (iii) minor increases in administrative costs directly attributable to the Millarville Acquisition, (iv) the increase in interest expense related to the bank debt incurred as a result of the Millarville Acquisition, and (v) the increase in income taxes resulting from future income directly attributable to the Millarville Acquisition. The pro forma amounts do not purport to be indicative of the results of operations that would have been reported had the acquisition 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)
NOTE 3--PROPERTY, PLANT AND EQUIPMENT:
Investments in property, plant and equipment were as follows at December 31, 1996 and 1995 (amounts in thousands):
Depreciation, depletion and amortization for all property, plant and equipment for the years ended December 31, 1996, 1995 and 1994 was $12,279,000, $13,145,000 and $12,663,000, respectively. Oil and gas property depreciation, depletion and amortization for the years ended December 31, 1996, 1995 and 1994 was $10,788,000, $11,510,000 and $11,353,000, respectively. Depreciation, depletion and amortization per equivalent barrel (using a Mcf-to-barrel conversion factor of 6 to 1) for the years ended December 31, 1996, 1995 and 1994 was $6.38, $6.21 and $6.23, respectively, for United States operations and $2.03, $2.13 and $2.10, respectively, for Canadian operations. The total composite rates were $5.24, $5.22 and $5.15 for the years ended December 31, 1996, 1995 and 1994, respectively. At June 30, 1995, the Company's net capitalized costs of its United States oil and gas properties exceeded the capitalization ceiling by $8,500,000. This amount is reflected in the Company's results of operations for the year ended December 31, 1995.
NOTE 4--LONG-TERM DEBT:
The Company's total long-term debt is payable as follows (amounts in thousands):
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Series A and Series B Senior Notes
Series A and Series B Senior Notes at December 31, 1996 and 1995 consisted of (amounts in thousands):
Redemption payments to affiliates and nonaffiliates were $4,142,000 and $808,000 in 1996 and $2,967,000 and $433,000 in 1995, respectively.
Interest paid to affiliates and nonaffiliates for the years ended December 31, 1996, 1995 and 1994 amounted to $1,883,000 and $706,000, $2,150,000 and $755,000 and $2,010,000 and $755,000, respectively.
On July 29, 1993, the Company entered into the Note Purchase Agreement with subsidiaries of CIGNA Corporation and USF&G Corporation together with certain other insurance companies, to refinance existing notes totaling $36,976,000 with $40,000,000 in proceeds received under the Note Purchase Agreement. At that time, subsidiaries of CIGNA Corporation and USF&G Corporation were shareholder affiliates of the Company. However, 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 6.68% to 7.09%, 6.71% to 7.40% and 4.40% to 6.71% during 1996, 1995 and 1994, respectively. Interest on the Series B notes is fixed at a rate of 7.55% and is payable semiannually in arrears.
The Note Purchase Agreement prohibited the declaration or payment of any cash dividends related to the Company's common stock prior to July 1, 1995. In addition, other provisions of the Note Purchase Agreement impose upon the Company certain financial covenants that have the effect of restricting the amount of dividends on common stock that may be paid by the Company after June 30, 1995. These restrictions include a covenant under which the aggregate amount of such dividends after June 30, 1995 may not exceed the sum of (i) $5 million plus (ii) 50% of consolidated net income (as defined) for the period January 1, 1993 through the end of the then most recently completed fiscal quarter (or less 100% of consolidated net income for such period if such amount is a loss) plus (iii) the amount of the Company's net cash proceeds from issuance subsequent to December 31, 1992 of shares of common stock or options, rights or warrants to purchase common stock. Certain other restrictive covenants could, depending upon future events and circumstances, further reduce the amount of any dividends on common stock permitted to be paid by the Company.
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.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Bank Debt
On December 30, 1996, the Company, through a wholly-owned Canadian subsidiary, entered into a long-term borrowing arrangement with the Royal Bank of Canada (RBC) whereby the Company borrowed $3,648,000 to partially fund the Millarville Acquisition. The arrangement allows the Company to forgo principal payments in the first year. Additionally, the Company may elect to pay interest only (Interest Only Period) in subsequent years if the Company's Canadian subsidiary meets certain borrowing base tests. Otherwise, the loan becomes payable over a three-year period as follows: $1,575,000 in the first year, $1,200,000 in the second year and $873,000 in the third year (the Term Period). The borrowings may be funded by RBC Prime loans or Banker's Acceptances (BA) loans. During the Interest Only Period, the Company pays interest at the RBC prime rate plus 1/2% on Prime loans and pays the BA rate plus 1/2% and an acceptance fee on BA loans. During the Term Period, the Company pays interest at the RBC prime rate plus 3/4% on Prime loans and pays the BA rate plus 3/4% and an acceptance fee on BA loans. The Company initially funded the debt with a Prime loan but rolled-over the debt into a twelve-month BA loan on January 9, 1997 with an effective interest rate of 5.8%.
Nonrecourse Notes Payable
On August 9, 1994, the Company's Canadian subsidiary, 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 (Note 6). Consistent with the redeemable preferred stock, the Nonrecourse Notes Payable are denominated in Canadian dollars.
During 1996 and 1995, interest payments were $896,000 and $1,010,000, respectively, while principal payments totaled $1,938,000 and $857,000, respectively. Additionally, in 1996 and 1995, the Company issued $261,000 and $665,000 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.
NOTE 5--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. Through December 31, 1996, $694,000 has been recognized, leaving a balance of $1,395,000 in "deferred revenue" on the consolidated balance sheet as of December 31, 1996.
NOTE 6--PREFERRED STOCK:
The Company is authorized to issue up to 1,000,000 shares of preferred stock, par value $0.01 per share. However, no preferred shares have been issued. The Company's Board of Directors is authorized to divide the preferred stock into series and, with respect to each series, to determine the dividend rights, dividend rate,
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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.
Redeemable preferred stock of subsidiary
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 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.
Prior to August 9, 1994, PCC Inc. had authorized 50,000,000 shares of First Preferred Shares Series A, par value $1.00 (CAN) per share, which were mandatorily redeemable and were generally nonvoting (the Redeemable Preferred Stock). The Company had a call on the Redeemable Preferred Stock held by the preferred shareholders entitling the Company at any time to convert the Redeemable Preferred Stock for an amount equal to the redemption price, plus any dividends and redemptions in arrears, to long-term debt with an interest rate of 15% per annum. On August 9, 1994, PCC Inc. redeemed the remaining balance of the preferred stock and issued $7,034,000 in nonrecourse long-term notes payable to the previous holders of the preferred stock with financial terms similar to the Redeemable Preferred Stock (Note 4). The number of shares of Redeemable Preferred Stock redeemed for the year ended December 31, 1994 approximated $10,209,000.
During 1994, preferred dividend cash payments were $928,000 while 10,209,000 preferred shares were redeemed for $7,437,000 and 27,000 new preferred shares were issued for $20,000.
Dividends were accrued and paid on a quarterly basis at a rate of 15% per annum. In addition, redemptions were required to be made quarterly, based on a fixed schedule through December 31, 2002. Dividend and redemption payments were made only to the extent that there were 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 Redeemable Preferred Stock. To the extent dividends and redemptions exceeded such cash proceeds, the excess amount was carried forward to the next quarter.
NOTE 7--INCOME TAXES:
Effective January 1, 1993, the Company adopted the provisions of SFAS 109, which requires the use of the "liability" method under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.
The components of income (loss) before income taxes for the years ended December 31, 1996, 1995 and 1994 consisted of the following (amounts in thousands):
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The provision (benefit) for income taxes consists of the following (amounts in thousands):
During the year ended December 31, 1994, the Company paid Canadian preferred dividend taxes of $617,000. Canadian income tax rules allow the Company to include 225% of the amount of preferred dividend taxes paid with the Company's Canadian net operating loss carryforwards. Effectively, this will allow the Company to reduce (dollar-for-dollar) future income tax payments by the amount of the preferred dividend taxes previously paid.
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, 1996, 1995 and 1994 is presented in the following table (amounts in thousands):
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Deferred tax assets and liabilities consist of the following at December 31, 1996 and 1995 (amounts in thousands):
As of December 31, 1996, the Company has U.S. net operating loss carryforwards of $24,055,000 and $17,756,000 for regular tax and alternative minimum tax purposes, respectively, which begin to expire in 2000. The Company is subject to certain restrictions under Section 382 on the annual utilization of a portion of its net operating loss carryforwards. Certain future changes in the Company's shareholders may impose additional limitations as well.
In 1996, under SFAS 109, the Company was required to increase deferred income taxes and oil and gas properties by $2,890,000 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):
NOTE 8--STOCK OPTION AND OTHER EMPLOYEE BENEFIT PLANS:
In 1992, the Company established the 1992 PetroCorp Stock Option Plan (the Option Plan). The Option Plan allows up to 957,357 option shares to be granted and outstanding of which 890,740 option shares were granted and outstanding as of December 31, 1996.
The Company has issued option shares as follows: (1) 225,000 were granted in October 1992 in exchange for rights which existed under the 1989 PetroCorp Equity Interest Plan (the 1989 Plan) which was terminated and replaced by the Option Plan; these option shares have an exercise price of $5.00, which was equal to the value of the rights under the 1989 Plan; (2) 407,740 were granted in October 1992 and 105,000 were granted in
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
August 1993 with an exercise price of $10.00 and (3) 220,000 were granted in February 1996 with an exercise price of $6.38. The exercise price for all options equaled fair value at the date of grant. Of the option shares previously granted with a $10.00 exercise price, 67,000 shares have been forfeited as of December 31, 1996. The weighted-average exercise prices for options outstanding at January 1, 1996, outstanding at December 31, 1996, exercisable at December 31, 1996 and forfeited during 1996 were $8.43, $7.84, $7.84 and $10.00, respectively.
In October 1996, all granted stock options 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 had purchased the common shares owned by investment funds managed by First Reserve Corporation and the common shares owned by a subsidiary of CIGNA Corporation. All stock options expire ten years from the date of grant.
The Company applies Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for the Option Plan. Accordingly, no compensation expense has been recognized for this stock-based compensation plan. Had compensation cost for the Option Plan been determined based upon the fair value at the grant date for awards under such plan consistent with the methodology prescribed under SFAS No. 123, Accounting for Stock-Based Compensation, the Company's 1996 net income and earnings per share would have been reduced by approximately $450,000 or $0.05 per share. The fair value of the options granted during 1996 is estimated as $720,000 on the date of grant using the Black-Scholes option-pricing model with the following assumptions: dividend yield 0%, volatility of 34.3%, risk-free interest rate of 5.7% and an expected life of ten years.
The Company has a savings plan, which became effective January 1, 1993, available to permanent employees and is qualified as a deferred compensation plan under Section 401(k) of the Internal Revenue Code. The Company matches employee contributions for an amount up to 6% of each employee's salary. The Company's contributions to the plan, which are charged to expense, totaled $208,000, $243,000 and $242,000 in 1996, 1995 and 1994, respectively.
NOTE 9--RELATED PARTY TRANSACTIONS:
In February 1994, the Company completed the sale of approximately 300 U.S. oil and gas properties. The sale of properties, in addition to the Company's share, also included interests managed by the Company but owned by others, principally limited partnerships in which the Company or PetroCorp Management, Inc. (PMI), a wholly-owned subsidiary at that time, served as general partner. As a result, the Company made liquidating distributions to the limited partners in June 1994, allowing the Company to close out its management of the limited partnerships.
Previously, the Company served as manager of the activities for the limited partnerships in which the Company or PMI was the general partner. Additionally, the Company served as operator of various wells in which such partnerships had an interest. The Company disbursed funds to third parties on behalf of the partnerships and was reimbursed on a monthly basis. Likewise, revenues were received by the Company and disbursed to the partnerships and to the other well participants, including royalty owners. During 1994, the Company received $97,000 from affiliated partnerships, representing reimbursement of certain costs of a general and administrative nature.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 10--GEOGRAPHIC AREA INFORMATION:
The principal business of the Company is oil and gas, which consists of the exploration, development, acquisition, exploitation and operation of oil and gas properties and the production and sale of crude oil and natural gas in North America. Pertinent information with respect to the Company's oil and gas business is presented in the following table (amounts in thousands):
The following table reflects purchasers which accounted for more than 10% of the Company's oil and gas revenues:
The majority of the Company's Canadian gas is dedicated under long-term contracts to Pan-Alberta Gas Ltd., a major Canadian aggregator. The Company does not believe the loss of any purchaser would have a material adverse effect on its financial position since the Company believes alternative sales arrangements could be made on relatively comparable terms.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 11--HEDGING PROGRAM AND FAIR VALUE OF FINANCIAL INSTRUMENTS:
Hedging Program
From time to time, the Company has utilized hedging transactions to manage its exposure to price fluctuations on its sales of oil and natural gas. Realized gains and losses from the Company's hedging activities are included in oil and gas revenues in the period of the hedged production. Normally, any realized and unrealized gains and losses prior to the period when the hedged production occurs are deferred. Since initiating the hedging program, the Company has used oil and natural gas futures contracts or natural gas option contracts traded on the NYMEX to hedge its oil and gas sales.
The Company recorded realized hedging losses of $918,000 in 1996 and hedging gains of $338,000 in 1995. The Company had no open hedging positions as of December 31, 1996. As of December 31, 1995, deferred losses related to hedged oil and natural gas sales totaled $227,000 and $148,000, respectively.
As a result of the decoupling of the relationship between the pricing of certain NYMEX natural gas futures contracts for the first quarter of 1996 and the Company's field prices for the same period, these futures contracts no longer qualified as hedges for accounting purposes. Accordingly, the Company recorded a $996,000 reduction to "investment and other income" during the fourth quarter of 1995.
In connection with its oil and gas hedging program, the Company may be exposed to the risk of financial loss in certain circumstances including instances where production is less than expected, the Company's customers fail to purchase or take delivery of the contracted sales quantities, or a sudden, unexpected event materially impacts product prices, as occurred at year-end 1995. The Company attempts to reduce these risks by limiting, at any point in time, its U.S. hedged oil and natural gas sales volumes to approximately 85% of total U.S. sales volumes and limiting its Canadian hedged natural gas sales volumes to approximately 65% of total Canadian natural gas sales volumes.
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.
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 12--COMMITMENTS AND CONTINGENCIES:
The Company has entered into operating lease agreements with noncancelable terms in excess of one year for office space. Future minimum lease payments are $605,000, $418,000, $393,000, $396,000 and $434,000 for the years ended December 31, 1997, 1998, 1999, 2000 and 2001, respectively. Total rental expense for office space for the years ended December 31, 1996, 1995 and 1994 was $646,000, $637,000 and $631,000, respectively.
There are other claims and actions pending against the Company. In the opinion of management, the amounts, if any, which may be awarded in connection with any of these claims and actions would not be material to the Company's consolidated financial position or results of operations.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA (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, 1996, 1995 and 1994 were $1,690,000, $1,962,000 and $2,552,000, respectively, of capitalized internal costs related to property acquisition, exploration and development. In 1996, under SFAS 109, the Company was required to increase deferred income taxes and oil and gas properties by $2,890,000 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.
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, 1996, approximately $2,931,000 and $1,282,000 was incurred in 1996 and 1995, respectively. The Company anticipates evaluating these properties during subsequent years.
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.
The Company's estimates of its proved reserves and proved developed reserves of oil and gas as of December 31, 1996, 1995 and 1994 and the changes in its proved reserves are as follows:
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):
The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows (amounts in thousands):
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:
SUMMARIZED QUARTERLY FINANCIAL DATA
(UNAUDITED) (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- -------- (1) Revenues less operating expenses other than general and administrative. (2) In the first quarter of 1996, the Company recorded a $629,000 after-tax gain related to the sale of its Oklahoma gas gathering system. (3) The fourth quarter of 1995 includes a $1.0 million after-tax gain related to the settlement of a gas contract claim against Columbia Gas System and a $630,000 after-tax loss related to natural gas hedging activity.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES 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 24, 1997
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